UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in Its Charter)

Texas		20-3940661
(State of Incorporation)		(I.R.S. Employer Identification No.)

16825 Northchase Dr., Suite 400
Houston, Texas 77060
(281) 874-2700
(Address and telephone number of principal executive offices)
Securities registered pursuant to Section 12(b) of the Act:

Title of Class:		Exchanges on Which Registered:
Common Stock, par value $.01 per share		New York Stock Exchange, Inc.
		Pacific Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes  þ     No  o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.  Yes  o     No  þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months, and (2) has been subject to such filing requirements for the past 90 days.  Yes  þ     No  o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).

Large accelerated filer  þ               Accelerated filer  o               Non-accelerated filer  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  o     No  þ

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of June 2005 was approximately $998,652,215.

The number of shares of common stock outstanding as of January 31, 2006 was 29,061,106.

Document		Incorporated as to
Proxy Statement for the Annual		Part II, Item 5
Meeting of Shareholders to be held May 9, 2006		Part III, Items 10, 11, 12, 13 and 14

 

 

Form 10-K
Swift Energy Company and Subsidiaries

10-K Part and Item No.						Page
Part I
		Item 1.		Business			3
		Item 1A.		Risk Factors			19
		Item 1B.		Unresolved Staff Comments			23
		Item 2.		Properties			6
		Item 3.		Legal Proceedings			26
		Item 4.		Submission of Matters to a Vote of Security Holders			26
Part II
		Item 5.		Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities (1)			26
		Item 6.		Selected Financial Data			27
		Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
		Item 7A.		Quantitative and Qualitative Disclosures About Market Risk			43
		Item 8.		Financial Statements and Supplementary Data			45
		Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			85
		Item 9A.		Controls and Procedures			85
		Item 9B.		Other Information			85
Part III
		Item 10.		Directors and Executive Officers of the Registrant (1)			86
		Item 11.		Executive Compensation (1)			86
		Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters (1)			86
		Item 13.		Certain Relationships and Related Transactions (1)			86
		Item 14		Principal Accountant Fees and Services (1)			86
Part IV
		Item 15		Exhibits and Financial Statement Schedules			87
Forms of Agreements for Grant of Incentive Stock Options
Second Amendment to First Amended Credit Agreement
Ratio of Earnings to Fixed Charges
List of Subsidiaries
Consent of H.J. Gruy and Associates, Inc.
Consent of Ernst & Young LLP
Certification of CEO Pursuant to Section 302
Certification of CEO Pursuant to Section 302
Certification of CEO & CFO Pursuant to Section 906
Summary of H.J. Gruy and Associates, Inc. Report

     (1) Incorporated by reference from Proxy Statement for the Annual Meeting of Shareholders to be held May 9, 2006.

PART I

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.

     We also employ measurement-while-drilling techniques extensively in our Lake Washington area, which allows us to guide the drill bit during the drilling process. This technology allows the well bore path to be steered parallel to the salt face and to intersect multiple targeted sands in a single well bore.

Operating Areas

     The following table sets forth information regarding our proved reserves and production by field:

						% of Year-End
						2005 Proved				% of 2005
Area		Region				Reserves				Production
AWP Olmos		South Texas					23	%			13	%
Brookeland		Toledo Bend					5	%			5	%
Lake Washington		South Louisiana					31	%			45	%
Masters Creek		Toledo Bend					7	%			4	%
Bay de Chene, Cote Blanche Island		South Louisiana					10	%			2	%
Rimu/Kauri		New Zealand					11	%			14	%
TAWN		New Zealand					5	%			14	%
% of Total							92	%			97	%

Domestic Regional Focus Areas

     Our domestic regions consist of three main regions located in South Louisiana, South Texas and Toledo Bend, which straddles the Texas and Louisiana border. South Texas is the oldest of our core regions, with our operations being established in the AWP Olmos area in 1989. During 2001, we added Garcia Ranch, an area southeast of AWP Olmos. In mid-1998, we acquired the Masters Creek and Brookeland areas in the Toledo Bend region, with South Bearhead Creek being our most recent acquisition in this region during late 2005. In South Louisiana, we established our operations when we acquired majority interests in producing properties in the Lake Washington field in early 2001, adding Bay de Chene and Cote Blanche Island in December 2004.

South Louisiana

     Lake Washington Area. As of December 31, 2005, we owned drilling and production rights in 17,352 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana, along with lease and seismic options covering another 6,400 acres. Approximately 93% of our proved reserves of 39.8 million BOE in this area at December 31, 2005 were oil and NGLs. To date, we have primarily produced from multiple Miocene sands ranging in depth from greater than 2,000 feet to 10,000 feet. The field is located on a salt dome and has produced over 300 million BOE since its discovery in the 1930s. The area around the dome is heavily faulted, thereby creating a large number of potential traps. Oil and gas from approximately 115 producing wells is gathered from three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with rigs on barges.

     In 2005, we drilled 24 development wells and eight exploratory wells, of which 16 development and five exploratory wells were completed. At year-end 2005, we had 87 proved undeveloped locations in this field. Our planned 2006 capital expenditures in this area will focus on drilling at least 26 wells; of these at least three will be exploratory wells with targets derived from recently acquired three-dimensional seismic data. Additional facility work is planned to further improve the deliverability and efficiency in this area.

     Bay de Chene and Cote Blanche Island Areas. Bay de Chene is located in Jefferson Parish and Lafourche Parish, while Cote Blanche Island is located in St. Mary Parish, both of which are in South Louisiana in close proximity to Lake Washington. These fields hold predominantly undeveloped reserves. As of December 31, 2005, we owned drilling and production rights in 14,156 net acres in the Bay de Chene field and 7,032 net acres in the Cote Blanche Island field. We plan to spend $40 million to $50 million to begin developing these fields during 2006. These fields were shut-in following the acquisition for facility enhancements and to repair a gas supply line. Beginning in late August of 2005, both fields were shut-in for Hurricanes Katrina and Rita. Bay de Chene field returned to production in the fourth quarter 2005, meanwhile, Cote Blanche Island is expected to resume production late in the first quarter of 2006. At year-end 2005, we had three proved undeveloped locations in the Bay de Chene field and 20 in the Cote Blanche Island field. We drilled our first exploratory well in Bay de Chene in late 2005, which was unsuccessful. During 2006, we plan to drill two to four wells and perform several recompletions in each area. We also have a 3-D seismic acquisition for Cote Blanche Island planned for 2006.

South Texas

     AWP Olmos Area. As of December 31, 2005, we owned drilling and production rights in 29,226 net acres in the AWP Olmos Area in South Texas. We have extensive experience with low-permeability, tight-sand formations typical of this area, having acquired our first acreage there in 1988. These reserves are approximately 67% natural gas. At year-end 2005, we owned interests in and operated 526 wells in this area producing natural gas from the Olmos sand formation at depths of approximately 9,000 to 11,500 feet. We own nearly 100% of the working interests in all our operated wells.

     In 2005, we completed 18 development wells in this area, and performed 23 fracture enhancements. At year-end 2005, we had 118 proved undeveloped locations. Our planned 2006 capital expenditures will focus on drilling 12 to 15 wells in this area.

     Garcia Ranch Area. We have been focusing on the deep sands of the Frio formation (10,000 to 16,000 feet) in an area known as Garcia Ranch, which straddles the border of Kenedy County and Willacy County in the southern tip of Texas. Two development wells were drilled in this area in 2005; both were completed.

Toledo Bend

     Brookeland Area. As of December 31, 2005, we owned drilling and production rights in 78,535 net acres and 3,500 fee mineral acres in the Brookeland area. This area is located in East Texas near the border of Louisiana in Jasper and Newton counties. We primarily drill horizontal wells and produce from the Austin Chalk formation in this area. The reserves are approximately 57% oil and natural gas liquids. During 2005, we participated in drilling one non-operated development well, which was successful. At year-end 2005, we had 11 proved undeveloped locations. Our planned 2006 capital expenditures in Toledo Bend region include drilling one to two development wells.

     Masters Creek Area. As of December 31, 2005, we owned drilling and production rights in 46,635 net acres and 91,994 fee mineral acres in the Masters Creek area. This area is located in Central Louisiana near the Texas-Louisiana border in the two parishes of Vernon and Rapides. It contains horizontal wells producing both oil and gas from the Austin Chalk formation. The reserves are approximately 68% oil and NGLs. At year-end 2005, we had eight proved undeveloped locations.

