Items 1 and 2. Business and Properties

See pages 25 and 26 for explanations of abbreviations and terms used herein.

General

Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas and onshore in New Zealand. Swift Energy was founded in 1979 and is headquartered in Houston, Texas. At year-end 2005, we had estimated proved reserves of 761.8 Bcfe with a PV-10 Value of $3.2 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Business and Properties section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). Our proved reserves at year-end 2005 were comprised of approximately 51% crude oil, 38% natural gas, and 11% NGLs, of which 50% were proved developed. Our proved reserves are concentrated 52% in Louisiana, 31% in Texas, 16% in New Zealand, and 1% in other states.

We currently focus primarily on development and exploration of fields in three domestic regions and in New Zealand:

• South Louisiana Region
      Lake Washington Area
      Bay de Chene Area
      Cote Blanche Island Area
• South Texas Region
      AWP Olmos Area
      Garcia Ranch Area
• Toledo Bend Region
      Brookeland Area
      Masters Creek Area
      South Bearhead Creek Area
• New Zealand Region
      Rimu/Kauri Area
      TAWN Area

Competitive Strengths and Business Strategy

Our competitive strengths, together with a balanced and comprehensive business strategy, provide us with the flexibility and capability to achieve our goals. Our primary goals for the next five years are to increase proved oil and natural gas reserves at an average rate of 5% to 10% per year and to increase production at an average rate of 7% to 12% per year.

     Demonstrated Ability to Grow Reserves and Production

Although we have had slight decreases in the last two years, we have grown our proved reserves from 629.4 Bcfe to 761.8 Bcfe over the five-year period ended December 31, 2005. Over the same period, our annual production has grown from 42.4 Bcfe to 59.6 Bcfe and our annual net cash provided by operations has increased from $128.2 million to $285.3 million. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities in our four core regions combined with producing property acquisitions. More recently, we increased our production by 2% during 2005 as compared to 2004 production. During 2005, our total proved reserves decreased by 5%, primarily due to a slowdown in drilling activity in Lake Washington as a result of Hurricane Katrina. Based on our long-term historical performance and our business strategy going forward, we believe that we have the opportunities, experience, and knowledge to grow both our reserves and production.

     Balanced Approach to Growth

Our strategy is to increase our reserves and production through both drilling and acquisitions, shifting the balance between the two activities in response to market conditions and strategic opportunities. In general, we focus on drilling in our anchor assets and diversity properties in each of our four regions when oil and natural gas prices are strong. When prices weaken and the per unit cost of acquisitions becomes more attractive, or a strategic opportunity exists, we shift our focus toward acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner. Over the five-year period ended December 31, 2005, we replaced 149% of our production at an average cost of $2.44 per Mcfe. More recently, we replaced 36% of our 2005 production. For 2006, we are targeting total production to increase 14% to 18% and proved reserves to increase 5% to 8% over 2005 levels.

Our 2006 capital expenditures are currently budgeted at $300 million to $325 million, net of approximately $5 million to $10 million of non-core property dispositions. Approximately 85% of the budget is targeted for domestic activities, with about 15% planned for activities in New Zealand. We plan to spend $175 million to $195 million in our South Louisiana region, which includes Lake Washington, Bay de Chene, and Cote Blanche Island. Of this amount, approximately $40 million to $50 million will be focused on activities in Bay de Chene and Cote Blanche Island and includes approximately $11 million designated for the Cote Blanche Island 3-D seismic acquisition planned for 2006. No acquisitions are currently included in our 2006 capital budget. We expect our 2006 capital expenditures will initially be at the low end of the budgeted range, and depending on commodity prices and operational performance, they may increase to the high end of the range during the course of the year. We anticipate 2006 capital expenditures to approximate our cash flow provided from operating activities during 2006.

