Edgar Filing: SWIFT ENERGY CO

edgar200710-k.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Fiscal Year Ended December 31, 2007

Commission File Number 1-8754

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in Its Charter)

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

16825 Northchase Drive, 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

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

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

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

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

Accelerated filer

Non-accelerated filer

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes

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 on the New York Stock Exchange as of June 29, 2007, the last business day of June 2007, was approximately $1,263,629,153.

The number of shares of common stock outstanding as of January 31, 2008 was 30,242,157.

Documents Incorporated by Reference

Document Incorporated as to

Proxy Statement for the Annual
Meeting of Shareholders to be held May 13, 2008	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	4

Item 1A.	Risk Factors	19

Item 1B.	Unresolved Staff Comments	24

Item 2.	Properties	7

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	27

Item 6.	Selected Financial Data	29

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	30

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	80

Item 9A.	Controls and Procedures	80

Item 9B.	Other Information	80

Part III
Item 10.	Directors, Executive Officers and Corporate Governance (1)	81

Item 11.	Executive Compensation (1)	81

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters (1)	81

Item 13.	Certain Relationships and Related Transactions, and Director Independence (1)	81

Item 14	Principal Accountant Fees and Services (1)	81

Part IV
Item 15	Exhibits and Financial Statement Schedules	82
(1) Incorporated by reference from Proxy Statement for the Annual Meeting of Shareholders to be held May 13, 2008

PART I

Item 1. Business

See pages 24 and 25 for explanations of abbreviations and terms used herein.

General

Swift Energy Company is engaged in developing, exploring, acquiring, and operating oil and natural gas properties, with a focus on oil and natural gas reserves onshore and in the inland waters of Louisiana and Texas. Swift Energy was founded in 1979 and is headquartered in Houston, Texas. In December 2007, we agreed to sell the majority of our New Zealand assets with an expected closing date towards the end of the first quarter of 2008. At year-end 2007, we had estimated proved reserves from our domestic continuing operations of 133.8 MMBoe with a PV-10 of $3.8 billion, while our total estimated proved reserves, both domestically and in New Zealand, were 150.1 MMBoe with a PV-10 Value of $3.9 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). Our total proved reserves at year-end 2007 were comprised of approximately 43% crude oil, 44% natural gas, and 13% NGLs; and 45% of our total proved reserves were proved developed. Our proved reserves are concentrated with 59% of the total in Louisiana, 29% in Texas, 1% in other states, and 11% in New Zealand.

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

• South Louisiana Region

Bay de Chene Area

Bayou Penchant Area

Bayou Sale Area

Cote Blanche Island Area

High Island Area

Horseshoe Bayou Area

Jeanerette Area

Lake Washington Area

• South Texas Region

AWP Olmos Area

Cotulla Area

• Toledo Bend Region

Brookeland Area

Masters Creek Area

South Bearhead Creek 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 strengths and strategies are set forth below.

Demonstrated Ability to Grow Reserves and Production

We have grown our domestic proved reserves from 99.0 MMBoe to 133.8 MMBoe over the five-year period ended December 31, 2007. Over the same period, our annual domestic production has grown from 5.7 MMBoe to 10.6 MMBoe. Our growth in reserves and production over this five-year period has resulted primarily from drilling activities and acquisitions in our three core domestic regions. During 2007, our domestic proved reserves increased by 13%, due to acquisitions of properties in our South Texas region and our 2007 drilling results. 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 in each of our three domestic 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 also focus on acquisitions. We believe this balanced approach has resulted in our ability to grow in a strategically cost effective manner, and in 2007 we replaced 245% of our domestic 2007 production and over the last five years we have replaced 187% of our domestic production.

For 2008, we are targeting total production from continuing operations to increase 10% to 15% and proved reserves from continuing operations to increase 5% to 9% over 2007 levels.

Our 2008 capital expenditures are currently budgeted at $425 million to $475 million, net of minor non-core dispositions and excluding any property acquisitions.

Replacement of Reserves

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 have included below a listing of 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 natural gas production. Our reserves additions for each year are estimates. Reserves 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, adverse weather conditions, competition within our industry, the requirement of new or upgraded infrastructure at the production site, and technological advances.

Concentrated Focus on Regions with Operational Control

The concentration of our operations in three domestic regions allows us to leverage our drilling unit and workforce synergies while minimizing the continued escalation of drilling and completion costs. Our average lease operating costs for continuing operations, excluding taxes, were $6.68, $5.29, and $4.87 per Boe in 2007, 2006, and 2005, respectively. Each of our three regions includes at least one anchor asset, previously termed a core area, and several diversity properties that are targeted for future growth. 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. The value of this concentration is enhanced by our operational control of 96% of our proved oil and natural gas reserves base as of December 31, 2007. 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 three domestic 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 15,900 Boe for the quarter ended December 31, 2007. We have also increased our proved reserves in the area from 7.7 million Boe to approximately 36.4 million Boe as of December 31, 2007. When we first acquired our interests in AWP Olmos, Brookeland, and Masters Creek, these areas also had significant additional development potential. In December 2004, we acquired our Bay de Chene and Cote Blanche Island fields which hold mainly proved undeveloped reserves and we began our initial development activities of these properties in 2006. In November 2005, we acquired our South Bearhead Creek field and then in October 2006, we acquired interests in five fields in South Louisiana which have significant development potential. In October 2007, we acquired interests in three South Texas properties in the Maverick Basin that total approximately 82,000 acres. These properties are located in the Sun TSH area in La Salle County, the Briscoe Ranch area primarily in Dimmitt County, and the Las Tiendas area in Webb County. 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 three domestic regions.

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, 2007, our debt to capitalization was approximately 41%, while our debt to domestic proved reserves ratio was $4.39 per Boe, and our debt to domestic PV-10 ratio was 15%. 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, and forward sales 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 and Technology Utilization

We employ 61 oil and gas professionals, including geophysicists, petrophysicists, geologists, petroleum engineers, and production and reservoir engineers, who have an average of approximately 24 years of experience in their technical fields and have been employed by us for an average of over five 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 increasingly use seismic technology to enhance the results of our drilling and production efforts, including two and three-dimensional seismic acquisition, pre-stack image enhancement reprocessing, amplitude versus offset datasets, coherency cubes, and detailed field reservoir depletion planning. In 2004, we completed our 3-D seismic survey covering our Lake Washington area. In 2007 we utilized this seismic data to drill all of our exploratory and development wells. In 2005, we began a seismic program that encompasses 77 square miles in our Cote Blanche Island area, which was completed in 2006 and have used this data to drill new wells in that area. We now have seismic data covering over 4,000 square miles in South Louisiana that has been merged into two data sets, inclusive of data covering five fields we acquired in 2006 that will form the base dataset for our regional exploration and development program. This data will be analyzed over the next several years, feeding our acquisition and organic growth led strategies.

We use various recovery techniques, including gas lift, water flooding, pressure maintenance, 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 also employ measurement-while-drilling techniques extensively in our South Louisiana region, 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.

Item 2. Properties

Domestic Operating Areas (Continuing Operations)

The following table sets forth information regarding our 2007 year-end proved reserves from continuing operations of 133.8 MMBoe and production of 10.6 MMBoe by area:

Area	Developed (MMBoe)	Undeveloped (MMBoe)	Total (MMBoe)	% of Domestic Reserves	% of Domestic Production	% Oil and NGLs
Lake Washington	18.5	17.9	36.4	27.2%	62.0%	92.1%
Bay de Chene	2.3	2.4	4.7	3.5%	5.7%	39.9%
Other South Louisiana	7.3	25.2	32.5	24.3%	9.1%	40.1%
Total South Louisiana	28.1	45.5	73.6	55.0%	76.8%	65.8%

AWP	16.3	6.1	22.4	16.8%	10.7%	29.1%
Cotulla	9.5	6.9	16.4	12.2%	2.8%	51.5%
Other South Texas	0.3	0.1	0.4	0.3%	0.8%	5.8%
Total South Texas	26.1	13.1	39.2	29.3%	14.3%	38.2%

Austin Chalk	4.7	7.9	12.6	9.4%	4.9%	64.3%
South Bearhead Creek	4.1	2.7	6.8	5.1%	3.3%	67.5%
Total Toledo Bend	8.8	10.6	19.4	14.5%	8.2%	65.4%

Total	63.0	69.2	132.2	98.8%	99.2%	57.6

Total Louisiana	34.6	53.5	88.1	65.9%	82.1%	66.2%
Total Texas	28.4	15.7	44.1	32.9%	17.1%	40.2%

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 and the acquisition of the Sun TSH, Briscoe Ranch, and Las Tiendas fields during 2007, which comprise our Cotulla area. 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, and adding five fields in 2006: Bayou Sale, Bayou Penchant, High Island, Horseshoe Bayou, and Jeanerette.

South Louisiana

Lake Washington Area. As of December 31, 2007, we owned drilling and production rights in 32,075 net acres in the Lake Washington area located in Plaquemines Parish in South Louisiana. Approximately 92% of our proved reserves of 36.4 MMBoe in this area at December 31, 2007, were oil and NGLs. To date, we have primarily produced from multiple Miocene sands ranging in depth from greater than 2,000 feet to 13,000 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 natural gas from approximately 141 producing wells and 35 shut-in wells is gathered to three platforms located in water depths from two to 12 feet, with drilling and workover operations performed with rigs on barges.

In 2007, we drilled 22 development wells, of which 18 wells were completed. At year-end 2007, we had 113 proved undeveloped locations in this field. Our planned 2008 capital expenditures in this area will focus on drilling from 23 to 27 wells, along with the construction of a facility on the west side of the field, which is expected to be commissioned in the first half of 2008, to further improve the deliverability and efficiency in this area.

Bay de Chene Area. Bay de Chene is located in Jefferson Parish and Lafourche Parish which is in South Louisiana in close proximity to Lake Washington. As of December 31, 2007, we owned drilling and production rights in 18,546 net acres in Bay de Chene, and successfully drilled two development wells in this field. At year-end 2007, we had seven proved undeveloped locations in the Bay de Chene field. During 2008, we plan to drill up to five wells in Bay de Chene. Production in the Bay de Chene area is currently constrained by the market capacity, and alternative outlets are being pursued by the Company.

Other South Louisiana Areas. Cote Blanche Island is in St. Mary Parish which is in South Louisiana. This field holds predominately undeveloped reserves. As of December 31, 2007, we owned drilling and production rights in 15,498 net acres in the Cote Blanche Island field, along with options covering another 8,817 acres. At year-end 2007, we had 25 proved undeveloped locations in the Cote Blanche Island field. During 2008, we plan to drill up to two wells in this area along with processing the 3-D seismic data covering this area that was shot in 2006. In October 2006, we acquired interests in five fields located in five primarily onshore South Louisiana fields: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), High Island Field in Cameron Parish and Bayou Penchant Field in Terrebonne Parish. Bayou Sale and Horseshoe Bayou fields are adjacent to each other and located 13 miles southeast of our Cote Blanche Island field. Production in these fields is from formations at depths ranging from 10,000 to 14,000 feet. The Bayou Penchant field was discovered in the 1930s and produces from a number of Middle Miocene sands at depths of 7,000 to 10,000 feet. Bayou Penchant is located approximately 44 miles southeast of Cote Blanche Island and is a non-operated field with Swift holding an average 50% working interest. The High Island field is located 65 miles west of Cote Blanche Island and was discovered in 1983. The Jeanerette field is positioned on the flank of a large salt dome and approximately 12 miles north of Cote Blanche Island. Jeanerette Field produces from the Planulina sands in the 10,000 feet to 15,000 feet depth range. We plan to initiate an exploration and development program in 2008 to drill proved undeveloped and probable locations, recomplete several wells, enhance facilities and improve per unit operating costs in these five fields. During 2008, we plan to drill up to five wells in these areas.

In 2007, we successfully drilled one well in the Bayou Sale field.

South Texas

AWP Olmos Area. As of December 31, 2007, we owned drilling and production rights in 29,107 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 71% natural gas. At year-end 2007, we owned interests in and operated 536 wells in this area producing oil and 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 these operated wells.

In 2007, we completed 21 development wells in this area and performed 16 fracture enhancements. At year-end 2007, we had 98 proved undeveloped locations. Our planned 2008 capital expenditures will focus on drilling 10 to 15 wells in this area.

Cotulla area. In October 2007, we acquired interests in three South Texas properties in the Maverick Basin. These properties are located in the Sun TSH area in La Salle County, the Briscoe Ranch area primarily in Dimmitt County, and the Las Tiendas area in Webb County.

As of December 31, 2007, we owned drilling and production rights in 81,986 net acres in the Cotulla area, owned interests in and operated 205 wells, and had 89 proved undeveloped locations. In 2007, we drilled seven development wells in this area, of which six were completed. Our planned 2008 capital expenditures will focus on drilling 30 to 36 wells in this area.

Toledo Bend

Brookeland Area. As of December 31, 2007, we owned drilling and production rights in 79,308 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. At year-end 2007, we had ten proved undeveloped locations.

Masters Creek Area. As of December 31, 2007, we owned drilling and production rights in 40,509 net acres and 91,534 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 natural gas from the Austin Chalk formation. The reserves are approximately 69% oil and NGLs. At year-end 2007, we had nine proved undeveloped locations. We plan on drilling one to two wells in the Austin chalk area in 2008.

South Bearhead Creek Area. In November and December 2005, and then in December 2006, 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 natural gas are produced in this area predominantly from the upper and lower Wilcox sands at depths ranging from approximately 10,600 to 14,100 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.

In 2007, we drilled 11 development wells in the area, all of which were successful. As of December 31, 2007, we owned drilling and production rights in 7,176 net acres in the South Bearhead Creek area. At year-end 2007, we had 18 proved undeveloped locations in this field. Our 2008 plans for this area include drilling up to four wells.

Domestic Dispositions. In April 2006, we sold our minority interest in the natural gas processing plant and related infrastructure that serves the Brookeland and the Masters Creek areas within our Toledo Bend region. In December 2006, we sold our interest in wells in the Garcia Ranch area within the South Texas region.

New Zealand Areas (Discontinued Operations)

In December 2007, Swift agreed to sell substantially all of our New Zealand assets for approximately $87.8 million. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. We began a strategic review of our New Zealand assets in the second quarter of 2007 which culminated in the agreement to sell the majority of these assets in the fourth quarter of 2007, with an expected closing towards the end of the first quarter of 2008. The remaining assets are expected to be sold in the later part of 2008. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility.