     South Bearhead Creek Area. In November and December 2005, we acquired interests in the South Bearhead Creek field, which is located in the Toledo Bend region approximately 50 miles south of our Masters Creek field and 30 miles north of Lake Charles, Louisiana. Oil and gas are produced in this area predominantly from the upper and lower Wilcox sands, at depths ranging from approximately 10,600 to 13,700 feet. The field also has production in the Cockfield sands at approximately 8,000 to 8,500 feet. South Bearhead Creek field was discovered in 1958 by a major oil company. It is a large east-west trending anticlinal closure and has had cumulative production of over 4 million BOE.

     As of December 31, 2005, we owned drilling and production rights in 5,258 net acres in the South Bearhead Creek area. At year-end 2005, we had 19 proved undeveloped locations in this field. Our 2006 plans for this area include two to four development wells and several recompletions.

New Zealand Regional Focus Area

     Our New Zealand region contains two anchor assets, the Rimu/Kauri area and the TAWN area. Our activity in New Zealand began in 1995. As of December 31, 2005, our exploration permit 38719, which we operate, included approximately 64,061 acres in the Taranaki Basin of New Zealand’s north island. In April 2004, two other permits (38756 and 38759) within the Taranaki Basin were consolidated with our permit 38719 to form one permit area. This acreage includes our Rimu/Kauri area, and our Rimu and Kauri mining permit areas. Our 2006 planned activity in New Zealand includes drilling six to eight development wells and two to four exploration wells. We also plan to acquire seismic on our offshore Kaheru exploration permit in 2006.

     Rimu/Kauri Area. Since 2002, we have held a 100% working interest in petroleum mining permit 38151 covering approximately 5,500 acres in the Rimu area for a primary term of 30 years. We began commercial production from the Rimu area in May 2002, and own a hydrocarbon-processing facility in this area as well. During 2005, we completed two out of five wells in the Kauri area. One of these wells successfully targeted the Kauri sands, and one was completed in the Manutahi sand. We were awarded a 30-year primary term mining permit covering approximately 8,714 acres in the Kauri area in April 2005. Our natural gas production from this area is sold to Genesis Power Ltd. under a long-term contract for use at its Huntly Power Station, New Zealand’s largest thermal power station.

     TAWN Area. Our interest in TAWN consists of a 100% working interest in four petroleum mining permits, 38138 through 38141, covering producing oil and gas fields and extensive associated hydrocarbon-processing facilities and pipelines. The properties are collectively identified as the TAWN properties, an acronym derived from the first letters of the field names — the Tariki field, the Ahuroa field, the Waihapa field, and the Ngaere field. The four fields include 18 wells where the purchaser of gas is Contact Energy. In 2005, we completed the Piakau North A1 exploration well in this area. The TAWN assets are located approximately 17 miles north of the Rimu/Kauri area.

     Our infrastructure in New Zealand includes two hydrocarbon-processing plants with significant excess capacity. We also own the pipelines connecting the fields and facilities to export terminals and interior markets.

     Diversity Areas. Two prospects, which were drilling at the end of 2005, are located in our TAWN area and are identified as the Goss prospect (Goss A1 well), and the Trapper prospect (Trapper A1 well). Both prospects have the Kapuni group sands (the major reservoir in the basin) as their main target, but as these wells are drilled they will also pass through the Tariki sandstone and other major producing sands in the basin. We have entered into a series of farm-out agreements with Mighty River Power (“MRP”), a state owned New Zealand utility, which provide for a 50% working interest in both the Goss A1 well, and the Trapper A1 well. Under the farm-out agreements, MRP will provide the funding for the drilling of these exploration wells and can earn a 50% working interest in certain commercial discoveries, outside of known productive zones, resulting from these wells. Once MRP has earned its 50%, we will equally share any future development costs subject to the terms of the agreements. We will continue to maintain our 100% working interest in the existing producing horizons and facilities in both the TAWN and Rimu/Kauri areas.

     In December 2004, we entered into a farm-in agreement with Ballance Agri-Nutrients Limited of New Zealand for their exploration permit 38742. The approximately 16,800 gross acre permit is located onshore in the north-central Taranaki Basin. Under the terms of the contract, we became the operator of the permit, and now have an 80% working interest. We anticipate drilling an exploratory well in this area in the second half of 2006.

Summary of New Zealand Government Licenses and Permits

     Our acreage in New Zealand is licensed from the New Zealand government under both production exploration permits (PEP), production mining licenses (PML), and production mining permits (PMP). These licenses and permits as of December 31, 2005 are summarized in the following table:

		Date of
		Initial Interest				Swift’s
Permit		Acquired				Interest
PEP 38495			2005				50	%
PEP 38716			1999				21	%
PEP 38719			1996				100	%
PEP 38742			2004				80	%
PML 38138			2002				100	%
PML 38139			2002				100	%
PML 38140			2002				100	%
PML 38141			2002				100	%
PMP 38151			2002				100	%
PMP 38155			2005				100	%

     Details of these licenses can be found on the New Zealand government’s Crown Minerals website at http://crownminerals.med.govt.nz/index.asp.

Oil and Natural Gas Reserves

     The following tables present information regarding proved reserves of oil and natural gas attributable to our interests in producing properties as of December 31, 2005, 2004, and 2003. The information set forth in the tables regarding reserves is based on proved reserves reports prepared by us and audited by H. J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy has audited 100% of our proved reserves. Gruy’s audit was conducted according to standards approved by the Board of Directors of the Society of Petroleum Engineers, Inc. and included examination, on a test basis, of the evidence supporting our reserves. Gruy’s audit was based upon review of all available production histories and other geological, economic, and engineering data, all of which was provided by us.

     Estimates of future net revenues from our proved reserves and their PV-10 Value are made using oil and gas sales prices in effect as of the dates of such estimates adjusted for the effects of hedging and are held constant, for that year’s reserves calculation, throughout the life of the properties, except where such guidelines permit alternate treatment, including, in the case of gas contracts, the use of fixed and determinable contractual price escalations. We have interests in certain tracts that are estimated to have additional hydrocarbon reserves that cannot be classified as

proved and are not reflected in the following tables. Our hedges at year-end 2005 consisted of natural gas price floors with strike prices lower than the period-end price and thus did not materially affect prices used in these calculations. The weighted averages of such year-end 2005 prices domestically were $10.36 per Mcf of natural gas, $60.00 per barrel of oil, and $33.28 per barrel of NGL, compared to $5.87, $42.21, and $26.49 at year-end 2004 and $5.53, $30.88, and $21.81 at year-end 2003, respectively. The weighted averages of such year-end 2005 prices for New Zealand were $3.79 per Mcf of natural gas, $60.98 per barrel of oil, and $19.20 per barrel of NGL, compared to $3.07, $33.60, and $20.48 in 2004 and $2.04, $26.78, and $14.10 in 2003, respectively. The weighted averages of such year-end 2005 prices for all our reserves, both domestically and in New Zealand, were $8.94 per Mcf of natural gas, $60.12 per barrel of oil, and $31.40 per barrel of NGL, compared to $5.16 $41.07, and $25.48 in 2004 and $4.56, $30.16, and $20.61 in 2003, respectively.

     The following tables set forth estimates of future net revenues presented on the basis of unescalated prices and costs in accordance with criteria prescribed by the Securities and Exchange Commission and their PV-10 Value as of December 31, 2005, 2004, and 2003. Operating costs, development costs, asset retirement obligation costs, and certain production-related taxes were deducted in arriving at the estimated future net revenues. No provision was made for income taxes. The estimates of future net revenues and their present value differ in this respect from the standardized measure of discounted future net cash flows set forth in supplemental information to our consolidated financial statements, which is calculated after provision for future income taxes. We combine NGLs with oil for reserves reporting purposes. PV-10 is a non-GAAP measure, see the reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure, in the section below this table.