     Reserves Replacement Ratio and Reserves Replacement Cost

Historically we have added proved reserves through both our drilling and acquisition activities. We believe that this strategy will continue to add reserves for us over the long-term, however, external factors beyond our control, such as adverse weather conditions, commodity market factors, and governmental regulations, could limit our ability to drill wells and acquire proved properties in the future. We calculate and analyze reserves replacement ratios and costs to use as benchmarks against certain of our competitors. These ratios and costs are limited in use by the inherent uncertainties in the reserves estimation process, and other factors discussed below. We have included below a table listing the vintages of our proved undeveloped reserves in the table titled “Proved Undeveloped Reserves,” and believe this table will provide an understanding of the time horizon required to convert proved undeveloped reserves to oil and gas production. Our reserves additions for each year are estimates. Reserve volumes can change over time and, therefore cannot be absolutely known or verified until all volumes have been produced and a cumulative production total for a well or field can be calculated. Many factors will impact our ability to access these reserves, such as availability of capital, commodity prices, new and existing government regulations, competition within our industry, the requirement of new or upgraded infrastructure at the production site, and technological advances.

The reserves replacement ratio is calculated using reserves replacement volumes divided by production volumes during a specific period. The reserves replacement volumes used in this calculation are listed in the “Supplemental Information (Unaudited)” section of this report, specifically in a table titled “Supplemental Reserves Information.” Within this table there are categories titled “Revisions of previous estimates,” “Purchases of minerals in place” and “Extensions, discoveries, and other additions,” which when added, total the reserves replacement volumes. Production volumes are also listed in the same table, and these production volumes are also used in the reserves replacement ratio calculation.

The reserves replacement cost is calculated using reserves replacement volumes divided into acquisition, exploration, and development costs incurred during a specific period. Our acquisition, exploration, and development costs are listed in the “Supplemental Information (Unaudited)” section of this report, specifically in a table titled “Costs Incurred.” Development costs as defined by Securities and Exchange Commission rules, include costs incurred to obtain access to proved reserves and provide facilities for extracting, treating, gathering and storing the oil and gas. Development costs thus include well costs for our development wells and facility costs, such as those facility and platform costs we have incurred in our Lake Washington area over the past several years. Costs incurred to explore and develop reserves may extend over several years. We believe a reserves replacement cost estimate is more meaningful when calculated over several periods. Future development costs from prior years are included in this calculation to the extent that they have been included in our actual costs incurred.

     Concentrated Focus on Regions with Operational Control

The concentration of our operations in four regions allows us to realize economies of scale in drilling and production by enabling us to manage larger producing fields with less personnel while minimizing incremental costs of increased drilling and completions. Each of our four regions includes at least one anchor asset, previously termed a core area, and several diversity properties that are targeted for future growth. Our average lease operating costs, excluding taxes, were $0.79, $0.71, and $0.64 per Mcfe in 2005, 2004, and 2003, respectively. This concentration allows us to utilize the experience and knowledge we gain in these areas to continually improve our operations and guide us in developing our future activities and in operating similar type assets. For example, in our South Louisiana region, we will apply the experience we have gained in Lake Washington to our Bay de Chene and Cote Blanche Island properties acquired at the end of 2004, which are also situated around salt domes. The value of this concentration is enhanced by our operating 95% of our proved oil and natural gas reserves base as of December 31, 2005. Retaining operational control allows us to more effectively manage production, control operating costs, allocate capital, and time field development.

     Develop Under-Exploited Properties

We are focused on applying advanced technologies and recovery methods to areas with known hydrocarbon resources to optimize our exploration and exploitation of such properties as illustrated in our four regions. For instance, the Lake Washington field was discovered in the 1930s. We acquired our properties in this area for $30.5 million in 2001. Since that time, we have increased our average daily net production from less than 700 BOE to 13,100 BOE for the quarter ended December 31, 2005. We have also increased our proved reserves in the area from 7.7 million BOE, or 46.2 Bcfe, to approximately 39.8 million BOE or 238.9 Bcfe, as of December 31, 2005. Additionally, on our original 100,000 acre New Zealand permit, only two wells had been drilled at the time that we acquired our interest. We have drilled 42 wells in New Zealand since 1999. When we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas also had significant additional development potential. Our properties in the Bay de Chene and Cote Blanche Island fields hold mainly proved undeveloped reserves and we plan to begin our initial development activities of these properties in 2006. We intend to continue acquiring large acreage positions where we can grow production by applying advanced technologies and recovery methods using our experience and knowledge developed in our four regions.