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 both domestically and in New Zealand as of December 31, 2007, 2006, and 2005. The information set forth in the tables regarding reserves is based on proved reserves reports prepared by us. H.J. Gruy and Associates, Inc., Houston, Texas, independent petroleum engineers, has audited 100% of our domestic proved reserves in each of the last three years and 100% of our New Zealand proved reserves for 2006 and 2005. The audit by H.J. Gruy and Associates, Inc. was conducted according to the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information approved by the Board of Directors of the Society of Petroleum Engineers, Inc. Based on its investigations, it is the judgment of H.J. Gruy and Associates, Inc. that Swift used appropriate engineering, geologic, and evaluation principles and methods that are consistent with practices generally accepted in the petroleum industry. Reserves estimates are based on extrapolation of established performance trends, material balance calculations, volumetric calculations, analogy with the performance of comparable wells, or a combination of these methods. The classification and definitions of all proved reserves estimates are in accordance with Rule 4-10 of Regulation S-X and the auditing process as described in the Society of Petroleum Engineers document Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the Society of Petroleum Engineers, a reserves audit should be of sufficient rigor to determine the appropriate reserve classification for all reserves in the property set evaluated and to clearly state the reserves classification system being utilized. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

Estimates of future net revenues from our proved reserves and their PV-10 Value are made using oil and natural gas sales prices in effect as of the dates of such estimates excluding 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 natural 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 2007 consisted of oil and natural gas price floors with strike prices lower than the period-end price and did not affect prices used in these calculations. The weighted averages of such year-end 2007 prices domestically were $6.65 per Mcf of natural gas, $93.24 per barrel of oil, and $56.28 per barrel of NGL, compared to $5.84, $60.07, and $31.54 at year-end 2006 and $10.36, $60.00, and $33.28 at year-end 2005, respectively. The weighted averages of such year-end 2007 prices for New Zealand were $3.08 per Mcf of natural gas, $93.20 per barrel of oil, and $36.98 per barrel of NGL, compared to $3.59, $63.51, and $26.84 in 2006 and $3.79, $60.98, and $19.20 in 2005, respectively. The weighted averages of such year-end 2007 prices for all our reserves, both domestically and in New Zealand, were $6.19 per Mcf of natural gas, $93.24 per barrel of oil, and $54.63 per barrel of NGL, compared to $5.46, $60.41, and $30.93 in 2006 and $8.94, $60.12, and $31.40 in 2005, 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 SEC and their PV-10 Value as of December 31, 2007, 2006, and 2005. 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 NGL volumes with oil volumes solely for reserves volumes reporting purposes. We apply oil prices to proved oil reserves volumes and apply NGL prices to proved NGL reserves volumes in determining both the PV-10 and standardized measure values. 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, 2007
	Total		Domestic		Discontinued Operations
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed		187,152		172,974		14,178
Proved undeveloped		206,862		170,824		36,038
Total		394,014		343,798		50,216
Oil reserves (MBbl):
Proved developed		36,753		35,548		1,205
Proved undeveloped		47,702		40,934		6,768
Total		84,455		76,482		7,973

Total Estimated Reserves (MBoe)		150,124		133,781		16,343

Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed	$	2,071	$	1,999	$	73
Proved undeveloped		1,823		1,790		32
PV-10 Value	$	3,894	$	3,789	$	105

	As of December 31, 2006
	Total		Domestic		Discontinued Operations
Estimated Proved Oil and Natural Gas Reserves
Natural gas reserves (MMcf):
Proved developed		151,276		133,815		17,462
Proved undeveloped		172,855		135,846		37,009
Total		324,131		269,661		54,471
Oil reserves (MBbl):
Proved developed		34,956		33,346		1,611
Proved undeveloped		47,163		40,119		7,044
Total		82,119		73,465		8,655

Total Estimated Reserves (MBoe)		136,141		118,408		17,733

Estimated Discounted Present Value of Proved Reserves (In millions)
Proved developed	$	1,382	$	1,307	$	75
Proved undeveloped		1,326		1,137		189
PV-10 Value	$	2,708	$	2,444	$	264

	As of December 31, 2005
	Total		Domestic		Discontinued Operations
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 (MBoe)		126,965		107,329		19,636

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

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 natural 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 natural 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 natural 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 natural gas reserves.

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 natural 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, 2007
	Total			Domestic			Discontinued Operations
(In millions)
PV-10 Value	$	3,894		$	3,789		$	105

Future income taxes (discounted at 10%)		(1,212	)		(1,211	)		(1	)
Asset retirement obligations (discounted at 10%)		(46	)		(38	)		(8	)

Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves	$	2,636		$	2,540		$	96

	As of December 31, 2006
	Total			Domestic			Discontinued Operations
(In millions)
PV-10 Value	$	2,708		$	2,444		$	264

Future income taxes (discounted at 10%)		(800	)		(778	)		(22	)
Asset retirement obligations (discounted at 10%)		(39	)		(34	)		(5	)

Standardized Measure of Discounted Future Net Cash Flows relating to oil and natural gas reserves	$	1,869		$	1,632		$	237

	As of December 31, 2005
	Total			Domestic			Discontinued Operations
(In millions)
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 natural gas reserves	$	2,159		$	1,895		$	265

Domestic Proved Undeveloped Reserves

The following table sets forth the aging and PV-10 value of our domestic proved undeveloped reserves as of December 31, 2007:

Year Added	Volume (MMBoe)	% of PUD Volumes	PV-10 Value (in millions)	% of PUD PV-10 Value
2007	17.1	25%	$351.1	20%
2006	13.5	19%	372.5	21%
2005	12.6	18%	410.9	23%
2004	11.9	17%	339.1	19%
2003	2.9	4%	111.3	6%
Prior to 2003	11.4	17%	205.3	11%
Total	69.4	100%	$1, 790.2	100%

Sensitivity of Domestic Reserves to Pricing

As of December 31, 2007, a 5% increase in oil and NGL pricing would increase our total estimated domestic proved reserves of 133.8 MMBoe by approximately 0.1 MMBoe, and increase the domestic PV-10 Value of $3.8 billion by approximately $186 million. Similarly, a 5% decrease in oil and NGL pricing would decrease our total estimated domestic proved reserves by approximately 0.1 MMBoe and decrease the domestic PV-10 Value by approximately $186 million.

As of December 31, 2007 a 5% increase in natural gas pricing would increase our total estimated domestic proved reserves by approximately 0.1 MMBoe and increase the domestic PV-10 Value by approximately $59 million. Similarly, a 5% decrease in natural gas pricing would decrease our total estimated domestic proved reserves by approximately 0.1 MMBoe and decrease the domestic PV-10 Value by approximately $59 million.

Oil and Gas Wells

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

	Oil Wells	Gas Wells	Total Wells(1)(2)
December 31, 2007:
Gross	504	761	1,265
Net	437.4	719.9	1,157.3
December 31, 2006:
Gross	423	662	1,085
Net	353.4	562.4	915.8
December 31, 2005:
Gross	402	565	967
Net	324.8	497.5	822.3

(1)	Excludes 65 service wells in 2007, 51 service wells in 2006, and 49 service wells in 2005.

(2)	Includes 49 wells in New Zealand in both 2007 and 2006, and 45 wells in 2005.

Oil and Gas Acreage

The following table sets forth the developed and undeveloped leasehold acreage held by us at December 31, 2007:

	Developed(1)		Undeveloped(1)
	Gross	Net	Gross	Net
Alabama	9,629	2,600	81	80
Alaska	---	---	41,194	14,017
Louisiana	123,917	106,456	57,306	52,180
Texas	145,002	105,400	82,942	78,152
Wyoming	640	151	27,711	25,916
All other states	320	267	400	258
Offshore Louisiana	4,609	277	5,000	258
Total Domestic	284,117	215,151	214,634	170,861
New Zealand	9,960	9,912	580,169	310,354
Total	294,077	225,063	794,803	481,215

(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 68,689 undeveloped fee mineral acres for a total of 95,034 fee mineral acres.

Drilling Activities

The following table sets forth the results of our drilling activities during the three years ended December 31, 2007:

		Gross Wells			Net Wells
Year	Type of Well	Total	Producing	Dry	Total	Producing	Dry
2007	Exploratory — Domestic	5	2	3	5.0	2.0	3.0
	Development — Domestic	64	59	5	62.6	58.1	4.5
	Exploratory — New Zealand	—	—	—	—	—	—
	Development — New Zealand	—	—	—	—	—	—

2006	Exploratory — Domestic	6	—	6	5.5	—	5.5
	Development — Domestic	49	42	7	47.6	40.6	7.0
	Exploratory — New Zealand	4	—	4	4.0	—	4.0
	Development — New Zealand	4	3	1	4.0	3.0	1.0

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

Operations

We generally seek to be the operator of 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 natural gas properties.

Oil and natural 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 2007 totaled $11.8 million and ranged from $500 to $2,495 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. In 2007 and 2006, several companies accounted for 10% or more of our total revenues. Shell Oil Company and its affiliates, both domestically and in New Zealand, accounted for approximately 42% and 30% of our total oil and gas sales in 2007 and 2006, respectively. In 2007 and 2006, Chevron and its domestic affiliates accounted for 22% and 32% of our total oil and gas sales, respectively. However, due to the demand for oil and natural gas and availability of other purchasers, we do not believe that the loss of any single oil or natural 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. Natural gas delivered into Tennessee Gas Pipeline is processed at the Yscloskey plant. In the first half of 2008, we plan to complete a connection which will also provide for the delivery of natural gas from this area to El Paso’s Southern Natural Gas pipeline system.

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. Discussions regarding replacement gas processing and gas transportation agreements are ongoing with Enterprise and other providers of such services in the area.

In the Toledo Bend area, our oil production from the Brookeland, Masters Creek and South Bearhead Creek areas is sold to various purchasers at prevailing market prices. Our natural gas production from the Brookeland and Masters Creek areas is processed under long term gas processing contracts with Eagle Rock Operating, LLC. The processed liquids and residue gas production are sold in the spot market at prevailing prices. South Bearhead Creek natural gas production is sold into the interstate market on Trunkline Gas Company’s pipeline at prevailing market prices.

Our oil production from the Bay de Chene and Cote Blanche Island fields is transported on barges for sales to various purchasers at prevailing market prices. Natural gas production from both fields is sold into intrastate pipelines with prices tied to monthly and daily natural gas price indices.

In the fields of Bayou Sale, Horseshoe Bayou, High Island and Jeanerette in South Louisiana, we market our own production and sell the oil production to various purchasers at prevailing market prices. Bayou Sale and Horseshoe Bayou oil production is delivered into Plains All-American pipeline. Oil production from High Island and Jeanerette fields is transported to market by truck. Natural gas production for each of these fields is sold into one or more interstate pipelines at prevailing market prices.

In the newly acquired Cotulla area, our oil production is sold at prevailing market prices and transported to market by truck. Natural gas from the fields is delivered either to Enterprise South Texas Gathering or Regency Gas Services. For natural gas delivered to Enterprise, the natural gas is sold to Enterprise; with Swift receiving revenues from residue gas sales and processed liquids. For natural gas delivered to Regency, the natural gas production is transported to a downstream processing plant. We sell the residue gas at prevailing market prices and receive processing revenues from Regency.

The following table summarizes domestic sales volumes, sales prices, and production cost information for our net oil and natural gas production from our continuing operations for the three-year period ended December 31, 2007:

	Year Ended December 31,
	2007	2006	2005
Domestic Net Sales Volume:
Oil (MBbls)	7,045	6,721	4,709
Natural Gas Liquids (MBbls)	774	460	508
Natural gas (MMcf)	16,782	13,604	11,739
Total (MBoe)	10,617	9,449	7,174

Domestic Average Sales Price:
Oil (Per Bbl)	$71.92	$64.28	$53.45
Natural Gas Liquids (Per Bbl)	$49.72	$38.70	$34.00
Natural gas (Per Mcf)	$6.42	$6.44	$7.40

Average Production Cost (Per Boe)	$13.63	$11.77	$10.14

Our New Zealand production and pricing information is included in the Discontinued Operations discussion within the Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this Form 10-K. The prices above do not include the effects of hedging. The hedge adjusted prices are detailed in the "Management's Discussion and Analysis of Financial Condidtion and Results of Operations" section of this Form 10-K.

Risk Management

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural 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 natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil spills, natural 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 business interruption 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 natural gas prices, mainly through the purchase of price floors and participating collars. At December 31, 2007, we had price floors in place through the March 2008 contract month for oil and natural gas; these cover a portion of our domestic oil and natural gas production for January 2008 through March 2008. The oil floors cover notional volumes of 639,000 barrels, with a weighted average floor price of $71.22 per barrel, and the natural gas price floors cover notional volumes of 1,330,000 MMBtu, with a weighted average floor price of $6.90 per MMBtu. Our oil price floors in place at December 31, 2007 are expected to cover approximately 40% to 45% of our domestic oil production during the first quarter of 2008, and our natural gas price floors in place at December 31, 2007 are expected to cover approximately 40% to 45% of our domestic natural gas production from February 2008 to March 2008.

Competition

We operate in a highly competitive environment, competing with major integrated and independent energy companies for desirable oil and natural 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 natural 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 and acquisition.

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 natural 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 discontinued 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.

The Energy Independence and Security Act of 2007 became law on December 19, 2007. Among other provisions, the Act promotes research and development of biofuels and biofuels infrastructure, supports research and development in solar, geothermal, marine and hydrokinetic energy, energy storage and carbon capture and sequestration; and contains certain revenue raising provisions. The Act does not repeal certain tax incentives for expenditures by companies engaged in the exploration and production of oil and natural gas, nor does it impose new excise taxes specifically on certain companies engaged in the exploration and production of oil and natural gas, both of which had been proposed in earlier versions of the legislation. As a result of this new legislation, in 2008 Congress may decide to revisit legislation to repeal existing incentives or impose new taxes on the exploration and production of oil and natural gas, and/or create new incentives for alternative energy sources. If enacted, such legislation could reduce the demand for and uses of oil, natural gas and other minerals and/or increase the costs incurred by the Company in its exploration and production activities, which could affect the Company’s revenues and profits.

Production of any oil and natural 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 natural gas, including provisions regarding deliverability. Such statutes, and the regulations promulgated in connection therewith, are generally intended to prevent waste of oil and natural gas and to protect correlative rights to produce oil and natural gas between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and natural gas produced by assigning allowable rates of production to each well or proration unit, which could restrict the rate of production below the 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 natural 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 natural 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, 2007, we employed 360 persons. Of these employees, 62 were in New Zealand, including two expatriate employees. Eleven 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. Upon closing of the sale of our New Zealand assets; we will have no employees in New Zealand other than expatriate employees.

Facilities

At December 31, 2007, we occupied approximately 126,000 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 $243,000 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 $27,000 per month and the purchaser of the majority of our New Zealand assets has agreed to assume these leases upon closing of the asset sale. We also have field offices in various locations from which our employees supervise local oil and natural 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.”

Approximately 55% of our 2007 reserves and 77% of our 2007 production are located in our South Louisiana region. If that area is hit by a hurricane or we have a pipeline outage, it could cause us to suffer significant losses.