		As of December 31, 2005
		Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed			152,001				125,368				26,633
Proved undeveloped			135,472				99,907				35,565
Total			287,473				225,275				62,198
Oil reserves (MBbl):
Proved developed			37,990				35,298				2,691
Proved undeveloped			41,063				34,485				6,579
Total			79,053				69,783				9,270
Total Estimated Reserves (Bcfe)			762				644				118
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed		$	1,721			$	1,612			$	109
Proved undeveloped			1,450				1,248				202
PV-10 Value		$	3,171			$	2,860			$	311

		As of December 31, 2004
		Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed			193,311				140,549				52,762
Proved undeveloped			124,935				97,343				27,593
Total			318,246				237,892				80,355
Oil reserves (MBbl):
Proved developed			42,038				36,629				5,409
Proved undeveloped			38,229				32,510				5,719
Total			80,267				69,139				11,128
Total Estimated Reserves (Bcfe)			800				653				147
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed		$	1,182			$	1,038			$	144
Proved undeveloped			839				760				79
PV-10 Value		$	2,021			$	1,797			$	224

		As of December 31, 2003
		Total				Domestic				New Zealand
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed			210,120				138,173				71,947
Proved undeveloped			125,685				104,148				21,537
Total			335,805				242,321				93,484
Oil reserves (MBbl):
Proved developed			45,525				38,768				6,757
Proved undeveloped			35,235				28,248				6,987
Total			80,760				67,016				13,744
Total Estimated Reserves (Bcfe)			820				644				176
Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed		$	941			$	806			$	135
Proved undeveloped			598				517				80
PV-10 Value		$	1,539			$	1,323			$	215

     Proved reserves are estimates of hydrocarbons to be recovered in the future. Reservoir engineering is a subjective process of estimating the sizes of underground accumulations of oil and gas that cannot be measured in an exact way. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Reserves reports of other engineers might differ from the reports contained herein. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Future prices received for the sale of oil and gas may be different from those used in preparing these reports. The amounts and timing of future operating and development costs may also differ from those used. Accordingly, reserves estimates are often different from the quantities of oil and gas that are ultimately recovered. There can be no assurance that these estimates are accurate predictions of the present value of future net cash flows from oil and gas reserves.

     No other reports on our reserves have been required to be filed, nor have any been filed with any federal agency.

     The closest GAAP measure to PV-10, a non-GAAP measure, is the standardized measure of discounted future net cash flows. We believe PV-10 is a helpful measure in evaluating the value of our oil and gas reserves and many securities analysts and investors use PV-10. We use PV-10 in our ceiling test computations, and we also compare PV-10 against our debt balances. The following table is a reconciliation between PV-10 and the standardized measure of discounted future net cash flows:

		As of December 31, 2005
(In millions)		Total				Domestic				New Zealand
PV-10 Value		$	3,171			$	2,860			$	311
Future income taxes (discounted at 10%)			(984	)			(942	)			(42	)
Asset retirement obligations (discounted at 10%)			(27	)			(23	)			(4	)
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves		$	2,159			$	1,895			$	265

		As of December 31, 2004
(In millions)		Total				Domestic				New Zealand
PV-10 Value		$	2,021			$	1,797			$	224
Future income taxes (discounted at 10%)			(533	)			(521	)			(12	)
Asset retirement obligations (discounted at 10%)			(23	)			(19	)			(4	)
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves		$	1,465			$	1,257			$	208

		As of December 31, 2003
(In millions)		Total				Domestic				New Zealand
PV-10 Value		$	1,539			$	1,323			$	215
Future income taxes (discounted at 10%)			(392	)			(351	)			(41	)
Asset retirement obligations (discounted at 10%)			(13	)			(9	)			(2	)
Standardized Measure of Discounted Future Net Cash Flows relating to oil and gas reserves		$	1,135			$	963			$	172

Proved Undeveloped Reserves

     The following table sets forth the aging and PV-10 value of our proved undeveloped reserves as of December 31, 2005:

										PV-10
		Volume				% of PUD				Value				% of PUD
Year Added		(Bcfe)				Volumes				(in millions)				PV-10 Value
2005			102.9				27	%		$	439.2				30	%
2004			70.4				18	%			299.4				21	%
2003			59.4				16	%			248.7				17	%
2002			40.6				11	%			122.6				8	%
2001			16.5				4	%			74.8				5	%
Prior to 2001			92.1				24	%			264.0				19	%
Total			381.9				100	%		$	1,448.7				100	%

Sensitivity of Reserves to Pricing

     As of December 31, 2005, a 5% increase in crude oil and NGL pricing would increase our total estimated proved reserves of 761.8 Bcfe by approximately 0.3 Bcfe, and increase the total PV-10 Value of $3.2 billion by approximately $129 million. Similarly, a 5% decrease in crude oil and NGL pricing would decrease our total estimated proved reserves by approximately 0.2 Bcfe and decrease the total PV-10 Value by approximately $131 million.

     As of December 31, 2005 a 5% increase in natural gas pricing (exclusive of fixed contract volumes) would increase our total estimated proved reserves by approximately 0.4 Bcfe and increase the total PV-10 Value by approximately $60 million. Similarly, a 5% decrease in natural gas pricing (exclusive of fixed contract volumes) would decrease our total estimated proved reserves by approximately 0.3 Bcfe and decrease the total PV-10 Value by approximately $63 million.

Oil and Gas Wells

     The following table sets forth the gross and net wells in which we owned an interest at the following dates:

		Oil Wells				Gas Wells				Total Wells(1)
December 31, 2005:
Gross			402				565				967
Net			324.84				497.47				822.31
December 31, 2004:
Gross			358				574				932
Net			308.8				525.9				834.7
December 31, 2003:
Gross			397				560				957
Net			340.6				504.0				844.6

Oil and Gas Acreage

     The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2005:

		Developed(1)								Undeveloped(1)
		Gross				Net				Gross				Net
Alabama			9,045.27				2,587.86				124.22				79.82
Louisiana			104,746.41				86,175.61				20,019.57				15,656.27
Texas			134,942.31				93,034.91				21,507.04				15,100.67
Wyoming			640.00				151.06				54,117.93				52,322.47
All other states			320.00				266.66				400.00				319.82
Offshore Louisiana			4,609.37				276.56				5,000.00				258.34
Offshore Texas			2,880.00				74.39				—				—
Total Domestic			257,183.36				182,567.05				101,168.76				83,737.39
New Zealand			9,480.00				9,118.15				143,250.85				114,291.18
Total			266,663.36				191,685.20				244,419.61				198,028.57

(1)

Fee mineral acres acquired in the Brookeland and Masters Creek areas acquisition are not included in the above leasehold acreage table. We have 26,345 developed fee mineral acres and 69,149 undeveloped fee mineral acres for a total of 95,494 fee mineral acres.

Drilling Activities

     The following table sets forth the results of our drilling activities during the three years ended December 31, 2005:

						Gross Wells												Net Wells
Year				Type of Well		Total				Producing				Dry				Total				Producing				Dry
	2005			Exploratory — Domestic			9				5				4				9.0				5.0				4.0
				Development — Domestic			45				37				8				44.3				36.3				8.0
				Exploratory — New Zealand			5				1				4				3.7				1.0				2.7
				Development — New Zealand			5				2				3				5.0				2.0				3.0
	2004			Exploratory — Domestic			10				4				6				7.5				2.3				5.2
				Development — Domestic			44				37				7				41.7				35.0				6.7
				Exploratory — New Zealand			1				—				1				1.0				—				1.0
				Development — New Zealand			11				10				1				11.0				10.0				1.0
	2003			Exploratory — Domestic			8				5				3				7.3				5.0				2.3
				Development — Domestic			63				53				10				61.9				51.9				10.0
				Exploratory — New Zealand			1				—				1				0.5				—				0.5
				Development — New Zealand			3				3				—				3.0				3.0				—

Operations

     We generally seek to be operator in the wells in which we have a significant economic interest. As operator, we design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or other oil field services equipment used for drilling or maintaining wells on properties we operate. Independent contractors supervised by us provide this equipment and personnel. We employ drilling, production, and reservoir engineers, geologists, and other specialists who work to improve production rates, increase reserves, and lower the cost of operating our oil and gas properties.

     Oil and gas properties are customarily operated under the terms of a joint operating agreement. These agreements usually provide for reimbursement of the operator’s direct expenses and for payment of monthly per-well supervision fees. Supervision fees vary widely depending on the geographic location and depth of the well and whether the well produces oil or natural gas. The fees for these activities in 2005 totaled $7.8 million and ranged from $529 to $2,231 per well per month.