     Capitalize on the Near Term Depletion of New Zealand’s Largest Gas Field

The Maui field in New Zealand currently comprises over 60% of the natural gas produced in New Zealand. Production from the Maui field is expected to decline sharply each year of its remaining life, which has caused significant upward pressure on prices for natural gas in the country. Due to currency exchange increases between the New Zealand dollar and the U.S. dollar, along with increases in our natural gas contract prices, our average natural gas price in New Zealand has increased 34% from the first quarter of 2004 to the fourth quarter of 2005. We expect the prices we receive for our natural gas in New Zealand to continue to improve. During 2006, we anticipate drilling six to eight development wells and expect to drill two to four exploration tests, which includes our Tarata Thrust exploration activity. These New Zealand activities provide us with long-term growth opportunities and significant potential reserves in a country with stable political and economic conditions, existing oil and gas infrastructure, and favorable tax and royalty regimes.

     Maintain Financial Flexibility and Disciplined Capital Structure

We practice a disciplined approach to financial management and have historically maintained a disciplined capital structure to provide us with the ability to execute our business plan. As of December 31, 2005, our debt to capitalization was approximately 37%, while our debt to proved reserves ratio was $0.46 per Mcfe, and our debt to PV-10 ratio was 11%. Including our cash on hand at year-end 2005, our net debt to capital ratio would have been 33% and our net debt per Mcfe would be $0.38 per Mcfe. We plan to maintain a capital structure that provides financial flexibility through the prudent use of capital, aligning our capital expenditures to our cash flows, and maintaining a strategic hedging program. The combination of hedging with collars, floors, forward sales, and the sale of our New Zealand natural gas production under long-term, fixed-price contracts will provide for a more stable cash flow for the periods covered as described in the “Commodity Risk” section of this report.

     Experienced Technical Team

We employ 50 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 25 years of experience in their technical fields and have been employed by us for an average of over six years. In addition, we engage experienced and qualified consultants to perform various comprehensive seismic acquisitions, processing, reprocessing, interpretation, and other related services. We continually apply our extensive in-house experience and current technologies to benefit our drilling and production operations.

We have increasingly used seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, post-stack image enhancement reprocessing, amplitude versus offset datasets, correlation cubes, and detailed formation depletion studies. In 2004, we completed our 3-D seismic survey covering our Lake Washington area and during 2005, all eight of our exploration wells in the Lake Washington area utilized the 3-D seismic data, of which five were successful, and all 24 of our development wells utilized the 3-D seismic data, of which 16 were successful. In 2005, we began a seismic program that encompasses 77 square miles in our Cote Blanche Island area, which is expected to be completed in the third quarter of 2006. In New Zealand, we also plan to acquire seismic on our offshore Kaheru exploration permit in 2006.

We use various recovery techniques, including gas lift, water flooding, and acid treatments to enhance crude oil and natural gas production. We also fracture reservoir rock through the injection of high-pressure fluid, install gravel packs, and insert coiled-tubing velocity strings to enhance and maintain production. We believe that the application of fracturing and coiled-tubing technology has resulted in significant increases in production and decreases in completion and operating costs, particularly in our AWP Olmos area.

We have developed an expertise in drilling horizontal wells at vertical depths below 10,000 feet, often in a high-pressure environment, involving single or dual lateral legs of several thousand feet. This results in an integrated approach to exploration using multidisciplinary data analysis and interpretation that has helped us identify a number of exploration prospects.