Increased hurricane activity over the past three years has resulted in production curtailments and physical damage to our Gulf Coast operations. For example, in 2005, a significant percentage of our production was shut down by Hurricanes Katrina and Rita. Unlike in 2005, however, due to increased costs, we no longer carry business interruption insurance. If hurricanes damage the Gulf Coast region where we have a significant percentage of our operations, our cash flow would suffer. This decrease in cash flow, depending on the extent of the decrease, could reduce the funds we would have available for capital expenditures and reduce our ability to borrow money or raise additional capital.

Our oil and natural 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. 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, such as business interruption, 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.

As of December 31, 2007, our total debt comprised approximately 41% 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. Higher levels of indebtedness could negatively affect us by requiring us to dedicate a substantial portion of our cash flow to the payment of interest, and limiting our ability to obtain financing or raise equity capital in the future.

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, 2007, approximately 52% of our estimated domestic 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 natural 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 natural 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, as is the case in our declining business interruption insurance following the hurricanes in 2005. 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 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 natural 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 as 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.

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

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

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 natural 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 and Texas, 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 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 natural 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, although we typically enter into only short-term hedges covering less than 50% of our anticipated production, which limits the price protection they provide. Our hedges at year-end 2007 consisted of oil and natural gas price floors with strike prices lower than the period end prices. Our hedging transactions have also historically 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 natural 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 natural 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.

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

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.

Fluctuations in rates between the New Zealand dollar and U.S. dollar impact our financial results from our discontinued New Zealand operations since we have receivables, liabilities, and natural gas and NGL sales contracts denominated in New Zealand dollars. New Zealand income taxes are also computed in New Zealand dollars. We do not hedge against the risks associated with fluctuations in exchange rates.

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. 1

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. 2

FASB — The Financial Accounting Standards Board.

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.

MBoe — Thousand barrels of oil equivalent.

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.

MMBoe — Million barrels of oil equivalent.

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. 3

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. 4

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. 5

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.

SFAS — Statement of Financial Accounting Standards.

Notes to Abbreviations and Terms Above

1 This is only an abbreviated definition. Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(11) of Regulation S-X.

2 This is only an abbreviated definition. Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(10) of Regulation S-X.

3 This is only an abbreviated definition. Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(3) of Regulation S-X.

4 This is only an abbreviated definition. Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(2) of Regulation S-X.

5 This is only an abbreviated definition. Please refer to Securities and Exchange Commission’s definition of this term at Rule 4-10(a)(4) of Regulation S-X.

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 2007 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, 2006 and 2007

Our common stock is traded on the New York Stock Exchange under the symbol “SFY.” The high and low quarterly closing sales prices for the common stock for 2006 and 2007 were as follows:

	2006				2007
	First Quarter	Second Quarter	Third Quarter	Fourth Quarter	First Quarter	Second Quarter	Third Quarter	Fourth Quarter
Low	$35.48	$35.61	$40.06	$39.10	$37.37	$39.09	$35.98	$39.89
High	$49.50	$45.22	$48.00	$51.84	$44.91	$45.78	$47.31	$47.72

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 231 stockholders of record as of December 31, 2007.

Share Performance Graph

The following Share Performance Graph shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing.

Item 6. Selected Financial Data

(In thousands except per share and well amounts)	2007		2006		2005		2004		2003

Total Revenues from Continuing Operations (1)	$	654,121	$	550,836	$	354,365	$	257,313	$	161,092

Income from Continuing Operations, Before Income
Taxes and Change in Accounting Principle (1)	$	244,556	$	248,308	$	156,129	$	86,083	$	37,688

Income from Continuing Operations (1)	$	152,588	$	151,074	$	97,880	$	54,340	$	22,396

Net Cash Provided by Operating Activities -
Continuing Operations	$	442,282	$	383,241	$	236,791	$	147,114	$	81,376

Per Share and Share Data
Weighted Average Shares Outstanding(1)		29,984		29,265		28,496		27,822		27,358
Earnings per Share--Basic(1)	$	5.09	$	5.16	$	3.43	$	1.95	$	0.82
Earnings per Share--Diluted(1)	$	4.98	$	5.03	$	3.34	$	1.92	$	0.81
Shares Outstanding at Year-End		30,179		29,743		29,010		28,090		27,484
Book Value per Share at Year-End	$	27.70	$	26.83	$	20.94	$	16.88	$	14.46
Market Price
High	$	47.72	$	51.84	$	50.01	$	30.34	$	18.00
Low	$	35.98	$	35.48	$	24.77	$	15.90	$	7.60
Year-End Close	$	44.03	$	44.81	$	45.07	$	28.94	$	16.85

Effect on Income from Continuing Operations and
Earnings per Share From Changes in Accounting
Principles (2)
Cumulative Effect of Change in Accounting
Principle (Net of Taxes)		---		---		---		---	$	(4,145	)
Effect per Share—Basic		---		---		---		---	$	(0.15	)
Effect per Share—Diluted		---		---		---		---	$	(0.15	)

Assets
Current Assets	$	199,950	$	83,783	$	110,199	$	51,694	$	31,398
Property & Equipment, Net of Accumulated
Depreciation, Depletion, and Amortization	$	1,760,195	$	1,239,722	$	862,717	$	731,868	$	641,366
Total Assets	$	1,969,051	$	1,585,682	$	1,204,413	$	990,573	$	859,839

Liabilities
Current Liabilities	$	210,161	$	145,471	$	98,421	$	68,618	$	69,353
Long-Term Debt	$	587,000	$	381,400	$	350,000	$	357,500	$	340,255
Total Liabilities	$	1,132,997	$	787,765	$	597,094	$	516,401	$	462,447

Stockholders’ Equity	$	836,054	$	797,917	$	607,318	$	474,172	$	397,391

Number of Domestic Employees		298		272		236		203		183

Domestic Producing Wells
Swift Operated		1,091		926		854		798		820
Outside Operated		127		112		69		97		113
Domestic Producing Wells		1,218		1,038		923		895		933

Domestic Wells Drilled (Gross)		69		55		54		54		71

Domestic Proved Reserves
Natural Gas (Bcf)		343.8		269.7		225.3		237.9		242.3
Oil, NGL, & Condensate (MMBbls)		76.5		73.5		69.8		69.1		67.0
Total Domestic Proved Reserves (MMBoe equivalent)		133.8		118.4		107.3		108.8		107.4

Domestic Production (MMBoe equivalent)		10.6		9.4		7.2		7.0		5.6

Domestic Average Sales Price (3)
Natural Gas (per Mcf)	$	6.42	$	6.44	$	7.40	$	5.74	$	5.07
Natural Gas Liquids (per barrel)	$	49.72	$	38.70	$	34.00	$	24.84	$	19.75
Oil (per barrel)	$	71.92	$	64.28	$	53.45	$	40.04	$	29.95
Boe Equivalent	$	61.49	$	56,89	$	49.61	$	36.90	$	29.17

(1) Amounts have been retroactively adjusted in all periods presented to give recognition to: (a) discontinued operations related to the pending sale of our New Zealand oil & gas assets, and (b) the conversion of production and reserves volumes to a Boe basis.

(2) We adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” on January 1, 2003.

(3) These prices do not include the effects of our hedging activities which were immaterial and recorded in “Price-risk management and other, net” on the accompanying statements of income. The hedge adjusted prices are detailed in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of this Form 10-K.

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, 2007, 2006, and 2005 included with this report. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 42 of this report.

Overview

We are an independent oil and natural gas company formed in 1979, and we are engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from the inland waters of Louisiana and from our onshore Louisiana and Texas properties.

We are the largest producer of oil in the state of Louisiana, and due to increasing emphasis on our South Louisiana operations, we have become predominantly an oil producer, with oil constituting 66% of our 2007 domestic production, and oil and natural gas liquids (“NGLs”) together making up 74% of our 2007 domestic production. This emphasis has allowed us to benefit from better margins for oil production than natural gas production in recent periods.

In December 2007, we agreed to sell substantially all of our New Zealand assets to Origin Energy Limited for a minimum of $87.8 million, with an expected closing towards the end of the first quarter of 2008. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. The pending sale of these assets resulted in a fourth quarter 2007 non-cash charge of approximately $131 million (net of tax effects) based on the selling price and terms of the sales agreement. We expect to realize total cash proceeds of between $100 and $110 million from the sale of all of our New Zealand assets, which we anticipate completing later this year. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility.

Unless otherwise noted, both historical information for all periods and forward-looking information provided in this Management’s Discussion and Analysis relates solely to our continuing operations located in the United States, and excludes our discontinued New Zealand operations.

In our 2007 continuing operations we had record income, cash flows, and production. Income from continuing operations increased 1% to $152.6 million and cash flows from operating activities from continuing operations increased 15% to $442.3 million, in each case compared to 2006 amounts. Production increased 12% to 10.6 MMBoe, due to increased production in our South Louisiana, Toledo Bend, and South Texas regions. We ended 2007 with domestic proved reserves of 133.8 MMBoe, an increase of 13% over year-end 2006 domestic reserves. We also had record revenues of $654.1 million for 2007, an increase of 19% over comparable 2006 levels. Our weighted average sales price received increased 8% to $61.49 per Boe for 2007 from $56.89 in 2006. Our $115.3 million, or 21%, increase in oil and gas sales revenues primarily resulted from both a 1.2 million Boe increase in production volumes and from 12% higher oil prices during 2007.

In October 2007, we acquired interests in three South Texas fields in the Maverick Basin from Escondido Resources, LP, which we collectively identify as the Cotulla properties. The total price for these interests was approximately $248.2 million after purchase price adjustments. The 12.9 MMBoe of proved reserves added through this acquisition are located in the Sun TSH field in La Salle County, the Briscoe Ranch field primarily in Dimmit County, and the Las Tiendas field in Webb County, of which 42% were proved undeveloped and which are predominantly natural gas and natural gas liquids. These properties added 0.3 MMBoe of production to our total production quantities for 2007. We plan to acquire more producing acreage in this area as well, and maintain a two rig drilling program in this area into 2008.

Our overall costs and expenses increased in 2007 by 35%. In 2008, we will continue to focus upon our capital efficiency to better manage our costs and expenses, a difficult task in the inflationary cost environment prevalent in the industry over the last several years. The largest increase in these costs and expenses in 2007 was attributable to 35% higher depreciation, depletion and amortization expense, not only due to our larger depletable property base and higher production, but also due to increases in future development costs, which reflect industry cost inflation. We expect cost pressures to continue to affect the industry throughout 2008, with tightening availability of crews as well as increasing costs of services, goods, and basic equipment.

Lake Washington is our most significant field, and provides approximately 62% of our domestic production, and in the fourth quarter of 2007, our production fell 13% from third quarter 2007 levels. In the fourth quarter of 2007, along with experiencing natural declines in production as our wells mature, we reduced the choke size of several wells in the Newport area to preserve reservoir pressure in anticipation of the pressure maintenance program that will commence with the Westside facility start-up by mid 2008. We continue to drill deeper wells, higher flowing pressure wells, and wells with higher associated natural gas content, and our system must also handle more mature wells that may produce larger volumes of water that require artificial lift. We believe the pressure maintenance activities planned for 2008 and Westside facility start-up by mid 2008 will improve the majority of these production constraints.

Our year-end 2007 domestic proved reserves were 44% crude oil, 43% natural gas, and 13% NGLs, compared to 52% crude oil, 38% natural gas, and 10% NGLs a year earlier, with 48% of our domestic proved reserves were proved developed at December 31, 2007. Our 2007 domestic production was 66% crude oil, down from 71% in 2006. Domestic proved reserves increased to 133.8 MMBoe at year-end 2007 from 118.4 MMBoe at year-end 2006.

Our financial position remains strong even with our recent increase in debt levels during the fourth quarter of 2007. Our debt to capitalization ratio was 41% at December 31, 2007, compared to 32% at year-end 2006, as debt levels increased in 2007, with debt per domestic Boe of $4.39 at year-end 2007 a 36% increase compared to $3.22 a year earlier. Our debt to domestic PV-10 ratio decreased to 15% at December 31, 2007 from 16% compared to a year earlier, as higher year-end reserves volumes and prices were largely offset by increased borrowings against our line of credit at that date.

Our capital expenditures from continuing operations of $650.6 million increased by $162.4 million from 2006 to 2007, primarily due to our acquisition of the Cotulla properties in South Texas and the increase in our spending on drilling and development, predominantly in our South Louisiana region. These expenditures were primarily funded by $442.3 million of cash provided by operating activities from continuing operations, and an increase in debt levels of $205.6 million.

Our current 2008 capital expenditure budget is $425 million to $475 million, net of minor non-core dispositions and excluding any property acquisitions. Based upon current market conditions and our estimates, our capital expenditures for 2008 should be within our anticipated cash flow from operations and currently have budgeted approximately two-thirds of these amounts for our South Louisiana region, and on an overall basis three-fourths for developmental activities. For 2008, we are targeting production from our continuing operations to increase 10% to 15% and domestic proved reserves to increase 5% to 9% both over 2007 levels. We may also increase our capital expenditure budget if commodity prices rise during the year or if strategic opportunities warrant. If 2008 capital expenditures exceed our cash flow from operating activities, we can fund these expenditures with our credit facility.

During 2008, we plan to further develop our inventory of properties in South Louisiana using our expertise and experience gained in expanding and producing in Lake Washington, together with significant 3-D seismic information, to exploit our other prospect areas covered by similar geological features. This broad prospect inventory will allow us to be selective in choosing drilling opportunities so we can create long-life reserves while at the same time raising our production.

Results of Continuing Operations — Years Ended 2007, 2006, and 2005

Revenues. Our revenues in 2007 increased by 19% compared to revenues in 2006 primarily due to increased production from our South Louisiana region and higher oil prices, and our revenues in 2006 increased by 55% compared to 2005 revenues due to increases in oil production from our South Louisiana area and increases in oil prices. Revenues for 2007, 2006, and 2005 were substantially comprised of oil and gas sales. Crude oil production was 66% of our production volumes in 2007, 71% in 2006, and 66% in 2005. Natural gas production was 26% of our production volumes in 2007, 24% in 2006, and 27% in 2005.

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, 2007, 2006, and 2005:

Regions	Oil and Gas Sales (In Millions)			Net Oil and Gas Sales Volumes (MBoe)
	2007	2006	2005	2007	2006	2005
South Texas	$72.0	$61.8	$73.2	1,517	1,438	1,510
Toledo Bend	48.7	35.1	38.9	872	745	895
South Louisiana	527.2	434.7	236.6	8,139	7,138	4,611
Other	5.0	5.9	7.2	89 89	128	158
Total	$652.9	$537.5	$355.9	10,617	9,449	7,174

Oil and gas sales in 2007 increased by 21%, or $115.3 million, from the level of those revenues for 2006, and our net sales volumes in 2007 increased by 12%, or 1.2 MMBoe, over net sales volumes in 2006. Average prices for oil increased to $71.92 per Bbl in 2007 from $64.28 per Bbl in 2006. Average natural gas prices were virtually unchanged at $6.42 per Mcf in 2007 compared to $6.44 per Mcf in 2006. Average NGL prices increased to $49.72 per Bbl in 2007 from $38.70 per Bbl in 2006.