Marketing of Production

     Domestically, we typically sell our oil and natural gas production at market prices near the wellhead or at a central point after gathering and/or processing. We usually sell our natural gas in the spot market on a monthly basis, while we sell our oil at prevailing market prices. We do not refine any oil we produce. Shell Oil Company and its affiliates, both domestically and in New Zealand, accounted for 10% or more of our total revenues during the years ended December 31, 2005 and 2004, with purchases accounting for approximately 42% and 48% of our total oil and gas sales, respectively. However, due to the demand for oil and gas and availability of other purchasers, we do not believe that the loss of any single oil or gas purchaser or contract would materially affect our revenues.

     Our oil production from the Lake Washington area is delivered into ExxonMobil’s crude oil pipeline system or transported on barges for sales to various purchasers at prevailing market prices or at fixed prices tied to the then current NYMEX crude oil contract for the applicable month(s). Our natural gas production from this area is either consumed on the lease or is delivered into El Paso’s Tennessee Gas Pipeline system and then sold in the spot market at prevailing prices.

          In 1998, we entered into gas processing and gas transportation agreements for our natural gas production in the AWP Olmos area with PG&E Energy Trading Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and El Paso Industrial, LP, and then assumed by Enterprise Hydrocarbons L.P. in September 2004, for up to 75,000 Mcf per day, which provided for a ten-year term with automatic one-year extensions unless terminated earlier. We believe that these arrangements adequately provide for our gas transportation and processing needs in the AWP Olmos area for the foreseeable future.

          Our oil production from the Brookeland and Masters Creek areas is sold to various purchasers at prevailing market prices. Our natural gas production from these areas is processed under long term gas processing contracts with Duke Energy Field Services, Inc. The processed liquids and residue gas production are sold in the spot market at prevailing prices.

          Through 2005, our oil production in New Zealand was sold to Shell Petroleum Mining, and now is sold to BP at international prices tied to the Asia Petroleum Price Index (APPI) Tapis posting, less the cost of storage, trucking, and transportation.

          Our natural gas production from our TAWN fields is sold under a long-term fixed price contract with Contact Energy. Our natural gas production from the Rimu field is sold to Genesis Power Ltd. under a long-term fixed price contract that was modified in 2003 and covers approximately 7.2 Bcfe per year for a three-year period. During 2005, additional production volumes from our fields, over the contract maximum, were sold to Contact Energy or Genesis Power Ltd. at prevailing market rates.

          Production of NGLs in New Zealand is sold to Rockgas Ltd. under long-term contracts tied to New Zealand’s domestic natural gas liquids market.

          The following table summarizes sales volumes, sales prices, and production cost information for our net oil and natural gas production for the three-year period ended December 31, 2005:

		Year Ended December 31,
		2005				2004				2003
Net Sales Volume:
Oil (MBbls)(1)			5,159				4,722				3,369
Natural Gas Liquids (MBbls)(2)			838				1,040				823
Natural gas (MMcf)(3)			23,609				23,742				28,003
Total (MMcfe)			59,590				58,319				53,158
Average Sales Price:
Oil (Per Bbl)(1)		$	53.63			$	40.24			$	29.89
Natural Gas Liquids (Per Bbl)(2).		$	28.04			$	22.52			$	17.60
Natural gas (Per Mcf)(3)		$	5.23			$	4.12			$	3.42
Average Production Cost (Per Mcfe)		$	1.50			$	1.23			$	0.99

Risk Management

          Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, including blowouts, cratering, pipe failure, casing collapse, fires, and adverse weather conditions, each of which could result in severe damage to or destruction of oil and gas wells, production facilities or other property, or individual injuries. The oil and gas exploration business is also subject to environmental hazards, such as oil spills, gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. See “1A. Risk Factors” of this report for more details and for discussion of other risks. We maintain comprehensive insurance coverage, including general liability insurance, officer and director liability insurance, and property damage insurance. Prior to and at the time of Hurricanes Katrina and Rita, we maintained business interruption insurance as well. Since such time, the cost of such insurance coverage increased to a level that we believe makes it uneconomical to maintain at this time. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident, or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us.

Commodity Risk

          The oil and gas industry is affected by the volatility of commodity prices. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. We have a price-risk management policy to use derivative instruments to protect against declines in oil and gas prices, mainly through the purchase of price floors and collars. At December 31, 2005, we had price floors in place through the June 2006 contract month for natural gas; these cover a portion of our domestic natural gas production for February 2006 to June 2006. The natural gas price floors cover notional volumes of 2,075,000 MMBtu, with a weighted average floor price of $8.39 per MMBtu. Our natural gas price floors in place at December 31, 2005 are expected to cover approximately 35% to 40% of our domestic natural gas production from February 2006 to June 2006.

Competition

          We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition. Our ability to replace and expand our reserves base depends on our continued ability to attract and retain quality personnel and identify and acquire suitable producing properties and prospects for future drilling.

Regulations

Environmental Regulations

          Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of a permit by operators before drilling commences, prohibit drilling activities on certain lands lying within wilderness areas, wetlands, and other ecologically sensitive and protected areas, and impose substantial remedial liabilities for pollution resulting from drilling operations. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of significant investigatory or remedial obligations, and the imposition of injunctive relief that limits or prohibits our operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our operations and financial position, as well as those of the oil and gas industry in general. While we believe that we are in substantial compliance with current environmental laws and regulations and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

          We currently own or lease, and have in the past owned or leased, numerous properties in connection with our domestic operations that have been used for the exploration and production of oil and gas for many years. Although

we have used operation and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, many of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and the wastes disposed thereon or away from could be subject to stringent and costly investigatory or remedial requirements under applicable laws, some of which are strict liability laws without regard to fault or the legality of the original conduct, including the federal Comprehensive Environmental Response, Compensation, and Liability Act, also known as “CERCLA” or the “Superfund” law, the federal Resource Conservation and Recovery Act or “RCRA,” the federal Clean Water Act, the federal Clean Air Act, the federal Oil Pollution Act or “OPA,” and analogous state laws. Under such laws and any implementing regulations, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), to perform natural resource mitigation or restoration practices, or to perform remedial plugging or closure operations to prevent future contamination. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury or property damages allegedly caused by the release of petroleum hydrocarbons or other wastes into the environment.

          Our domestic operations offshore in the Gulf of Mexico are subject to OPA, which imposes a variety of requirements related to the prevention of oil spills, and liability for damages resulting from such spills in United States waters. The OPA imposes strict, joint and several liability on responsible parties for oil removal costs and a variety of public and private damages, including natural resource damages. Liability limits for offshore facilities require a responsible party to pay all removal costs, plus up to $75 million in other damages. These liability limits do not apply, however, if the spill was caused by gross negligence or willful misconduct of the party, if the spill resulted from violation of a federal safety, construction or operation regulation, or if the party fails to report the spill or cooperate fully in any resulting cleanup. The OPA also requires a responsible party at an offshore facility to submit proof of its financial ability to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. We believe our operations are in substantial compliance with OPA requirements.

          Our operations in New Zealand could also potentially be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior operators, closure and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations. While we believe that we are in substantial compliance with current environmental laws and regulations in New Zealand, and have not experienced any material adverse effect from such compliance, there is no assurance that this trend will continue in the future.

    United States Federal, State and New Zealand Regulation of Oil and Natural Gas

          The transportation and certain sales of natural gas in interstate commerce are heavily regulated by agencies of the federal government and are affected by the availability, terms and cost of transportation. The price and terms of access to pipeline transportation are subject to extensive federal and state regulation. The Federal Energy Regulatory Commission (“FERC”) is continually proposing and implementing new rules and regulations affecting the natural gas industry, most notably interstate natural gas transmission companies that remain subject to the FERC’s jurisdiction. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry. Some recent FERC proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines.

          Our sales of crude oil, condensate and NGLs are not currently subject to FERC regulation. However, the ability to transport and sell such products is dependent on certain pipelines whose rates, terms and conditions of service are subject to FERC regulation.

          Production of any oil and gas by us will be affected to some degree by state regulations. Many states in which we operate have statutory provisions regulating the production and sale of oil and gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and gas and to protect correlative rights to produce oil and gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the

17

rate that a well would otherwise produce in the absence of such regulation. In addition, certain state regulatory authorities can limit the number of wells or the locations where wells may be drilled. Any of these actions could negatively affect the amount or timing of revenues. Likewise, the government of New Zealand regulates the exploration, production, sales, and transportation of oil and natural gas.

Federal Leases

          Some of our domestic properties are located on federal oil and gas leases administered by various federal agencies, including the Bureau of Land Management. Various regulations and administrative orders affect the terms of leases, and in turn may affect our exploration and development plans, methods of operation, and related matters.