In 2007, our $115.3 million increase in oil, NGL, and natural gas sales resulted from:

•

Volume variances that had a $53.5 million favorable impact on sales, with $20.9 million of increases attributable to the 0.3 million Bbl increase in oil sales volumes, $12.1 million due to the 0.3 million Bbl increase in NGL sales volumes, and $20.5 million due to the 3.2 Bcf increase in natural gas sales volumes; and

•

Price variances that had a $61.8 million favorable impact on sales, of which $53.8 million was attributable to the 12% increase in average oil prices received, and $8.5 million was attributable to the 28% increase in NGL prices, partially offset by a decrease of $0.5 million attributable to the $0.02 per Mcf decrease in natural gas prices.

Oil and gas sales in 2006 increased by 51%, or $181.6 million, from the level of those revenues for 2005, and our net sales volumes in 2006 increased by 32%, or 2.3 MMBoe, over net sales volumes in 2005. Average prices for oil increased to $64.28 per Bbl in 2006 from $53.45 per Bbl in 2005. Average natural gas prices decreased to $6.44 per Mcf in 2006 from $7.40 per Mcf in 2005. Average NGL prices increased to $38.70 per Bbl in 2006 from $34.00 per Bbl in 2005.

In 2006, our $181.6 million increase in oil, NGL, and natural gas sales resulted from:

•

Volume variances that had a $119.7 million favorable impact on sales, with $107.5 million of increases attributable to the 2.0 million Bbl increase in oil sales volumes, and $13.8 million due to the 1.9 Bcf increase in natural gas sales volumes, partially offset by a decrease of $1.6 million due to the 48,000 Bbl decrease in NGL sales volumes; and

•

Price variances that had a $61.9 million favorable impact on sales, of which $72.8 million was attributable to the 20% increase in average oil prices received, $2.2 million was attributable to the 14% increase in NGL prices, slightly offset by a decrease of $13.1 million attributable to the 13% decrease in natural gas prices.

The following table provides additional information regarding our quarterly oil and gas sales from continuing operations excluding any effects of our hedging activities:

	Sales Volume				Average Sales Price
	Oil	NGL	Gas	Combined	Oil	NGL	Natural Gas
	(MBbl)	(MBbl)	(Bcf)	(MBoe)	(Bbl)	(Bbl)	(Mcf)
2005:
First	1,184	143	3.0	1,831	$47.20	$31.79	$5.41
Second	1,339	118	3.2	1,992	$50.21	$25.74	$6.13
Third	925	119	2.8	1,519	$59.44	$40.58	$7.68
Fourth	1,261	128	2.7	1,832	$58.36	$37.99	$10.89
Total	4,709	508	11.7	7,174	$53.45	$34.00	$ 7.40
2006:
First	1,487	90	3.3	2,127	$60.56	$39.75	$7.42
Second	1,554	70	3.4	2,184	$69.40	$40.85	$6.12
Third	1,825	159	3.3	2,537	$69.54	$42.37	$6.07
Fourth	1,855	141	3.6	2,601	$57.82	$32.82	$6.20
Total	6,721	460	13.6	9,449	$64.28	$38.70	$6.44
2007:
First	1,773	133	3.8	2,534	$57.87	$39.90	$5.92
Second	1,872	134	3.5	2,589	$66.20	$44.22	$7.56
Third	1,783	190	4.4	2,702	$76.20	$48.89	$5.68
Fourth	1,617	317	5.1	2,792	$89.23	$56.65	$6.62
Total	7,045	774	16.8	10,617	$71.92	$49.72	$6.42

During 2007, 2006, and 2005, we recognized net gains of $0.2 million and $4.0 million, and net losses of $1.1 million, respectively, related to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. Had these gains and losses been recognized in the oil and gas sales account, our average oil sales price would have been $71.91, $64.58, and $53.42 for 2007, 2006, and 2005, respectively, and our average natural gas sales price would have been $6.43, $6.59, and $7.32 for 2007, 2006, and 2005, respectively.

In 2006, we settled all insurance claims with our insurers relating to hurricanes Katrina and Rita for approximately $30.5 million and entered into a confidential final settlement agreement. The receipt of these amounts resulted in a benefit of $7.7 million in 2006 recorded in “Price-risk management and other, net,” for the portion of the above referenced settlement, which we have determined to be non-property damage related claims. Approximately $22.8 million of the above referenced settlement was determined to be property damage related claims. We recorded $14.1 million of the property related settlement as a reduction to “Proved properties” on the accompanying consolidated balance sheet, as this related to reimbursement of capital costs we incurred. We also recorded $8.7 million of the property related settlement as a reduction to “Lease operating cost” on the accompanying consolidated statement of income, as this related to reimbursement of repair costs which had been expensed as incurred. In the accompanying consolidated statement of cash flows, we have recorded the reimbursement which reduced “Proved properties” as a reduction of “Cash Used in Investing Activities – continuing operations” and the remainder of the insurance settlement was recorded as an increase to “Cash Provided by Operating Activities - continuing operations.”

Costs and Expenses. Our expenses in 2007 increased $107.0 million, or 35%, compared to 2006 expenses for the reasons noted below.

Our 2007 general and administrative expenses, net, increased $6.5 million, or 24%, from the level of such expenses in 2006, while 2006 general and administrative expenses, net, increased $8.8 million, or 46%, over 2005 levels. The increases in both 2007 and 2006 were primarily due to increased salaries and burdens associated with our expanded workforce, but were also impacted by increased restricted stock grants each year and the expensing of stock options which began in 2006. Costs also increased in 2007 due to ongoing support costs of our new computer system implemented in 2007. For the years 2007, 2006, and 2005, our capitalized general and administrative costs totaled $26.4 million, $24.1 million, and $14.5 million, respectively. Our net general and administrative expenses per Boe produced increased to $3.22 per Boe in 2007 from $2.92 per Boe in 2006 and $2.63 per Boe in 2005. The portion of supervision fees recorded as a reduction to general and administrative expenses was $11.8 million for 2007, $8.7 million for 2006, and $7.4 million for 2005.

DD&A increased $49.1 million, or 35%, in 2007, from 2006 levels and increased $58.1 million, or 72%, from 2005 levels. The increases in both years are due to increases in the depletable oil and natural gas property base, including future development costs, and higher production, partially offset by higher reserves volumes. Industry costs for services and goods have increased over the last three year period and have contributed to the increase in our DD&A expense. Our DD&A rate per Boe of production was $17.74 in 2007, $14.74 in 2006, and $11.31 in 2005, resulting from increases in per unit cost of reserves additions.

We recorded $1.4 million, $0.9 million, and $0.6 million of accretions to our asset retirement obligation in 2007, 2006, and 2005, respectively.

Our lease operating costs increased $20.9 million, or 42%, over the level of such expenses in 2006, while 2006 costs increased $15.0 million, or 43% over 2005 levels. Lease operating costs increased during 2007 and 2006 due to higher production from our three domestic regions, including costs from properties acquired in the fourth quarters of 2006 and 2007, increasing costs for industry goods and services, and higher natural gas and NGL processing costs in 2007. A portion of the increase in 2007 and 2006 was from increased well insurance premiums which increased after hurricanes Katrina and Rita. Our lease operating costs per Boe produced were $6.68, $5.29, and $4.87 in 2007, 2006, and 2005, respectively.

Severance and other taxes increased $12.6 million, or 21%, over 2006 levels, while in 2006 these taxes increased $23.4 million, or 62% over 2005 levels. The increases in each year were due primarily to higher commodity prices and increased production in our three domestic regions. Severance and other taxes, as a percentage of oil and gas sales, were approximately 11.3%, 11.4% and 10.6% in 2007, 2006 and 2005, respectively. Severance taxes on oil in Louisiana are 12.5% of oil sales, which is higher than in the other states where we have production. As our percentage of oil production in Louisiana increased in 2006, the overall percentage of severance costs to sales also increased.

Our total interest cost in 2007 was $37.6 million, of which $9.5 million was capitalized. Our total interest cost in 2006 was $32.8 million, of which $9.2 million was capitalized. Our total interest cost in 2005 was $32.1 million, of which $7.2 million was capitalized. Interest expense on our 7-5/8% senior notes due 2011 issued in June 2004, including amortization of debt issuance costs, totaled $12.0 million in 2007 and $11.9 million in both 2006 and 2005. Interest expense on our 9-3/8% senior subordinated notes due 2012 issued in April 2002 and retired in 2007, including amortization of debt issuance costs, totaled $8.9 million in 2007 and $19.2 million in both 2006 and 2005. Interest expense on our 7-1/8% senior notes due 2017 and issued in June 2007, including amortization of debt issuance costs, totaled $10.6 million in 2007. Interest expense on our bank credit facility, including commitment fees and amortization of debt issuance costs, totaled $6.1 million in 2007, $1.5 million in 2006, and $1.0 million in 2005. Other interest cost was $0.1 million in each of 2007, 2006 and 2005. We capitalize a portion of interest related to unproved properties. The increase in interest expense in 2007 was primarily due to an increase in borrowings against our line of credit facility, partially offset by an increase in capitalized interest costs. The decrease in interest expense in 2006 was primarily due to an increase in capitalized interest costs, partially offset by an increase in borrowings against our line of credit facility.

In 2007 we incurred $12.8 million of debt retirement costs related to the redemption of our 9-3/8% senior notes due 2012. The costs were comprised of approximately $9.4 million of premiums paid to repurchase the notes, and $3.4 million to write-off unamortized debt issuance costs.

Our overall effective tax rate was 37.6% for 2007, 39.2% for 2006 and 37.3% for 2005. The effective tax rate for 2007 and 2006 was higher than the statutory rate primarily because of state income taxes and valuation allowances. For 2005, the effective tax rate was higher than the statutory rate primarily because of state income taxes.

Income from Continuing Operations. Our income from continuing operations for 2007 of $152.6 million was 1% higher than our 2006 income from continuing operations of $151.1 million due to higher oil prices and increased production, partially offset by increased costs including the retirement of our 9-3/8% senior notes due 2012.

Our income from continuing operations in 2006 of $151.1 million was 54% higher than our 2005 income from continuing operations of $97.9 million due to higher commodity prices and increased production.

Net Income. Our net income in 2007 of $21.3 million was 87% lower than our 2006 net income of $161.6 million, mainly due to our loss from discontinued operations of $131.3 million. Our net income in 2006 of $161.6 million was 40% higher than our 2005 net income of $115.8 million due to higher oil prices and increased production.

Discontinued Operations

In December 2007, Swift agreed to sell substantially all of our New Zealand assets for approximately $87.8 million. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. We began a strategic review of our New Zealand assets in the second quarter of 2007 which culminated in the agreement to sell substantially all of these assets in the fourth quarter of 2007, with an expected closing towards the end of the first quarter of 2008. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility. We expect to sell the remaining New Zealand assets sometime in 2008.

In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-lived Assets” (“SFAS 144”), the results of operations and the non-cash asset write-down for the New Zealand operations have been excluded from continuing operations and reported as discontinued operations for the current and prior periods. Furthermore, the assets included as part of this divestiture have been reclassified as held for sale in the Balance Sheet for prior periods. During the fourth quarter of 2007, the Company assessed its long-lived assets in New Zealand based on the selling price and terms of the sales agreement and recorded a non-cash asset write-down of $143.2 million related to these assets. This write-down is recorded in “Income (loss) from discontinued operations, net of taxes” on the accompanying statement of income.

As of December 31, 2007, operations in New Zealand had represented approximately 6% of our total assets and 12% of our 2007 sales volumes. These revenues and expenses were historically reported under our New Zealand operating segment, and are now reported under discontinued operations. The following table summarizes selected data pertaining to discontinued operations (in thousands except per share and per Boe amounts):

	2007			2006		2005

Oil and gas sales	$	42,394		$	64,039	$	67,894
Other revenues		1,221			862		999
Total revenues		43,615			64,901		68,893


Depreciation, depletion, and amortization		23,147			30,051		26,354
Other operating expenses		22,491			20,872		20,230
Non-cash write-down of property and equipment		143,152			---		---

Total expenses		188,790			50,923		46,584

Income (loss) from discontinued operations before income taxes		(145,175	)		13,978		22,309
Income tax expense (benefit)		(13,874	)		3,487		4,412

Income (loss) from discontinued operations, net of taxes	$	(131,301	)	$	10,491	$	17,898

Earnings per common share from discontinued operations, net of taxes-diluted	$	(4.29	)	$	0.35	$	0.61

Total sales volumes (MBoe)		1,387			2,252		2,758
Oil sales volumes (MBbls)		225			469		450
Natural gas sales volumes (Bcf)		5.9			9.2		11.9
NGL sales volumes (MBbls)		177			253		329

Average sales price per Boe	$	30.56		$	28.43	$	24.60
Oil sales price per Bbl	$	75.78		$	67.06	$	55.57
Natural gas sales price per Mcf	$	3.36		$	2.99	$	3.09
NGL sales price per Bbl	$	30.91		$	20.22	$	18.84

Lease operating cost per Boe	$	9.93		$	5.56	$	4.49
Total assets	$	110,585		$	235,997	$	241,943
Cash flow provided by operating activities	$	25,620		$	41,680	$	48,543
Capital expenditures	$	9,466		$	56,707	$	50,844

Income (loss) from discontinued operations, net of tax, for 2007 decreased compared to the same period of 2006 primarily due to the non-cash write-down of property and equipment, a decrease in produced oil and natural gas volumes which reduced revenues, partially offset by a tax benefit associated with the non-cash write-down of property and equipment, along with lower depletion expense due to lower production volumes. For the years 2007, 2006, and 2005, our capitalized general and administrative expenses totaled $4.2 million, $4.1 million, and $4.3 million.

Income from discontinued operations, net of tax, for 2006 decreased 41% compared to the same period of 2005 primarily due to a decrease in produced oil and natural gas volumes which reduced revenue, along with higher depletion expense in the 2006 period due to an increase in the depletable oil and natural gas property base and lower reserves.

Liquidity and Capital Resources

During 2007, we relied upon our net cash provided by operating activities from continuing operations of $442.9 million, credit facility borrowings of $155.6 million, and cash balances to fund capital expenditures of $650.6 million including $252.3 million of acquisitions. During 2006, we relied upon our net cash provided by operating activities from continuing operations of $383.2 million, credit facility borrowings of $31.4 million, property sales proceeds of $24.7 million, and cash balances to fund capital expenditures of $488.2 million including $194.3 million of acquisitions.

Net Cash Provided by Operating Activities. For 2007, our net cash provided by operating activities from continuing operations was $442.3 million, representing a 15% increase as compared to $383.2 million generated during 2006. The $59.0 million increase in 2007 was primarily due to an increase of $115.3 million in oil and gas sales, attributable to higher oil prices and production, offset in part by higher lease operating costs and severance taxes due to higher oil prices and higher production. For 2006, our net cash provided by operating activities from continuing operations was $383.2 million, representing a 62% increase as compared to $236.8 million generated during 2005. The $146.5 million increase in 2006 was primarily due to an increase of $181.6 million in oil and gas sales, attributable to higher oil prices and production, offset in part by higher lease operating costs and severance taxes due to higher oil prices and higher production.

Accounts Receivable. We assess the collectibility of accounts receivable, and, based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both December 31, 2007 and 2006, we had an allowance for doubtful accounts of less than $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.

Existing Credit Facility. We had borrowings of $187.0 million under our bank credit facility at December 31, 2007, and $31.4 million in borrowings at December 31, 2006. Our bank credit facility at December 31, 2007 consisted of a $500.0 million revolving line of credit with a $400.0 million borrowing base based entirely on assets from our continuing operations. The borrowing base is re-determined at least every six months and was increased by our bank group from $350.0 million to $400.0 million in November 2007. Under the terms of our bank credit facility, we can increase this commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. In September 2007, we increased the commitment amount from $250.0 million to $350.0 million. Our revolving credit facility includes requirements to maintain certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt. We are in compliance with the provisions of this agreement.

Our access to funds from our credit facility is not restricted under any “material adverse condition” clause, a clause that is common for credit agreements to include. A “material adverse condition” clause can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have an adverse or material effect on operations, financial condition, prospects or properties, and would impair the ability to make timely debt repayments. Our credit facility includes covenants that require us to report events or conditions having a material adverse effect on our financial condition. The obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.

Working Capital. Our working capital increased from a deficit of $61.7 million at December 31, 2006, to a deficit of $10.2 million at December 31, 2007. The improvement primarily resulted from a reclassification of New Zealand oil and natural gas properties to assets held for sale within current assets, partially offset by an increase in accounts payable and accrued capital costs.

Debt Retirements and Debt Issuances. In June 2007, we issued $250.0 million of 7-1/8% senior notes due 2017. In June 2007, we redeemed all $200.0 million of 9-3/8% senior subordinated notes due 2012 and recorded a charge of $12.8 million related to the redemption of these notes, which is recorded in “Debt retirement costs” on the accompanying condensed consolidated statement of income. The costs were comprised of approximately $9.4 million of premium paid to redeem the notes, and $3.4 million to write-off unamortized debt issuance costs.

Debt Maturities. Our credit facility, with a balance of $187.0 million at December 31, 2007, extends until October 3, 2011. Our $150.0 million of 7-5/8% senior notes mature July 15, 2011, and our $250.0 million of 7-1/8% senior notes mature June 1, 2017.

Capital Expenditures. In 2007 we relied upon our net cash provided by operating activities from continuing operations of $442.3, credit facility borrowings of $155.6 million, and cash balances to fund capital expenditures of $650.6 million including $252.3 million of acquisitions.

We have spent considerable time and capital on facility capacity upgrades and additions in the Lake Washington field. Since acquiring the property, we have upgraded three production platforms, added new compression for the gas lift system, and installed a new oil delivery system and permanent barge loading facility. During 2006, we began planning for the addition of a fourth production platform, the Westside facility, which will increase our processing capacity another 10,000 barrels per day by mid-2008.

We completed 61 of 69 wells in 2007, for a success rate of 88%. A total of 22 development wells were drilled in the Lake Washington area, of which 18 were completed, and 21 development wells were drilled successfully in the AWP Olmos area. In Bay de Chene, we successfully drilled two development wells and drilled five exploratory wells, of which two were completed. We also drilled 11 successful development wells in the South Bearhead Creek area, drilled seven development wells in the Cotulla area, of which six were completed, and drilled one successful development well in the Bayou Sale field.

Our capital expenditures were approximately $488.2 million in 2006 and $197.8 million in 2005. In 2006, we relied upon our net cash provided by operating activities from continuing operations of $383.2 million, bank borrowings of $31.4 million, and cash balances to fund capital expenditures of $488.2 million, including acquisitions of $194.3 million. During 2005, we relied upon our net cash provided by operating activities of $236.8 million to fund capital expenditures of $197.8 million, including acquisitions of $28.9 million.

In 2006, we participated in drilling 49 development wells and six exploratory wells, of which 42 development wells were completed.

Contractual Commitments and Obligations

Our contractual commitments for the next five years and thereafter as of December 31, 2007 are as follows:

	2008		2009		2010		2011		2012		Thereafter		Total
	(In thousands)
Non-cancelable operating leases (1)	$	7,706	$	4,890	$	3,354	$	3,213	$	3,213	$	6,963	$	29,339
Asset retirement obligation (2)		3,393		1,878		2,047		2,419		2,604		30,183		42,524
Drilling rigs, seismic and pipe inventory		34,196		—		—		—		—		—		34,196
7-5/8% senior notes due 2011 (3)		—		—		—		150,000		—		—		150,000
7-1/8% senior notes due 2017 (3)		—		—		—		—		—		250,000		250,000
Credit facility (4)		—		—		—		187,000		—		—		187,000
Total	$	45,295	$	6,768	$	5,401	$	342,632	$	5,817	$	287,146	$	693,059

(1)	Our most significant office lease is in Houston, Texas and it extends until 2015.

(2)	Amounts shown by year are the fair values at December 31, 2007.

(3)	Amounts do not include the interest obligation, which is paid semiannually.

(4)	The credit facility expires in October 2011 and these amounts exclude a $0.8 million standby letter of credit outstanding under this facility.

Domestic Proved Oil and Gas Reserves

At year-end 2007, our domestic proved reserves were 133.8 MMBoe with a PV-10 Value of $3.8 billion (PV-10 is a non-GAAP measure, see the section titled “Oil and Natural Gas Reserves” in our Property section for a reconciliation of this non-GAAP measure to the closest GAAP measure, the standardized measure). In 2007, our domestic proved natural gas reserves increased 74.1 Bcf, or 27%, while our proved oil reserves decreased 3.7 MMBbl, or 6%, and our NGL reserves increased 6.7 MMBbl, or 58%, for a total equivalent increase of 15.4 MMBoe, or 13%. In 2006, our domestic proved natural gas reserves increased 44.4 Bcf, or 20%, while our proved oil reserves increased 4.4 MMBbl, or 8%, and our NGL reserves decreased 0.7 MMBbl, or 6%, for a total equivalent increase of 11.1 MMBbl, or 10%. We added reserves over the past three years through both our drilling activity and purchases of minerals in place. Through drilling we added 12.9 MMBoe of proved reserves in 2007, 11.9 MMBoe in 2006, and 4.9 MMBoe in 2005. Through acquisitions we added 12.9 MMBoe of proved reserves in 2007, 13.0 Bcfe in 2006, and 4.8 Bcfe in 2005. At year-end 2007, 48% of our total proved reserves were proved developed, compared with 47% at year-end 2006 and 52% at year-end 2005.

The PV-10 Value of our domestic proved reserves at year-end 2007 increased 55% from the PV-10 Value at year-end 2006. Natural gas prices increased in 2007 to $6.65 per Mcf from $5.84 per Mcf at year-end 2006, compared to $10.36 per Mcf at year-end 2005. Oil prices increased in 2007 to $93.24 per Bbl from $60.07 per Bbl at year-end 2006, compared to $60.00 in 2005. Under SEC guidelines, estimates of proved reserves must be made using year-end oil and gas sales prices and are held constant for that year’s reserves calculation throughout the life of the properties. Subsequent changes to such year-end oil and natural gas prices could have a significant impact on the calculated PV-10 Value.

Commodity Price Trends and Uncertainties

Oil and natural gas prices historically have been volatile and are expected to continue to be volatile in the future. The price of oil has increased over the last three years and is at historical highs when compared to longer-term historical prices. Factors such as worldwide supply disruptions, worldwide economic conditions, weather conditions, fluctuating currency exchange rates, and political conditions in major oil producing regions, especially the Middle East, can cause fluctuations in the price of oil. Domestic natural gas prices have fallen from highs in 2005 but continue to remain high when compared to longer-term historical prices. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, the level of liquefied natural gas imports, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas.

Income Taxes

The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ. Under SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

On January 1, 2007, we adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109" ("FIN 48"). Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting FIN 48, we reported a $1.0 million decrease to our January 1, 2007 retained earnings balance and a corresponding increase to other long-term liabilities. This was also the total balance of our unrecognized tax benefits, which would fully impact our effective tax rate if recognized. There were no increases or decreases in unrecognized tax benefits during the year ended December 31, 2007.

Our policy is to record interest and penalties relating to income taxes in income tax expense. As of December 31, 2007 and 2006 no interest or penalties relating to income taxes have been incurred or recognized. Our cumulative interest exposure on unrecognized tax benefits is not material.

Our U.S. Federal and State of Louisiana income tax returns from 1998 forward, our New Zealand income tax returns after 2001, and our Texas franchise tax returns after 2005 remain subject to examination by the taxing authorities. There are no unresolved items related to periods previously audited by these taxing authorities. No other state returns are significant to our financial position.

In the third quarter of 2007 we increased the valuation allowance for our capital loss carryforward assets by $2.6 million to cover the full value of the carryforward. The increase in the valuation allowance was due to changes in the Company’s property disposition plans and increased income tax expense of $2.6 million in that period.

Critical Accounting Policies

The following summarizes several of our critical accounting policies. See a complete list of significant accounting policies in Note 1 to the consolidated financial statements.

Use of Estimates. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires us to make estimates and assumptions that affect the reported amount of certain assets and liabilities and the reported amounts of certain revenues and expenses during each reporting period. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates. Significant estimates and assumptions underlying these financial statements include:

the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties and the related present value of estimated future net cash flows there-from,

estimates of future costs to develop and produce reserves,

accruals related to oil and gas revenues, capital expenditures and lease operating expenses,

estimates in the calculation of stock compensation expense,

estimates of our ownership in properties prior to final division of interest determination,

the estimated future cost and timing of asset retirement obligations, and

estimates made in our income tax calculations.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as changes in new accounting pronouncements, ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the years 2007, 2006, and 2005, such internal costs capitalized totaled $26.4 million, $24.1 million, and $14.5 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the years 2007, 2006, and 2005, capitalized interest on unproved properties totaled $9.5 million, $9.2 million, and $7.2 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges at December 31, 2007 consisted of oil and natural gas price floors with strike prices lower than the period-end price and did not materially affect this calculation. This calculation is done on a country-by-country basis.

The calculation of the Ceiling Test and provision for DD&A is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered. Our reserves estimates are prepared in accordance with Securities and Exchange Commission guidelines and are audited on an annual basis at year-end by a firm of independent petroleum engineers in accordance with standards approved by the Board of Directors of the Society of Petroleum Engineers.

Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the near term. If oil and natural gas prices decline significantly from our period-end prices used in the Ceiling Test, even if only for a short period, it is possible that non-cash write-downs of oil and natural gas properties could occur in the future. If we have significant declines in our oil and natural gas reserves volumes, which also reduce our estimate of discounted future net cash flows from proved oil and natural gas reserves, a non-cash write-down of our oil and natural gas properties could occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a sizable decrease in oil and/or natural gas prices were to occur.

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. The Company uses the entitlement method of accounting in which the Company recognizes its ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2007, we did not have any material natural gas imbalances.

New Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. It does not create or modify any current GAAP requirements to apply fair value accounting. However, it provides a single definition for fair value that is to be applied consistently for all prior accounting pronouncements. SFAS No. 157 was effective for fiscal periods beginning after November 15, 2007. On February 12, 2008, the FASB delayed the effective date of SFAS No. 157 for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. For Swift, this action defers the effective date for those assets and liabilities until January 1, 2009. We believe that the adoption of this statement will not have a material impact on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115. SFAS No. 159 permits entities to measure eligible assets and liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been elected are reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We adopted SFAS No. 159 on January 1, 2008 and did not elect to apply the fair value method to any eligible assets or liabilities at that time.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS No. 141(R) provides enhanced guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect on the Company. This Statement, together with the International Accounting Standards Board’s IFRS 3, Business Combinations , completes a joint effort by the FASB and IASB to improve financial reporting about business combinations and promotes the international convergence of accounting standards. For Swift, SFAS No. 141(R) applies prospectively to business combinations in 2009 and is not subject to early adoption. We are currently evaluating the potential impact of SFAS No. 141(R) on business combinations and related valuations.

Related-Party Transactions

We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee, and controlled and majority owned by the aunt of the Company’s Chairman of the Board and Chief Executive Officer. We paid approximately $0.6 million to Tec-Com for such services pursuant to the terms of the contract between the parties in 2007, $0.5 million in 2006 and $0.4 million in 2005. The contract was renewed June 30, 2007, on substantially the same terms as the previous contract and expires June 30, 2010. We believe that the terms of this contract are consistent with third party arrangements that provide similar services.

As a matter of corporate governance policy and practice, related party transactions are presented and considered by the Corporate Governance Committee of our Board of Directors.

Forward-Looking Statements

The statements contained in this report that are not historical facts are forward-looking statements as that term is defined in Section 21E of the Securities Exchange Act of 1934, as amended. Such forward-looking statements may pertain to, among other things, financial results, capital expenditures, drilling activity, development activities, cost savings, production efforts and volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, acquisition plans, regulatory matters, and competition. Such forward-looking statements generally are accompanied by words such as “plan,” “future,” “estimate,” “expect,” “budget,” “predict,” “anticipate,” “projected,” “should,” “believe,” or other words that convey the uncertainty of future events or outcomes. Such forward-looking information is based upon management’s current plans, expectations, estimates, and assumptions, upon current market conditions, and upon engineering and geologic information available at this time, and is subject to change and to a number of risks and uncertainties, and, therefore, actual results may differ materially from those projected. Among the factors that could cause actual results to differ materially are: volatility in oil and natural gas prices; availability of services and supplies; disruption of operations and damages due to hurricanes or tropical storms; fluctuations of the prices received or demand for our oil and natural gas; the uncertainty of drilling results and reserve estimates; operating hazards; requirements for and availability of capital; general economic conditions; changes in geologic or engineering information; changes in market conditions; competition and government regulations; as well as the risks and uncertainties discussed in this report and set forth from time to time in our other public reports, filings, and public statements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. 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. The effects of such pricing volatility are expected to continue.

Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. Below is a description of the financial instruments we have utilized to hedge our exposure to price risk.