Litigation

          In the ordinary course of business, we have been party to various legal actions, which arise primarily from our activities as operator of oil and gas wells. In our opinion, the outcome of any such currently pending legal actions will not have a material adverse effect on our financial position or results of operations.

Employees

          At December 31, 2005, we employed 311 persons. Of these employees, 75 were in New Zealand, including four expatriate employees. Eight of our New Zealand employees are members of a union. None of our other employees are represented by a union. Relations with employees are considered to be good.

Facilities

          At December 31, 2005, we occupied approximately 120,000 square feet of office space at 16825 Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2015. The lease requires payments of approximately $216,000 per month. In New Zealand we leased approximately 18,400 square feet of office space, under leases expiring in 2008 and 2009. These New Zealand leases require payments of approximately $33,000 per month. We also have field offices in various locations from which our employees supervise local oil and gas operations.

Available Information

          Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, amendments to those reports, changes in and stock ownership of our directors and executive officers, together with other documents filed with the Securities and Exchange Commission under the Securities Exchange Act can be accessed free of charge on our web site at www.swiftenergy.com as soon as reasonably practicable after we electronically file these reports with the SEC. All exhibits and supplemental schedules to these reports are available free of charge through the SEC web site at www.sec.gov. In addition, we have adopted a Code of Ethics for Senior Financial Officers and Principal Executive Officer. We have posted this Code of Ethics on our website, where we also intend to post any waivers from or amendments to this Code of Ethics.

Item 1A. Risk Factors

          The nature of the business activities conducted by Swift Energy subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to our business activities. Other risks are described in Items 1 and 2 Business and Properties “Competition” and “Regulations” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Our oil and gas exploration and production business involves high risks and we may suffer uninsured losses.

          These risks include blowouts, explosions, adverse weather effects and pollution and other environmental damage, any of which could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Increased hurricane activity over the past two years has resulted in production curtailments and physical damage to the Company’s Gulf Coast operations. Although the Company currently maintains insurance coverage that it considers reasonable and that is similar to that maintained by comparable companies in the oil and gas industry, it is not fully insured against certain of these risks, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance.

Oil and natural gas prices are volatile. A substantial decrease in oil and natural gas prices would adversely affect our financial results.

          Our future revenues, net income, cash flow, and the value of our oil and natural gas properties depend primarily upon market prices for oil and natural gas. Oil and natural gas prices historically have been volatile and will likely continue to be volatile in the future. The recent record high oil and natural gas prices may not continue and could drop precipitously in a short period of time. The prices for oil and natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty, worldwide economic conditions, weather conditions, currency exchange rates, and political conditions in major oil producing regions, especially the Middle East. A significant decrease in price levels for an extended period would negatively affect us in several ways:

	•		our cash flow would be reduced, decreasing funds available for capital expenditures employed to increase production or replace reserves;
	•		certain reserves would no longer be economic to produce, leading to both lower cash flow and proved reserves;
	•		our lenders could reduce the borrowing base under our bank credit facility because of lower oil and natural gas reserves values, reducing our liquidity and possibly requiring mandatory loan repayments; and
	•		access to other sources of capital, such as equity or long term debt markets, could be severely limited or unavailable in a low price environment.
			Consequently, our revenues and profitability would suffer.

Our level of debt could reduce our financial flexibility, and we currently have the ability to incur substantially more debt, including secured debt.

          As of December 31, 2005, our total debt comprised approximately 37% of our total capitalization. Although our bank credit facility and indentures limit our ability and the ability of our restricted subsidiaries to incur additional indebtedness, we will be permitted to incur significant additional indebtedness, including secured indebtedness, in the future if specified conditions are satisfied. All borrowings under our bank credit facility are effectively senior to our outstanding 7-5/8% senior notes and 9-3/8% senior subordinated notes to the extent of the value of the collateral securing those borrowings. Our current level of indebtedness:

	•		will require us to dedicate a substantial portion of our cash flow to the payment of interest;
	•		will subject us to a higher financial risk in an economic downturn due to substantial debt service costs;

	•		may limit our ability to obtain financing or raise equity capital in the future; and
	•		may place us at a competitive disadvantage to the extent that we are more highly leveraged than some of our peers.
			Higher levels of indebtedness would increase these risks.

Estimates of proved reserves are uncertain, and revenues from production may vary significantly from expectations.

          The quantities and values of our proved reserves included in this report are only estimates and subject to numerous uncertainties. Estimates by other engineers might differ materially. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation. These estimates depend on assumptions regarding quantities and production rates of recoverable oil and natural gas reserves, future prices for oil and natural gas, timing and amounts of development expenditures and operating expenses, all of which will vary from those assumed in our estimates. These variances may be significant.

          Any significant variance from the assumptions used could result in the actual amounts of oil and natural gas ultimately recovered and future net cash flows being materially different from the estimates in our reserves reports. In addition, results of drilling, testing, production, and changes in prices after the date of the estimates of our reserves may result in substantial downward revisions. These estimates may not accurately predict the present value of net cash flows from our oil and natural gas reserves.

          At December 31, 2005, approximately 50% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling operations. The reserves data assumes that we can and will make these expenditures and conduct these operations successfully, which may not occur.

If we cannot replace our reserves, our revenues and financial condition will suffer.

          Unless we successfully replace our reserves, our long- term production will decline, which could result in lower revenues and cash flow. When oil and natural gas prices decrease, our cash flow decreases, resulting in less available cash to drill and replace our reserves and an increased need to draw on our bank credit facility. Even if we have the capital to drill, unsuccessful wells can hurt our efforts to replace reserves. Additionally, lower oil and natural gas prices can have the effect of lowering our reserves estimates and the number of economically viable prospects that we have to drill.

Drilling wells is speculative and capital intensive.

          Developing and exploring properties for oil and natural gas requires significant capital expenditures and involves a high degree of financial risk, including the risk that no commercially productive oil or gas reservoirs will be encountered. The budgeted costs of drilling, completing, and operating wells are often exceeded and can increase significantly when drilling costs rise. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages, and mechanical difficulties. Moreover, the successful drilling or completion of an oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations.

          We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, or results of operations. Our oil and natural gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

	•		Hurricanes or tropical storms;
	•		environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas, or other pollution into the environment, including groundwater and shoreline contamination;

	•		abnormally pressured formations;
	•		mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;
	•		fires and explosions;
	•		personal injuries and death; and
	•		natural disasters.

          Any of these risks could adversely affect our ability to conduct operations or result in substantial losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our financial condition.

We are exposed to the risk of fluctuations in foreign currencies, primarily the New Zealand dollar.

          Fluctuations in rates between the New Zealand dollar and U.S. dollar impact our financial results from our New Zealand subsidiaries since we have receivables, liabilities, and natural gas and NGL sales contracts denominated in New Zealand dollars. We do not hedge against the risks associated with fluctuations in exchange rates. Although we may use hedging techniques in the future, we may not be able to eliminate or reduce the effects of currency fluctuations. As a result, exchange rate fluctuations could have an adverse impact on our operating results.

We have incurred a write-down of the carrying values of our properties in the past and could incur additional write-downs in the future.

          Under the full cost method of accounting, SEC accounting rules require that on a quarterly basis we review the carrying value of our oil and gas properties on a country-by-country basis for possible write-down or impairment. Under these rules, capitalized costs of proved reserves may not exceed a ceiling calculated at the present value of estimated future net revenues from those proved reserves, determined using a 10% per year discount and unescalated prices in effect as of the end of each fiscal quarter. Capital costs in excess of the ceiling must be permanently written down.

          We recorded an after-tax, non-cash charge during the fourth quarter of 2001 of $63.5 million. This write-down resulted in a charge to earnings and a reduction of stockholders’ equity, but did not impact our cash flow from operating activities. If commodity prices decline or if we have significant downward reserves revisions, we could incur additional write-downs in the future.

Substantial acquisitions or other transactions could require significant external capital and could change our risk and property profile.

          To finance acquisitions, we may need to substantially alter or increase our capitalization through the use of our bank credit facility, the issuance of debt or equity securities, the sale of production payments, or by other means. These changes in capitalization may significantly affect our risk profile. Additionally, significant acquisitions or other transactions can change the character of our operations and business. The character of the new properties may be substantially different in operating or geological characteristics or geographic location than our existing properties. Furthermore, we may not be able to obtain external funding for any such acquisitions or other transactions or to obtain external funding on terms acceptable to us.