•Price Floors – At December 31, 2007, we had in place price floors in effect through the March 2008 contract month for oil and natural gas. The oil price floors cover notional volumes of 639,000 barrels, with a weighted average floor price of $71.22 per barrel. Our oil price floors in place at December 31, 2007, are expected to cover approximately 40% to 45% of our estimated oil production from January 2008 to March 2008. The natural gas price floors cover notional volumes of 1,330,000 MMBtu, with a weighted average floor price of $6.90 per MMBtu. Our natural gas price floors in place at December 31, 2007, are expected to cover approximately 40% to 45% of our natural gas production in February 2008 and March 2008. The fair value of these instruments at December 31, 2007, was $0.3 million and is recognized on the accompanying balance sheet in “Other current assets.” There are no additional cash outflows for these price floors, as the cash premium was paid at inception of the hedge. The maximum loss that could be sustained on our financial statements from these price floors in 2008 would be their fair value at December 31, 2007 of $0.3 million.

Interest Rate Risk. Our senior notes and senior subordinated notes both have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At December 31, 2007, we had borrowings of $187.0 million under our credit facility, which bears a floating rate of interest and therefore is susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 73 basis points and would not have a material adverse effect on our 2008 cash flows based on this same level of borrowing.

Income Tax Carryforwards. During 2007, the Company recorded a write-down and valuation allowance totaling $2.6 million for capital loss carryforwards as detailed in Note 3 of the accompanying consolidated financial statements. The Company has other net tax carryforwards for federal alternative minimum tax credits ($5.1 million) and state tax net operating loss carryforwards ($4.3 million) which in management’s judgment will more likely than not be utilized to offset future taxable earnings.

The Company’s New Zealand subsidiaries have local income tax loss carryovers, a portion of which will offset the sales proceeds from the liquidation of assets. We have estimated a net loss carryover asset of $33.5 million will remain after closing of the pending transaction. In management’s judgment it is less than more likely than not that the remaining carryover will be utilized. Accordingly, this carryover asset has been fully offset by a valuation allowance.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2007 and 2006, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2007, the fair value of our senior notes due 2017, which were issued during 2007, were $237.5 million, or 95.0% of face value. Based upon quoted market prices as of December 31, 2007 and 2006, the fair values of our senior notes due 2011 were $150.8 million, or 100.5% of face value, and $152.6 million, or 101.75% of face value. The carrying value of our senior notes due 2017 was $250.0 million at December 31, 2007. The carrying value of our senior notes due 2011 was $150.0 million at December 31 for both 2007 and 2006.

Foreign Currency Risk. We are exposed to the risk of fluctuations in foreign currencies, most notably the New Zealand Dollar. Fluctuations in rates between the New Zealand Dollar and U.S. Dollar may impact our financial results from our New Zealand subsidiaries since we have receivables, liabilities, natural gas and NGL sales contracts, and New Zealand income tax calculations, all denominated in New Zealand Dollars. We use the U.S. Dollar as our functional currency in New Zealand and as currency rate changes between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in “Income (loss) from discontinued operations, net of taxes” on the accompanying statements of income.

Customer Credit Risk. We are exposed to the risk of financial non-performance by customers. Our ability to collect on sales to our customers is dependent on the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers and seek to minimize exposure to any one customer where other customers are readily available. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Item 8. Financial Statements and Supplementary Data	Page

Management’s Report on Internal Control
Over Financial Reporting	46

Reports of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	47

Reports of Independent Registered Public Accounting Firm on Consolidated Financial Statements	48

Consolidated Balance Sheets	49

Consolidated Statements of Income	50

Consolidated Statements of Stockholders’ Equity	51

Consolidated Statements of Cash Flows	52

Notes to Consolidated Financial Statements	53

1. Summary of Significant Accounting Policies	53
2. Earnings Per Share	60
3. Provision for Income Taxes	60
4. Long-Term Debt	62
5. Commitments and Contingencies	64
6. Stockholders’ Equity	64
7. Related-Party Transactions	68
8. Discontinued Operations	68
9. Acquisitions and Dispositions	70
10. Condensed Consolidating Financial Information	71

Supplementary Information	74
Oil and Gas Operations (Unaudited)	74
Selected Quarterly Financial Data (Unaudited)	80

Management’s Report on Internal Control Over Financial Reporting

Management of Swift Energy Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934. The Company’s internal control over financial reporting is a process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external purposes in accordance with U. S. generally accepted accounting principles.

Management of the Company assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control—Integrated Framework. Based on our assessment and those criteria, management determined that the Company maintained effective internal control over financial reporting as of December 31, 2007.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the Company’s internal control over financial reporting as of December 31, 2007, based on their audit. The Public Company Accounting Oversight Board (United States) standards require that they plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Their audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as they considered necessary in the circumstances.

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of Swift Energy Company

We have audited Swift Energy Company and subsidiaries’ (the “Company”) internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of the Company as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007 and our report dated February 27, 2008 expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas

February 27, 2008

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of Swift Energy Company

We have audited the accompanying consolidated balance sheets of Swift Energy Company and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company at December 31, 2007 and 2006, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2007 the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes, and effective January 1, 2006 the Company adopted Statement of Financial Accounting Standards No. 123 (revised 2004), Share-Based Payment.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2008 expressed an unqualified opinion thereon.

ERNST & YOUNG LLP

Houston, Texas

February 27, 2008

Consolidated Balance Sheets

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)	Year Ended December 31,
	2007			2006
ASSETS
Current Assets:
Cash and cash equivalents	$	5,623		$	1,058
Accounts receivable-
Oil and gas sales		72,916			63,935
Joint interest owners		1,587			1,844
Other Receivables		1,324			1,231
Deferred tax asset		8,055			2,383
Other current assets		13,896			13,332
Current assets held for sale		96,549			---
Total Current Assets		199,950			83,783

Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties		2,610,469			1,918,375
Unproved properties		106,643			95,569
		2,717,112			2,013,944
Furniture, fixtures, and other equipment		33,064			26,020
		2,750,176			2,039,964
Less – Accumulated depreciation, depletion, and amortization		(989,981	)		(800,242	)
		1,760,195			1,239,722
Other Assets:
Debt issuance costs		7,252			7,382
Restricted assets		1,654			2,415
Long-term assets held for sale		---			252,380
		8,906			262,177
	$	1,969,051		$	1,585,682

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	89,281		$	73,921
Accrued capital costs		94,947			55,282
Accrued interest		7,558			8,764
Undistributed oil and gas revenues		10,309			7,504
Current liabilities associated with assets held for sale		8,066			---
Total Current Liabilities		210,161			145,471
Long-Term Debt		587,000			381,400
Deferred Income Taxes		302,303			212,458
Asset Retirement Obligation		31,066			28,533
Other Long-Term Liabilities		2,467			1,728
Long-term liabilities associated with assets held for sale		---			18,175

Commitments and Contingencies

Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding		---			---
Common stock, $.01 par value, 85,000,000 shares authorized, 30,615,010 and 30,170,004 shares issued, and 30,178,596 and 29,742,918 shares
outstanding, respectively		306			302
Additional paid-in capital		407,464			387,556
Treasury stock held, at cost, 436,414 and 427,086 shares, respectively		(7,480	)		(6,125	)
Retained earnings		436,178			415,868
Accumulated other comprehensive income (loss), net of income tax		(414	)		316
		836,054			797,917
	$	1,969,051		$	1,585,682

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Income

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)

	Year Ended December 31,
	2007			2006		2005
Revenues:
Oil and gas sales	$	652,856		$	537,513	$	355,873
Price-risk management and other, net		1,265			13,323		(1,508	)

		654,121			550,836		354,365

Costs and Expenses:
General and administrative, net		34,182			27,634		18,866
Depreciation, depletion, and amortization		188,393			139,245		81,124
Accretion of asset retirement obligation		1,437			884		626
Lease operating cost		70,893			49,948		34,941
Severance and other taxes		73,813			61,235		37,806
Interest expense, net		28,082			23,582		24,873
Debt retirement cost		12,765			---		---

		409,565			302,528		198,236


Income from Continuing Operations Before Income Taxes		244,556			248,308		156,129

Provision for Income Taxes		91,968			97,234		58,249

Income from Continuing Operations		152,588			151,074		97,880

Income (Loss) from Discontinued Operations, net of taxes		(131,301	)		10,491		17,898

Net Income	$	21,287		$	161,565	$	115,778

Per Share Amounts-

Basic: Income from Continuing Operations	$	5.09		$	5.16	$	3.43
Income (Loss) from Discontinued Operations, net of taxes		(4.38	)		0.36		0.63
Net Income	$	0.71		$	5.52	$	4.06

Diluted: Income from Continuing Operations	$	4.98		$	5.03	$	3.34
Income (Loss) from Discontinued Operations, net of taxes		(4.29	)		0.35		0.61
Net Income	$	0.69		$	5.38	$	3.95

Weighted Average Shares Outstanding		29,984			29,265		28,496

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Stockholders’ Equity

Swift Energy Company and Subsidiaries

(in thousands, except per share amounts)

	Common Stock (1)		Additional Paid-in Capital			Treasury Stock			Unearned Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2004	$	286	$	343,536		$	(6,896	)	$	(1,729	)	$	138,524		$	451		$	474,172

Stock issued for benefit plans (31,424 shares)		-		435			450			-			-			-			885
Stock options exercised (840,847 shares)		9		9,805			-			-			-			-			9,814
Tax benefits from exercise of stock options		-		4,366			-			-			-			-			4,366
Employee stock purchase plan (32,495 shares)		-		642			-			-			-			-			642
Issuance of restricted stock (15,000 shares)		-		-			-			-			-			-			-
Grants of restricted stock (158,500 shares)		-		6,669			-			(6,072	)		-			-			597
Forfeitures of restricted stock		-		(367	)		-			367			-			-			-
Amortization of stock compensation		-		-			-			1,584			-			-			1,584
Comprehensive income:
Net income		-		-			-			-			115,779			-			115,779
Change in fair value of other comprehensive loss		-		-			-			-			-			(521	)		(521	)
Total comprehensive income																			115,258
Balance, December 31, 2005	$	295	$	365,086		$	(6,446	)	$	(5,850	)	$	254,303		$	(70	)	$	607,318

Stock issued for benefit plans (22,358 shares)		-		714			321			-			-			-			1,035
Stock options exercised (652,829 shares)		7		11,831			-			-			-			-			11,838
Adoption of SFAS No. 123R		-		(5,875	)		-			5,850			-			-			(25	)
Excess tax benefits from stock-based awards		-		4,811			-			-			-			-			4,811
Employee stock purchase plan (22,425 shares)		-		671			-			-			-			-			671
Issuance of restricted stock (35,776 shares)		-		-			-			-			-			-			-
Amortization of stock compensation		-		10,318			-			-			-			-			10,318
Comprehensive income:
Net income		-		-			-			-			161,565			-			161,565
Other comprehensive income		-		-			-			-			-			386			386
Total comprehensive income																			161,951
Balance, December 31, 2006	$	302	$	387,556		$	(6,125	)	$	-		$	415,868		$	316		$	797,917

Stock issued for benefit plans (32,817 shares)		-		953			471			-			-			-			1,424
Stock options exercised (239,650 shares)		2		3,168			-			-			-			-			3,170
Purchase of treasury shares (42,145 shares)		-		-			(1,826	)		-			-			-			(1,826	)
Adoption of FIN 48		-		-			-			-			(977	)		-			(977	)
Excess tax benefits from stock-based awards		-		613			-			-			-			-			613
Employee stock purchase plan (17,678 shares)		-		619			-			-			-			-			619
Issuance of restricted stock (187,678 shares)		2		(2	)		-			-			-			-			-
Amortization of stock compensation		-		14,557			-			-			-			-			14,557
Comprehensive income:
Net income		-		-			-			-			21,287			-			21,287
Other comprehensive loss		-		-			-			-			-			(730	)		(730	)
Total comprehensive income																			20,557
Balance, December 31, 2007	$	306	$	407,464		$	(7,480	)	$	-		$	436,178		$	(414	)	$	836,054

(1)$.01 par value.

See accompanying Notes to Consolidated Financial Statements.

Consolidated Statements of Cash Flows

Swift Energy Company and Subsidiaries

(in thousands)	Year Ended December 31,
	2007			2006			2005
Cash Flows from Operating Activities:
Net income	$	21,287		$	161,565		$	115,778
Plus (income) loss from discontinued operations, net of taxes		131,301			(10,491	)		(17,898	)
Adjustments to reconcile net income to net cash provided by operation activities -
Depreciation, depletion, and amortization		188,393			139,245			81,124
Accretion of asset retirement obligation		1,437			884			626
Deferred income taxes		86,474			86,541			57,499
Stock-based compensation expense		10,317			6,905			1,451
Debt retirement cost – cash and non-cash		12,765			---			---
Other		(4,314	)		7,117			(334	)
Change in assets and liabilities-
Increase in accounts receivable		(9,114	)		(20,571	)		(5,826	)
Increase in accounts payable and accrued liabilities		5,748			10,906			5,072
Increase (decrease) in income taxes payable		(806	)		884			---
Increase (decrease) in accrued interest		(1,206	)		256			(701	)
Cash Provided by operating activities – continuing operations		442,282			383,241			236,791
Cash Provided by operating activities – discontinued operations		25,620			41,680			48,543
Net Cash Provided by Operating Activities		467,902			424,921			285,334

Cash Flows from Investing Activities:
Additions to property and equipment		(398,295	)		(293,957	)		(168,914	)
Proceeds from the sale of property and equipment		250			24,678			7,297
Acquisition of properties		(252,299	)		(194,269	)		(28,927	)
Net cash received (distributed) as operator of partnerships
and joint ventures		485			410			(948	)
Other		---			(528	)		255
Cash Used in investing activities – continuing operations		(649,859	)		(463,666	)		(191,237	)
Cash Used in investing activities – discontinued operations		(7,827	)		(59,881	)		(48,837	)
Net Cash Used in Investing Activities		(657,686	)		(523,547	)		(240,074	)

Cash Flows from Financing Activities:
Proceeds from long-term debt		250,000			---			---
Payments of long-term debt		(200,000	)		---			---
Net proceeds from (payments of) bank borrowings		155,600			31,400			(7,500	)
Net proceeds from issuances of common stock		3,789			12,509			10,325
Excess tax benefits from stock-based awards		613			3,328			---
Purchase of treasury shares		(1,826	)		---			---
Payments of debt retirement costs		(9,376	)		---			---
Payments of debt issuance costs		(4,451	)		(558	)		---
Cash provided by financing activities – continuing operations		194,349			46,679			2,825
Cash provided by financing activities – discontinued operations		---			---			---
Net Cash Provided by financing activities		194,349			46,679			2,825

Net Increase (Decrease) in Cash and Cash Equivalents	$	4,565		$	(51,947	)	$	48,085

Cash and Cash Equivalents at Beginning of Year		1,058			53,005			4,920

Cash and Cash Equivalents at End of Year	$	5,623		$	1,058		$	53,005

Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized	$	28,092		$	22,691		$	24,483
Cash paid during year for income taxes	$	2,113		$	9,780		$	750

See accompanying Notes to Consolidated Financial Statements.

Notes to Consolidated Financial Statements

Swift Energy Company and Subsidiaries

1.	Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial statements include the accounts of Swift Energy Company (“Swift Energy”) and its wholly owned subsidiaries, which are engaged in the exploration, development, acquisition, and operation of oil and natural gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in gas processing plants are accounted for using the proportionate consolidation method, whereby our proportionate share of each entity’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements. Intercompany balances and transactions have been eliminated in preparing the accompanying consolidated financial statements.

Holding Company Structure. In December 2005, we implemented a holding company structure pursuant to Texas and federal law in a manner designed to be a non-taxable transaction. The new parent holding company assumed the Swift Energy Company name and its common stock and continued to trade on the New York Stock Exchange. The purposes of this holding company structure are to align Swift Energy’s operations to better reflect management practices, to improve our economics, and to provide greater administrative and organizational flexibility. Under the new organizational structure, four new subsidiaries were formed with the Texas parent holding company wholly owning four Delaware subsidiaries, which in turn wholly own Swift Energy’s operating subsidiaries. Swift Energy Operating, LLC is the operator of record for Swift Energy’s domestic properties. Swift Energy’s name, charter, bylaws, officers, board of directors, authorized shares and shares outstanding remain substantially identical. The Company’s international operations continue to be conducted through Swift Energy International, Inc. Swift Energy made amendments to its bank credit agreement, debt indentures and various other plans and documents to accommodate the internal reorganization, but the Company’s day-to-day conduct of business was not impacted. Accordingly, there was no impact on our financial position or results of operations.

Discontinued Operations. Certain amounts have been reclassified to present the Company’s New Zealand operations as discontinued operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Swift’s continuing operations. Information related to discontinued operations is included in Note 8 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

estimates of future costs to develop and produce reserves,

accruals related to oil and gas revenues, capital expenditures and lease operating expenses,

estimates of insurance recoveries related to property damage,

estimates in the calculation of stock compensation expense,

estimates of our ownership in properties prior to final division of interest determination,

the estimated future cost and timing of asset retirement obligations,

estimates made in our income tax calculations, and

estimates in the calculation of the fair value of hedging assets.

While we are not aware of any material revisions to any of our estimates, there will likely be future revisions to our estimates resulting from matters such as new accounting pronouncements, changes in ownership interests, payouts, joint venture audits, re-allocations by purchasers or pipelines, or other corrections and adjustments common in the oil and gas industry, many of which require retroactive application. These types of adjustments cannot be currently estimated and will be recorded in the period during which the adjustment occurs.

No gains or losses are recognized upon the sale or disposition of oil and natural gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and natural gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a cost center. Internal costs associated with selling properties are expensed as incurred.

Future development costs are estimated property-by-property based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized.

We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and natural gas produced during the period by the total estimated units of proved oil and natural gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment, recorded at cost, are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between three and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

Geological and geophysical (“G&G”) costs incurred on developed properties are recorded in “Proved properties” and therefore subject to amortization. G&G costs incurred that are directly associated with specific unproved properties are capitalized in “Unproved properties” and evaluated as part of the total capitalized costs associated with a prospect. The cost of unproved properties not being amortized is assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using period-end prices, adjusted for the effects of hedging, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). Our hedges at December 31, 2007 consisted of oil and natural gas price floors with strike prices lower than the period-end price and did not materially affect this calculation. This calculation is done on a country-by-country basis.

The calculation of the Ceiling Test and provision for depreciation, depletion, and amortization (“DD&A”) is based on estimates of proved reserves. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production, timing, and plan of development. The accuracy of any reserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing, and production subsequent to the date of the estimate may justify revision of such estimates. Accordingly, reserves estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectibility of the revenue is probable. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying balance sheet. Natural gas balancing receivables are reported in “Other current assets” on the accompanying balance sheet when our ownership share of production exceeds sales. As of December 31, 2007, we did not have any material natural gas imbalances.

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At December 31, 2007 and 2006, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying balance sheets.

Debt Issuance Costs. Legal and accounting fees, underwriting fees, printing costs, and other direct expenses associated with the June 2004 extension of our bank credit facility, the public offering in June 2004 of our 7-5/8% senior notes due 2011, and the public offering in June 2007 of our 7-1/8% senior subordinated notes due 2017, were capitalized and are amortized on an effective interest basis over the life of each of the respective note offerings and credit facility. The 7-1/8% senior notes due 2017 mature on June 1, 2017, and the balance of their issuance costs at December 31, 2007, was $4.0 million, net of accumulated amortization of $0.2 million. The issuance costs associated with our revolving credit facility, which was extended in October 2006, have been capitalized and are being amortized over the life of the facility. The balance of revolving credit facility issuance costs at December 31, 2007, was $1.0 million, net of accumulated amortization of $2.2 million. The 7-5/8% senior notes due 2011 mature on July 15, 2011, and the balance of their issuance costs at December 31, 2007, was $2.3 million, net of accumulated amortization of $1.7 million.

Settlement of Insurance Claims. In 2006, we settled all insurance claims with our insurers relating to hurricanes Katrina and Rita for approximately $30.5 million and entered into a confidential final settlement agreement. The receipt of these amounts resulted in a benefit of $7.7 million in 2006 recorded in “Price-risk management and other, net,” for the portion of the above referenced settlement, which we have determined to be non-property damage related claims. Approximately $22.8 million of the above referenced settlement was determined to be property damage related claims. We recorded $14.1 million of the property related settlement as a reduction to “Proved properties” on the accompanying consolidated balance sheet, as this related to reimbursement of capital costs we incurred. We also recorded $8.7 million of the property related settlement as a reduction to “Lease operating cost” on the accompanying consolidated statement of income, as this related to reimbursement of repair costs which had been expensed as incurred. In the accompanying consolidated statement of cash flows, we have recorded the reimbursement which reduced “Proved properties” as a reduction of “Net Cash Used in Investing Activities – Continuing Operations” and the remainder of the insurance settlement was recorded as an increase to “Net Cash Provided by Operating Activities – Continuing Operations.”

Price-Risk Management Activities. The Company follows SFAS No. 133, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The statement also establishes accounting and reporting standards requiring that every derivative instrument (including certain derivative instruments embedded in other contracts) is recorded in the balance sheet as either an asset or a liability measured at its fair value. Hedge accounting for a qualifying hedge allows the gains and losses on derivatives to offset related results on the hedged item in the income statements and requires that a company formally document, designate, and assess the effectiveness of transactions that receive hedge accounting. Changes in the fair value of derivatives that do not meet the criteria for hedge accounting, and the ineffective portion of the hedge, are recognized currently in income.

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. During 2007, 2006 and 2005, we recognized net gains of $0.2 million and $4.0 million and a net loss of $1.1 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. Had these gains and losses been recognized in the oil and gas sales account they would not materially change our per unit sales prices received. At December 31, 2007, the Company had recorded $0.4 million, net of taxes of $0.2 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” for 2007, 2006, and 2005 was not material. All amounts currently held in “Accumulated other comprehensive income (loss), net of income tax” will be realized within the next three months when the forecasted sale of hedged production occurs.

At December 31, 2007, we had in place oil price floors in effect for the contract months of January 2008 through March 2008 that cover a portion of our oil production for January 2008 to March 2008. We also had in place natural gas price floors in effect for the contract months of February 2008 through March 2008 that cover a portion of our natural gas production for February to March 2008. The oil price floors cover notional volumes of 639,000 barrels, with a weighted average floor price of $71.22 per barrel. Our oil price floors in place at December 31, 2007 are expected to cover approximately 40% to 45% of our estimated oil production from January 2008 to March 2008. The natural gas price floors cover notional volumes of 1,330,000 MMBtu, with a weighted average floor price of $6.90 per MMBtu. Our natural gas price floors in place at December 31, 2007 are expected to cover approximately 40% to 45% of our estimated natural gas production from February 2008 to March 2008.

When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of oil and natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive income (loss), net of income tax.” When the hedged transactions are recorded upon the actual sale of the oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive income (loss), net of income tax” and recorded in “Price-risk management and other, net” on the accompanying statements of income. The fair value of our derivatives are computed using the Black-Scholes-Merton option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at December 31, 2007, was $0.3 million and is recognized on the accompanying balance sheet in “Other current assets.”

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees, to the extent they do not exceed actual costs incurred, are recorded as a reduction to “General and administrative, net.” Our supervision fees are based on COPAS determined rates. The amount of supervision fees charged in 2007 and 2006 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operate was $11.8 million in 2007, $8.7 million in 2006, and $7.4 million in 2005.

Inventories. We value inventories at the lower of cost or market value. Inventory is accounted for using the first in, first out method (“FIFO”). Inventories consisting of materials, supplies, and tubulars are included in “Other current assets” on the accompanying balance sheets totaling $4.2 million at December 31, 2007 and $1.8 million at December 31, 2006.

Income Taxes. Under SFAS No. 109, “Accounting for Income Taxes,” deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

On January 1, 2007, we adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an Interpretation of FASB Statement No. 109" ("FIN 48"). Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting FIN 48, we reported a $1.0 million decrease to our January 1, 2007 retained earnings balance and a corresponding increase to other long-term liabilities. This was also the total balance of our unrecognized tax benefits, which would fully impact our effective tax rate if recognized. We did not recognize significant increases or decreases in unrecognized tax benefits during the year ended December 31, 2007.

Our policy is to record interest and penalties relating to income taxes in income tax expense. As of December 31, 2007 no interest or penalties relating to income taxes have been incurred or recognized. Our cumulative interest exposure on unrecognized tax benefits is not material.

Accounts Payable and Accrued Liabilities. Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at December 31, 2007 and 2006 are liabilities of approximately $12.6 million and $13.9 million, respectively, which represent the amounts by which checks issued, but not presented by vendors to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.

Cash and Cash Equivalents. We consider all highly liquid debt instruments with an initial maturity of three months or less to be cash equivalents.

Credit Risk Due to Certain Concentrations. We extend credit, primarily in the form of uncollateralized oil and natural gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions within our industry and may accordingly impact our overall credit risk. However, we believe that the risk of these unsecured receivables is mitigated by the size, reputation, and nature of the companies to which we extend credit. During 2007 and 2006, oil and gas sales to Shell Oil Company and affiliates were $290.1 million and $180.4 million, or 42% and 30% of total oil and gas sales, respectively. During 2007 and 2006, Chevron Corporation and its affiliates accounted for $151.0 million and $193.9 million, or 22% 32% of our total oil and gas sales. Credit losses in 2007, 2006 and 2005 were immaterial.

Environmental Costs. Our operations include activities that are subject to extensive federal and state environmental regulations. Costs associated with redemption projects, which are probable and reasonably estimable, are accrued in advance. Ongoing environmental compliance costs are expensed as incurred.

Restricted Assets. These balances primarily include amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields.

Foreign Currency. We use the U.S. Dollar as our functional currency in New Zealand. The functional currency is determined by examining the entities’ cash flows, commodity pricing, environment and financing arrangements. We have both assets and liabilities denominated in New Zealand Dollars, the New Zealand “Assets held for sale” and a portion of our “Liabilities associated with assets held for sale” on the accompanying balance sheets. As the exchange rate moves between the U.S. Dollar and the New Zealand Dollar, we recognize transaction gains and losses in “Income (loss) from discontinued operations, net of taxes” on the accompanying statements of income.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of December 31, 2007 and 2006, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of December 31, 2007 the fair value of our senior notes due 2017, which were issued in June 2007, were $237.5 million, or 95.0% of face value. Based upon quoted market prices as of December 31, 2007 and 2006, the fair values of our senior notes due 2011 were $150.8 million, or 100.5% of face value, and $152.6 million, or 101.75% of face value.

Reclassification of Prior Period Balances. Certain reclassifications have been made to prior period amounts to conform to the current year presentation.

Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow the provisions of SFAS No. 130, “Reporting Comprehensive Income,” which establishes standards for reporting comprehensive income. In addition to net income, comprehensive income or loss includes all changes to equity during a period, except those resulting from investments and distributions to the owners of the Company. At December 31, 2007, we recorded $0.4 million, net of taxes of less than $0.2 million, of derivative losses in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying balance sheet. The components of accumulated other comprehensive Income (loss) and related tax effects for 2007 were as follows (in thousands):

	Gross Value			Tax Effect			Net of Tax Value

Other comprehensive income at December 31, 2006	$	503		$	(187	)	$	316
Change in fair value of cash flow hedges		(842	)		312			(530	)
Effect of cash flow hedges settled during the period		(319	)		119			(200	)
Other comprehensive income at December 31, 2007	$	(658	)	$	244		$	(414	)

Total comprehensive income was $20.6 million, $162.0 million, and $115.3 million for 2007, 2006, and 2005, respectively.

Stock Based Compensation. Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (SFAS) No. 123 (R), “Share-Based Payment” (SFAS No. 123R) utilizing the modified prospective approach. Under the modified prospective approach, SFAS No. 123R applies to new awards and to awards that were outstanding on January 1, 2006, as well as those that are subsequently modified, repurchased or cancelled. Under the modified prospective approach, compensation cost recognized for the years ended December 31, 2007 and 2006 includes compensation cost for all share-based awards granted prior to, but not yet vested as of January 1, 2006, based on the grant-date fair value estimated in accordance with the original provisions of SFAS No. 123, and compensation cost for all share-based awards granted subsequent to January 1, 2006, based on the grant-date fair value estimated in accordance with the provisions of SFAS No. 123R. Prior periods were not restated to reflect the impact of adopting SFAS No. 123R.

We have three stock-based compensation plans, which are described more fully in Note 6.

Prior to 2006, we accounted for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. No stock-based employee compensation cost is reflected in net income for employee stock options prior to 2006, as all options granted under those plans had an exercise price equal to the fair market value of the underlying common stock on the date of the grant; or in the case of the employee stock purchase plan, the purchase price is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year. Had compensation expense for these plans been determined based on the fair value of the options consistent with SFAS No. 123, “Accounting for Stock-Based Compensation,” our net income and earnings per share would have been adjusted to the following pro forma amounts (in thousands, except per share amounts):

		2005
Net Income:	As Reported	$	115,778
	Stock-based employee compensation expense determined under fair value method for all awards, net of tax		(2,712	)
	Pro Forma	$	113,066

Basic EPS:	As Reported	$	4.06
	Pro Forma	$	3.97

Diluted EPS:	As Reported	$	3.95
	Pro Forma	$	3.86

Pro forma compensation cost reflected above may not be representative of the cost to be expected in future years. The fair value of each option grant, as opposed to its exercise price, is estimated on the date of grant using the Black-Scholes-Merton option-pricing model with the following weighted average assumptions in 2007, 2006, and 2005, respectively: no dividend yield; expected volatility factors of 38.5%, 39.3%, and 41.6%; risk-free interest rates of 4.7%, 4.8%, and 3.8%; and expected lives of 6.0, 4.8, and 3.9 years. We viewed all awards of stock compensation as a single award with an expected life equal to the average expected life of underlying awards and amortized the award on a straight-line basis over the life of the award.