Reserves on acquired properties may not meet our expectations, and we may be unable to identify liabilities associated with acquired properties or obtain protection from sellers against associated liabilities.

          Property acquisition decisions are based on various assumptions and subjective judgments that are speculative. Although available geological and geophysical information can provide information about the potential of a property, it is impossible to predict accurately a property’s production and profitability. In addition, we may have difficulty integrating future acquisitions into our operations, and they may not achieve our desired profitability objectives. Likewise, as is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except through the transferor. In many instances, title opinions are not obtained if, in our judgment, it would

be uneconomical or impractical to do so. Losses may result from title defects or from defects in the assignment of leasehold rights. While our current operations are primarily in Louisiana, Texas, and New Zealand, we may pursue acquisitions of properties located in other geographic areas, which would decrease our geographical concentration, and could also be in areas in which we have no or limited experience.

          In addition, our assessment of acquired properties may not reveal all existing or potential problems or liabilities, nor will it permit us to become familiar enough with the properties to assess fully their capabilities and deficiencies. In the course of our due diligence, we may not inspect every well, platform, or pipeline. Inspections may not reveal structural and environmental problems, such as pipeline corrosion or groundwater contamination. We may not be able to obtain contractual indemnities from the seller for liabilities that it created. We may be required to assume the risk of the physical condition of acquired properties in addition to the risk that the properties may not perform in accordance with our expectations.

Prospects that we decide to drill may not yield oil or natural gas in commercially viable quantities.

          There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities, if at all, to recover drilling or completion costs or to be economically viable. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. In addition, a variety of factors, including geological and market-related, can cause a well to become uneconomical or only marginally economical. For example, if oil and natural gas prices are much lower after we complete a well than when we identified it as a prospect, the completed well may not yield commercially viable quantities.

In many instances, title opinions on our oil and gas acreage are not be obtained if in our judgment it would be uneconomical or impractical to do so.

          As is customary in the industry, we generally acquire oil and gas acreage without any warranty of title except as to claims made by, through, or under the transferor. Although we have title to developed acreage examined prior to acquisition in those cases in which the economic significance of the acreage justifies the cost, there can be no assurance that losses will not result from title defects or from defects in the assignment of leasehold rights.

Our use of oil and natural gas price hedging contracts involves credit risk and may limit future revenues from price increases and expose us to risk of financial loss.

          We enter into hedging transactions for our oil and natural gas production to reduce exposure to fluctuations in the price of oil and natural gas, primarily to protect against declines in prices. Our hedges at year-end 2005 consisted of mainly natural gas price floors with strike prices lower than the period end prices. Our hedging transactions have also consisted of financially settled crude oil and natural gas forward sales contracts with major financial institutions as well as crude oil price floors. We intend to continue to enter into these types of hedging transactions in the foreseeable future. Hedging transactions expose us to risk of financial loss in some circumstances, including if production is less than expected, the other party to the contract defaults on its obligations, or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. Hedging transactions other than floors may limit the benefit we would have otherwise received from increases in the price for oil and natural gas. Additionally, hedging transactions other than floors may expose us to cash margin requirements.

We may have difficulty competing for oil and gas properties or supplies.

          We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and gas properties, as well as for the equipment, labor, and materials required to develop and operate such properties. Many of these competitors have financial and technological resources substantially greater than ours. The market for oil and gas properties is highly competitive and we may lack technological information or expertise available to other bidders. We may incur higher costs or be unable to acquire and develop desirable properties at costs we consider reasonable because of this competition.

Our business depends on oil and natural gas transportation facilities, some of which are owned by others.

          The marketability of our oil and natural gas production depends in part on the availability, proximity, and capacity of pipeline systems owned by third parties. The unavailability of or lack of available capacity on these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our product, material changes in these business relationships could materially affect our operations. Federal and state regulation of oil and natural gas production and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines and general economic conditions could adversely affect our ability to produce, gather and transport oil and natural gas.

Governmental laws and regulations are costly and stringent, especially those relating to environmental protection.

          Our domestic exploration, production, and marketing operations are subject to complex and stringent federal, state, and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. These laws and regulations affect the costs, manner, and feasibility of our operations and require us to make significant expenditures in our efforts to comply. Failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial obligations, and the issuance of injunctions that could limit or prohibit our operations. In addition, some of these laws and regulations may impose joint and several, strict liability for contamination resulting from spills, discharges, and releases of substances, including petroleum hydrocarbons and other wastes, without regard to fault or the legality of the original conduct. Under such laws and regulations, we could be required to remove or remediate previously disposed substances and property contamination, including wastes disposed or released by prior owners or operations. Changes in or additions to environmental laws and regulations occur frequently, and any changes or additions that result in more stringent and costly waste handling, storage, transport, disposal, or cleanup requirements could have a material adverse effect our operations and financial position.

          Our operations outside of the United States could also be subject to similar foreign governmental controls and restrictions pertaining to protection of human health and the environment. These controls and restrictions may include the need to acquire permits, prohibitions on drilling in certain environmentally sensitive areas, performance of investigatory or remedial actions for any releases of petroleum hydrocarbons or other wastes caused by us or prior owners or operators, closure, and restoration of facility sites, and payment of penalties for violations of applicable laws and regulations.

Item 1B. Unresolved Staff Comments

None.

Glossary of Abbreviations and Terms

The following abbreviations and terms have the indicated meanings when used in this report:

Bbl — Barrel or barrels of oil.

Bcf — Billion cubic feet of natural gas.

Bcfe — Billion cubic feet of natural gas equivalent (see Mcfe).

BOE — Barrels of oil equivalent.

Development Well — A well drilled within the presently proved productive area of an oil or natural gas reservoir, as indicated by reasonable interpretation of available data, with the objective of completing in that reservoir.

Discovery Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred exploration and development costs (exclusive of future development costs) by net reserves added during the period through extensions, discoveries, and other additions.

Dry Well — An exploratory or development well that is not a producing well.

EBITDA — Earnings before interest, taxes, depreciation, depletion and amortization.

EBITDAX — Earnings before interest, taxes, depreciation, depletion and amortization, and exploration expenses. Since Swift uses full-cost accounting for oil and property expenditures, as noted in footnote one of the accompanying consolidated financial statements, exploration expenses are not applicable to Swift.

Exploratory Well — A well drilled either in search of a new, as yet undiscovered oil or natural gas reservoir or to greatly extend the known limits of a previously discovered reservoir.

FASB — The Financial Accounting Standards Board.

Gigajoules — A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural gas.

Gross Acre — An acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.

Gross Well — A well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned.

MBbl — Thousand barrels of oil.

Mcf — Thousand cubic feet of natural gas.

Mcfe — Thousand cubic feet of natural gas equivalent, which is determined using the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf of natural gas.

MMBbl — Million barrels of oil.

MMBtu — Million British thermal units, which is a heating equivalent measure for natural gas and is an alternate measure of natural gas reserves, as opposed to Mcf, which is strictly a measure of natural gas volumes. Typically, prices quoted for natural gas are designated as price per MMBtu, the same basis on which natural gas is contracted for sale.

MMcf — Million cubic feet of natural gas.

MMcfe — Million cubic feet of natural gas equivalent (see Mcfe).

Net Acre — A net acre is deemed to exist when the sum of fractional working interests owned in gross acres equals one. The number of net acres is the sum of fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.

Net Well — A net well is deemed to exist when the sum of fractional working interests owned in gross wells equals one. The number of net wells is the sum of fractional working interests owned in gross wells expressed as whole numbers and fractions thereof.

NGL— Natural gas liquid.

Producing Well — An exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

*

Proved Developed Oil and Gas Reserves — Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

*

Proved Oil and Gas Reserves — The estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, that is, prices and costs as of the date the estimate is made.

*

Proved Undeveloped Oil and Gas Reserves — Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Proved Undeveloped (PUD) Locations — A location containing proved undeveloped reserves.

PV-10 Value — The estimated future net revenues to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization.

Reserves Replacement Cost — With respect to proved reserves, a three-year average (unless otherwise indicated) calculated by dividing total incurred acquisition, exploration, and development costs (exclusive of future development costs) by net reserves added during the period.

SFAS — Statement of Financial Accounting Standards.

TAWN — New Zealand producing properties acquired by Swift in January 2002. TAWN is comprised of the Tariki, Ahuroa, Waihapa, and Ngaere fields.

*

These definitions regarding various types of proved reserves are only abbreviated versions of the Securities and Exchange Commission’s definitions of these terms contained in Rule 4-10(a) of Regulation S-X. See www.sec.gov/divisions/corpfin/forms/regsx.htm#gas for the full text of the SEC’s definitions of these terms.

Item 3. Legal Proceedings

          No material legal proceedings are pending other than ordinary, routine litigation and claims incidental to our business.

Item 4. Submission of Matters to a Vote of Security Holders

          No matters were submitted during the fourth quarter of 2005 to a vote of security holders.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Common Stock, 2004 and 2005

          Our common stock is traded on the New York Stock Exchange and the Pacific Exchange, Inc., under the symbol “SFY.” The high and low quarterly sales prices for the common stock for 2004 and 2005 were as follows :

		2004																2005
		First				Second				Third				Fourth				First				Second				Third				Fourth
		Quarter				Quarter				Quarter				Quarter				Quarter				Quarter				Quarter				Quarter
Low		$	15.90			$	18.72			$	18.16			$	23.50			$	24.77			$	26.22			$	37.31			$	39.82
High		$	20.02			$	22.75			$	25.16			$	30.34			$	30.64			$	36.75			$	48.86			$	50.01

          Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our credit agreements, as discussed in Note 4 to the consolidated financial statements, and we presently intend to continue a policy of using retained earnings for expansion of our business.

          We had approximately 258 stockholders of record as of December 31, 2005.

Equity Compensation Plan Information

Information regarding our equity compensation plans, including both shareholder approved plans and plans not approved by shareholders, is set forth in Proxy Statement for our annual meeting to be held May 9, 2006 (“Proxy Statement”), which Proxy Statement is to be filed within 120 days after Registrant’s fiscal year end of December 31, 2005, and which information is incorporated herein by reference.

Item 6. Selected Financial Data

		2005				2004				2003				2002				2001
Total Revenues		$	423,226,489			$	310,276,774			$	208,900,983			$	149,969,811			$	183,807,490
Income (Loss) Before Income Taxes and Change in Accounting Principle (1)		$	178,439,551			$	101,440,242			$	50,739,178			$	18,408,289			($	34,192,333	)
Net Income (Loss)		$	115,778,456			$	68,450,917			$	29,893,812			$	11,923,227			($	22,347,765	)
Net Cash Provided by Operating Activities		$	285,333,484			$	182,582,887			$	110,827,279			$	71,626,314			$	139,884,255
Per Share Data
Weighted Average Shares Outstanding(1)			28,496,275				27,822,413				27,357,579				26,382,906				24,732,099
Earnings (Loss) per Share—Basic(1)		$	4.06			$	2.46			$	1.09			$	0.45			($	0.90	)
Earnings (Loss) per Share—Diluted(1)		$	3.95			$	2.41			$	1.08			$	0.45			($	0.90	)
Shares Outstanding at Year-End			29,009,530				28,089,764				27,484,091				27,201,509				24,795,564
Book Value per Share at Year-End		$	20.94			$	16.88			$	14.46			$	13.42			$	12.61
Market Price(1)
High		$	50.01			$	30.34			$	18.00			$	20.58			$	37.70
Low		$	24.77			$	15.90			$	7.60			$	6.80			$	16.66
Year-End Close		$	45.07			$	28.94			$	16.85			$	9.67			$	20.20
Effect on Net Income and Earnings Per Share From Changes in Accounting Principles (2)
Cumulative Effect of Change in Accounting Principle (Net of Taxes)			—				—			($	4,376,852	)			—			($	392,868	)
Effect per Share—Basic			—				—			($	0.16	)			—			($	0.01	)
Effect per Share—Diluted			—				—			($	0.16	)			—			($	0.01	)
Assets
Current Assets		$	115,055,135			$	54,385,996			$	33,460,957			$	29,768,199			$	36,752,980
Oil and Gas Properties, Net of Accumulated Depreciation, Depletion, and Amortization		$	1,079,033,739			$	923,438,160			$	815,807,003			$	721,617,941			$	628,304,060
Total Assets		$	1,204,412,622			$	990,573,147			$	859,838,544			$	767,005,859			$	671,684,833
Liabilities
Current Liabilities		$	98,421,014			$	68,618,291			$	69,353,342			$	46,884,184			$	73,245,335
Long-Term Debt		$	350,000,000			$	357,500,000			$	340,254,783			$	324,271,973			$	258,197,128
Total Liabilities		$	597,094,455			$	516,401,007			$	462,447,280			$	401,932,675			$	359,032,113
Stockholders’ Equity		$	607,318,167			$	474,172,140			$	397,391,264			$	365,073,184			$	312,652,720
Number of Employees			311				272				241				234				209
Producing Wells
Swift Operated			898				835				870				820				854
Outside Operated			69				97				128				112				381
Total Producing Wells			967				932				998				932				1,235
Wells Drilled (Gross)			64				66				75				36				53
Proved Reserves
Natural Gas (Mcf)			287,473,150				318,246,294				335,804,862				326,731,672				324,912,125
Oil, NGL, & Condensate (barrels)			79,053,056				80,267,208				80,759,903				70,438,963				53,482,636
Total Proved Reserves (Mcf equivalent)			761,791,482				799,849,539				820,364,284				749,365,449				645,807,939
Production (Mcf equivalent)(3)			59,589,526				58,318,502				53,158,384				49,752,346				44,791,202
Average Sales Price
Natural Gas (per Mcf)		$	5.23			$	4.12			$	3.42			$	2.30			$	4.23
Natural Gas Liquids (per barrel)(4)		$	28.04			$	22.52			$	17.60			$	12.82				—
Oil (per barrel)(4)		$	53.63			$	40.24			$	29.89			$	24.52			$	22.64
Mcf Equivalent		$	7.11			$	5.34			$	3.97			$	2.84			$	4.05

		2000				1999				1998				1997				1996				1995
		$	191,624,946			$	110,671,007			$	82,469,221			$	74,712,180			$	56,298,026			$	25,092,230
			92,449,488			$	29,736,151				($73,391,581	)		$	33,129,606			$	28,785,783			$	6,894,537
		$	59,184,008			$	19,286,574				($48,225,204	)		$	22,310,189			$	19,025,450			$	4,912,512
		$	128,197,227			$	73,603,426			$	54,249,017			$	55,255,965			$	37,102,578			$	14,376,463
			21,244,684				18,050,106				16,436,972				16,492,856				15,000,901				10,035,143
		$	2.79			$	1.07				($2.93	)		$	1.35			$	1.27			$	0.49
		$	2.51			$	1.07				($2.93	)		$	1.26			$	1.25			$	0.49
			24,608,344				20,823,729				16,291,242				16,459,156				15,176,417				12,509,700
		$	13.50			$	8.18			$	6.71			$	9.69			$	9.41			$	7.46
		$	43.50			$	13.31			$	21.00			$	34.20			$	28.86			$	11.48
		$	9.75			$	5.69			$	6.94			$	16.93			$	9.89			$	7.05
		$	37.63			$	11.50			$	7.38			$	21.06			$	27.16			$	10.91
		—					—				—				—				—				—
		—					—				—				—				—				—
		—					—				—				—				—				—
		$	41,872,879			$	50,605,488			$	35,246,431			$	29,981,786			$	101,619,478			$	43,380,454
		$	524,052,828			$	392,986,589			$	356,711,711			$	301,312,847			$	200,010,375			$	125,217,872
		$	572,387,001			$	454,299,414			$	403,645,267			$	339,115,390			$	310,375,264			$	175,252,707
		$	64,324,771			$	34,070,085			$	31,415,054			$	28,517,664			$	32,915,616			$	40,133,269
		$	134,729,485			$	239,068,423			$	261,200,000			$	122,915,000			$	115,000,000			$	28,750,000
		$	240,232,846			$	283,895,297			$	294,282,628			$	179,714,470			$	167,613,654			$	81,906,742
		$	332,154,155			$	170,404,117			$	109,362,639			$	159,400,920			$	142,761,610			$	93,345,965
			181				173				203				194				191				176
			817				769				836				650				842				767
			711				788				917				917				986				3,316
			1,528				1,557				1,753				1,567				1,828				4,083
			70				27				75				182				153				76
			418,613,976				329,959,750				352,400,835				314,305,669				225,758,201				143,567,520
			35,133,596				20,806,263				13,957,925				7,858,918				5,484,309				5,421,981
			629,415,552				454,797,327				436,148,385				361,459,177				258,664,055				176,099,406
			42,356,705				42,874,303				39,030,030				25,393,744				19,437,114				11,186,573
		$	4.24			$	2.40			$	2.08			$	2.68			$	2.57			$	1.77
		—					—				—				—				—				—
		$	29.35			$	16.75			$	11.86			$	17.59			$	19.82			$	15.66
		$	4.47			$	2.54			$	2.05			$	2.72			$	2.71			$	2.01

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

     You should read the following discussion and analysis in conjunction with our financial information and our audited consolidated financial statements and accompanying notes for the years ended December 31, 2005, 2004, and 2003 included with this report. The following information contains forward-looking statements, see “Forward-Looking Statements” on page 43 of this report.

Overview

     Swift Energy had record net income, cash flow, and production for 2005. Net income increased 69% to $115.8 million and cash flow increased 56% to $285 million over 2004 net income and cash flow. Production increased 2% to 59.6 Bcfe over 2004 production. We also had record revenues of $423.2 million for 2005, an increase of 36% over 2004 levels, and became the largest crude oil producer in Louisiana. Swift Energy also dealt with challenges presented by the damage and disruption caused by Hurricanes Katrina and Rita in the last half of 2005. We ended 2005 with total proved reserves of 762 Bcfe, a decrease of 5% from year-end 2004 levels. Revenues, production levels, and reserves for 2005 were lower than our pre-hurricane guidance as a result of production shut-ins and deferred drilling necessitated by Hurricanes Katrina and then Rita. We estimate that the effect of these hurricanes deferred approximately 6.0 to 6.5 Bcfe of production and deferred the drilling of approximately 10 to 15 domestic wells into 2006. Our weighted average sales price increased 33% to $7.11 per Mcfe for 2005 from $5.34 in 2004. The strong commodity prices during 2005 supported the increase in our revenues as compared to 2004 despite the impact of the hurricanes on production volumes.

     Our efforts and capital throughout 2005 remained primarily focused on infrastructure improvements, increased production, and the development of long-lived reserves through exploration and exploitation activities primarily in our four regions: South Louisiana, South Texas, Toledo Bend, and New Zealand. We expect to continue this focus throughout 2006. We are reviewing further potential capacity increase of the facilities in Lake Washington, and expect the new 3-D seismic over the Cote Blanche Island area to be completed in the third quarter of 2006, and plan to acquire seismic on our offshore Kaheru exploration permit in New Zealand.

     Our overall costs and expenses increased in 2005, and we expect to manage our costs and expenses to remain at this level in 2006. The largest increase in these costs and expenses is due to increased depreciation, depletion and amortization expense as a result of increased estimates for future development costs and additional capital expenditures during 2005. We experienced higher costs due to increased oil production in Lake Washington, along with higher severance taxes due to increased revenues. We also saw an increase in our general and administrative expenses due to an increased workforce and stock compensation expense associated with the issuance of restricted stock. Although our lease operating costs were less than originally anticipated through the first six months of 2005, due to lower than expected chemical, repair and maintenance costs as well as no significant work-over activity, lease operating costs were adversely affected in the second half of 2005 due to Hurricanes Katrina and Rita. During the last half of 2005, we recorded approximately $10.8 million of costs related to Hurricane Katrina and $4.1 million related to Hurricane Rita, and we expect additional hurricane related costs to be incurred in 2006. Approximately $2.0 million of the total costs were expensed to lease operating expense, net of estimated insurance reimbursement, in 2005. The remainder of the costs related to capital projects. We expect cost pressures to continue to affect the industry throughout 2006, especially along the Gulf Coast following the hurricanes, with tightening availability of crews as well as increasing costs of services and basic equipment.

     Year-end 2005 proved reserves of 761.8 Bcfe, representing a 5% decline for the year, were 51% crude oil, 38% natural gas and 11% NGLs, compared to year-end 2004 proved reserves of 799.8 Bcfe, which were 49% crude oil, 40% natural gas and 11% NGLs. Proved developed reserves decreased slightly to 50% of total reserves at year-end 2005, compared to 56% the previous year. Domestic proved reserves decreased at year-end 2005 to 644.0 Bcfe and included the acquisition of reserves in the South Bearhead Creek field, which was predominantly proved undeveloped. Proved reserves in New Zealand decreased to 117.8 Bcfe at year-end 2005, primarily attributable to 2005 production and downward revisions in the Kauri sands in the Rimu/Kauri area. In 2005, we focused our drilling activity, both domestically and in New Zealand, on proved undeveloped locations that helped maximize production in a high-price environment, but which also resulted in smaller additions to proved reserves.

     Our financial position remains strong and flexible, allowing us to take advantage of future opportunities in organic growth through drilling and strategic growth through acquisitions. Our financial ratios have also continued

to improve. Our debt to PV-10 ratio decreased to 11% at December 31, 2005 compared to 18% at December 31, 2004, due to higher crude oil and natural gas prices and a slight decrease in our total debt. Higher commodity prices have increased our PV-10 Value. Our debt to capitalization ratio was 37% at December 31, 2005 compared to 43% at year-end 2004, as debt levels decreased slightly in 2005 and retained earnings increased as a result of the current period profit. 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.

     There are a number of factors that support our belief that Swift Energy’s performance for 2006 will be strong. We think that strong commodity prices will continue over the foreseeable future, based in part on forward-strip pricing. Although production was impacted by the hurricane activity in the second half of 2005, all of Swift Energy’s operations in the South Louisiana region are back on production at or above pre-Katrina production levels, except for the Cote Blanche Island field, and the major facility expansion projects at the Lake Washington area are in the final commissioning stages. Cote Blanche Island is expected to be back online by the end of the first quarter of 2006. Our merged 3-D seismic data offsets around our fields in southern Louisiana has yielded success in our exploration and development activities, as demonstrated by our year-end drilling successes at our Newport and Bondi prospects in the Lake Washington area. Continued work-over and recompletion activity is expected to take place in 2006, particularly in the Bay de Chene and Cote Blanche Island fields in southern Louisiana; however, this work has been delayed somewhat due to our recovery efforts from Hurricanes Katrina and Rita. We’ve also acquired additional property in our Toledo Bend region during the fourth quarter of 2005, the South Bearhead Creek property. The Piakau discovery in New Zealand has yielded positive results, although further reservoir delineation is required. Our diversified drilling portfolio positions us for higher impact exploration drilling as well as expanded exploitation efforts in 2006.

Results of Operations — Years Ended 2005, 2004, and 2003

     Revenues. Our revenues in 2005 increased by 36% compared to revenues in 2004, and our revenues in 2004 increased by 49% compared to 2003 revenues due primarily to increases in each successive year in oil and natural gas prices and in production from our Lake Washington and Rimu/Kauri areas. Revenues from our oil and gas sales comprised substantially all of total revenues for 2005, 2004, and 2003. Crude oil production was 52% of our production volumes in 2005, 49% in 2004, and 38% in 2003. Natural gas production was 40% of our production volumes in 2005, 41% in 2004, and 53% in 2003. Domestic production was 72% of our total production volumes in both 2005 and 2004, and 64% in 2003.

     The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the years ended December 31, 2005, 2004, and 2003:

														Oil and Gas
		Oil and Gas Sales												Sales Volume
		(In millions)												(Bcfe)
Area		2005				2004				2003				2005				2004				2003
AWP Olmos		$	61.7			$	49.9			$	43.7				7.7				9.0				8.4
Brookeland			20.4				18.0				16.4				2.9				3.4				3.9
Lake Washington			229.2				152.3				59.5				26.7				23.2				12.1
Masters Creek			17.9				21.0				25.7				2.4				3.7				5.7
Other			26.7				17.5				18.9				3.3				2.8				3.7
Total Domestic		$	355.9			$	258.7			$	164.2				43.0				42.1				33.8
Rimu/Kauri			41.6				24.5				11.6				8.2				5.3				3.3
TAWN			26.3				28.1				35.2				8.3				11.0				16.1
Total New Zealand		$	67.9			$	52.6			$	46.8				16.5				16.3				19.4
Total		$	423.8			$	311.3			$	211.0				59.6				58.3				53.2