Asset Retirement Obligation. In June 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” The statement requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the period in which it is incurred. When the liability is initially recorded, the carrying amount of the related long-lived asset is increased. The liability is discounted from the year the well is expected to deplete. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the estimated oil and natural gas reserves of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the full costs balance. This standard requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values. Based on our experience and analysis of the oil and gas services industry, we have not factored a market risk premium into our asset retirement obligation.

The following provides a roll-forward of our asset retirement obligation (in thousands):

Asset Retirement Obligation as of January 1, 2005	$13,987
Accretion expense for 2005	626
Liabilities incurred for new wells and facilities construction	142
Liabilities incurred for acquisitions	426
Reductions due to sold and abandoned wells	(465)
Revisions in estimated cash flows	708
Asset Retirement Obligation as of December 31, 2005	$15,424
Accretion expense for 2006	884
Liabilities incurred for new wells and facilities construction	190
Liabilities incurred for acquisitions	12,207
Reductions due to sold and abandoned wells	(177)
Revisions in estimated cash flows	265
Asset Retirement Obligation as of December 31, 2006	$28,793
Accretion expense for 2007	1,438
Liabilities incurred for new wells and facilities construction	981
Liabilities incurred for acquisitions	620
Reductions due to sold and abandoned wells	(808)
Revisions in estimated cash flows	3,435
Asset Retirement Obligation as of December 31, 2007	$34,459

At December 31, 2007 and 2006, approximately $3.4 million and $0.3 million, respectively, of our asset retirement obligation is classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets.

New Accounting Pronouncements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes guidelines for measuring fair value and expands disclosures regarding fair value measurements. It does not create or modify any current GAAP requirements to apply fair value accounting. However, it provides a single definition for fair value that is to be applied consistently for all prior accounting pronouncements. SFAS No. 157 was effective for fiscal periods beginning after November 15, 2007. On February 12, 2008, the FASB delayed the effective date of SFAS No. 157 for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, at least annually. For Swift, this action defers the effective date for those assets and liabilities until January 1, 2009. We believe that the adoption of this statement will not have a material impact on our financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141(R), Business Combinations. SFAS No. 141(R) provides enhanced guidance related to the measurement of identifiable assets acquired, liabilities assumed and disclosure of information related to business combinations and their effect on the Company. This Statement, together with the International Accounting Standards Board’s IFRS 3, Business Combinations, completes a joint effort by the FASB and IASB to improve financial reporting about business combinations and promotes the international convergence of accounting standards. For Swift, SFAS No. 141(R) applies prospectively to business combinations in 2009 and is not subject to early adoption. We are currently evaluating the potential impact of SFAS No. 141(R) on business combinations and related valuations.

2. Earnings Per Share

Basic earnings per share (“Basic EPS”) have been computed using the weighted average number of common shares outstanding during the respective periods. Diluted earnings per share (“Diluted EPS”) for all periods also assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Certain of our stock options and restricted stock that would potentially dilute Basic EPS in the future were also antidilutive for the 2007, 2006, and 2005 periods and are discussed below.

The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the years ended December 31, 2007, 2006, and 2005 (in thousands, except per share amounts):

	2007						2006						2005
	Income from continuing operations		Shares		Per Share Amount		Income from continuing operations		Shares		Per Share Amount		Income from continuing operations		Shares		Per Share Amount
Basic EPS:
Net Income from continuing operations, and Share Amounts	$	152,588		29,984	$	5.09	$	151,074		29,265	$	5.16	$	97,880		28,496	$	3.43
Dilutive Securities:
Restricted Stock		--		218				--		169				--		62
Stock Options		--		438				--		582				--		737
Diluted EPS:
Net Income from continuing operations, and assumed Share conversions	$	152,588		30,640	$	4.98	$	151,074		30,016	$	5.03	$	97,880		29,295	$	3.34

Options to purchase approximately 1.4 million shares at an average exercise price of $28.47 were outstanding at December 31, 2007, while options to purchase 1.5 million shares at an average exercise price of $24.59 were outstanding at December 31, 2006, and options to purchase 2.1 million shares at an average exercise price of $21.28 were outstanding at December 31, 2005. Approximately 1.0 million, 1.0 million, and 0.1 million stock options to purchase shares were not included in the computation of Diluted EPS for the years ended December 31, 2007, 2006, and 2005, respectively, because these stock options were antidilutive, in that the sum of the stock option price, unrecognized compensation expense and excess tax benefits recognized as proceeds in the treasury stock method was greater than the average closing market price for the common shares during those periods. Employee restricted stock grants of 0.4 million shares, 0.3 million shares and less than 0.1 million shares, were not included in the computation of Diluted EPS for the year ended December 31, 2007, 2006, and 2005, respectively, because these restricted stock grants were antidilutive in that the sum of the unrecognized compensation expense and excess tax benefits recognized as proceeds under the treasury stock method was greater than the average closing market price for the common shares during that period.

3. Provision for Income Taxes

Income from continuing operations before taxes is as follows (in thousands):

	Year Ended December 31,
	2007		2005		2004

Income From Continuing Operations Before Income Taxes	$	244,556	$	248,308	$	156,129

The following is an analysis of the consolidated income tax provision (in thousands):

	Year Ended December 31,
	2007		2006		2005

Current:	$	6,902	$	2,860	$	644

Deferred		85,066		94,374		57,605

Total	$	91,968	$	97,234	$	58,249

Current taxes are primarily U.S. Federal income taxes. The Company has no continuing operations in foreign jurisdictions.

Reconciliations of income taxes computed using the U.S. Federal statutory rate to the effective income tax rates are as follows (in thousands):

	2007			2006			2005

Income taxes computed at U.S. statutory rate (35%)	$	85,595		$	86,908		$	54,645
State tax provisions, net of federal benefits		3,396			3,921			2,145
Cumulative impact of adjustments to net state income tax rate		---			1,547			1,008
Write-offs and valuation allowance of carryover tax assets		2,585			3,200			---
Other, net		392			1,658			451
Provision for income taxes	$	91,968		$	97,234		$	58,249
Effective rate		37.6	%		39.2	%		37.3	%

The primary upward adjustment in the effective tax rate above the U.S. statutory rate is the provision for state income taxes (computed net of the offsetting federal benefit), which were $3.4 million, $3.9 million and $2.1 million for 2007, 2006, and 2005, respectively. In 2007, the company recorded write-offs and valuation allowances totaling $2.6 million as discussed further below. In 2006 the Company recorded a valuation allowance of $3.2 million due to changes in the Company’s tax planning strategies. Additionally, the Company recorded adjustments to the cumulative state deferred tax liability in the amounts of $1.5 million and $1.0 million for 2006 and 2005, respectively.

The tax effects of temporary differences representing the net deferred tax liability (asset) at December 31, 2007 and 2006 were as follows (in thousands):

	2007		2006
Current deferred tax assets:
Alternative minimum tax credits	$	5,094	$	---
Unrealized stock compensation		2,403		---
Other		558		2,383

Total current deferred tax assets	$	8,055	$	2,383

Non-Current deferred tax assets:
Carryover items, net of valuation allowance	$	4,334	$	2,648
Unrealized stock compensation		1,294		2,680
Other		749		2,527

Total non-current deferred tax assets	$	6,377	$	7,855

Non-Current deferred tax liabilities:
Oil and gas exploration and development costs	$	307,083	$	218,924
Other		1,597		1,389

Total deferred tax liabilities	$	308,680	$	220,313

Net Non-Current deferred tax liabilities	$	302,303	$	212,458

The total change in the net non-current deferred liability from 2006 to 2007 was $89.8 million. This increase is primarily attributable to an $88.2 million increase in the deferred liability for accelerated tax deductions for oil and natural gas exploration and development costs.

Current deferred tax assets increased by $5.7 million, primarily due to alternative minimum tax credits of $5.1 million that are expected to be utilized during 2008. Changes in market prices for oil and natural gas along with other economic and operational factors could result in the current deferred tax assets not being fully utilized to reduce 2008 income taxes.

The primary non-current deferred tax assets are $4.3 million for State of Louisiana net operating loss carryovers. These loss carryforwards are scheduled to expire between 2013 and 2020.

Unrealized stock compensation accounts for $2.4 million in current deferred tax assets and $1.3 million in non-current deferred tax assets. These amounts are attributable to stock compensation expenses accrued for employee stock options and restricted stock that are not realized for income tax purposes until exercised (for stock options) or vested (for restricted stock). The actual tax deductions realized may be significantly different than the accrued amounts depending on the market value of the stock on the date of exercise or vesting.

There is also a deferred tax asset of $1.1 million for a capital loss carryforward which is fully offset by a valuation allowance. This carryover is scheduled to expire in 2010. At the end of 2006 the Company had total capital loss carryforward assets of $6.1 million which included $5.0 million that expired at the end of 2007. At the end of 2006, the tax asset net of valuation allowances was $2.4 million. During 2007, the Company elected not to pursue previously planned property dispositions that would have utilized these loss carryforwards. Accordingly, tax expense was increased in 2007 to adjust for the carryovers that expired and to reserve a full valuation allowance against the unexpired portion.

On January 1, 2007, we adopted the recognition and disclosure provisions of FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"). Under FIN 48, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. As a result of adopting FIN 48, we reported a $1.0 million decrease to our January 1, 2007 retained earnings balance and a corresponding increase to our other long-term liabilities.

The $1.0 million decrease is also the total balance of our unrecognized tax benefits, which would impact our effective tax rate if recognized. We do not anticipate any significant increases or decreases in unrecognized tax benefits during 2008. Our policy is to record interest and penalties relating to income taxes in income tax expense. As of December 31, 2007, no interest or penalties relating to income taxes have been incurred or recognized. Our cumulative interest exposure on unrecognized tax benefits is not material.

There were no changes to unrecognized tax benefits recorded during 2007.

4. Long-Term Debt

Our long-term debt as of December 31, 2007 and 2006, is as follows (in thousands):

	2007		2006
Bank Borrowings	$	187,000	$	31,400
7-5/8% senior notes due 2011		150,000		150,000
9-3/8% senior subordinated notes due 2012		---		200,000
7-1/8% senior notes due 2017		250,000		---
Long-Term Debt	$	587,000	$	381,400

Bank Borrowings. At December 31, 2007, we had borrowings of $187.0 million under our $500.0 million credit facility with a syndicate of ten banks that has a borrowing base of $400.0 million, based entirely on assets from continuing operations, and expires in October 2011. At December 31, 2006, we had borrowings of $31.4 million under our credit facility. The interest rate is either (a) the lead bank’s prime rate (7.25% at December 31, 2007) or (b) the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin depending on the level of outstanding debt. The applicable margin is based on the ratio of the outstanding balance to the last calculated borrowing base. In October 2006, we increased, renewed and extended this credit facility, increasing the facility to $500 million from $400 million, increasing the commitment amount under the borrowing base to $250 million from $150 million, and extending its expiration to October 3, 2011 from October 1, 2008. The other terms of the credit facility stayed largely the same. In April 2007 we increased the borrowing base to $350.0 million; and effective November 2007, we further increased it to $400.0 million. In September 2007, we increased the commitment amount under the borrowing base to $350.0 million from $250.0 million. The covenants related to this credit facility changed somewhat with the extension of the facility and are discussed below. We incurred $0.3 million of debt issuance costs related to the increase of the commitment amount in 2007, and $0.6 million of debt issuance costs related to the extension of this facility in 2006, which is included in “Debt issuance costs” on the accompanying consolidated balance sheets and will be amortized to interest expense over the life of the facility.

The terms of our credit facility include, among other restrictions, a limitation on the level of cash dividends (not to exceed $15.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $50.0 million, requirements as to maintenance of certain minimum financial ratios (principally pertaining to adjusted working capital ratios and EBITDAX), and limitations on incurring other debt or repurchasing our 7-5/8% senior notes due 2011. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and natural gas properties. Under the terms of the credit facility, we can increase this commitment amount to the total amount of the borrowing base at our discretion, subject to the terms of the credit agreement. The borrowing base amount is re-determined at least every six months and the next scheduled borrowing base review is in May 2008.

Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $6.1 million in 2007, $1.5 million in 2006, and $1.0 million in 2005. The amount of commitment fees included in interest expense, net was $0.5 million in 2007, $0.6 million in 2006 and $0.5 million in 2005.

Senior Notes Due 2011. These notes consist of $150.0 million of 7-5/8% senior notes, which were issued on June 23, 2004 at 100% of the principal amount and will mature on July 15, 2011. The notes are senior unsecured obligations that rank equally with all of our existing and future senior unsecured indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank credit facility, and rank senior to all of our existing and future subordinated indebtedness. Interest on these notes is payable semi-annually on January 15 and July 15, and commenced on January 15, 2005. On or after July 15, 2008, we may redeem some or all of the notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.813% of principal, declining to 100% in 2010 and thereafter. We incurred approximately $3.9 million of debt issuance costs related to these notes, which is included in “Debt issuance costs” on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. Upon certain changes in control of Swift Energy, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these senior notes.

Interest expense on the 7-5/8% senior notes due 2011, including amortization of debt issuance costs totaled $12.0 million in 2007 and $11.9 million in both 2006 and 2005.

Senior Subordinated Notes Due 2012. These notes consisted of $200.0 million of 9-3/8% senior subordinated notes due May 2012, which were issued on April 16, 2002 and were scheduled to mature on May 1, 2012. Interest on these notes was payable semiannually on May 1 and November 1. As of June 18, 2007, we redeemed all $200.0 million of these notes. In the second quarter of 2007, we recorded a charge of $12.8 million related to the redemption of these notes, which is recorded in “Debt retirement costs” on the accompanying consolidated statement of income. The costs were comprised of approximately $9.4 million of premium paid to redeem the notes, and $3.4 million to write-off unamortized debt issuance costs.

Interest expense on the 9-3/8% senior subordinated notes due 2012, including amortization of debt issuance costs totaled $8.9 million in 2007 and $19.2 million in both 2006 and 2005.

Senior Notes Due 2017. These notes consist of $250.0 million of 7-1/8% senior notes due 2017, which were issued on June 1, 2007 at 100% of the principal amount and will mature on June 1, 2017. The notes are senior unsecured obligations that rank equally with all of our existing and future senior unsecured indebtedness, are effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank credit facility, and will rank senior to any future subordinated indebtedness of Swift Energy. Interest on these notes is payable semi-annually on June 1 and December 1, and commencing on December 1, 2007. On or after June 1, 2012, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.563% of principal, declining in twelve-month intervals to 100% in 2015 and thereafter. In addition, prior to June 1, 2010, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 107.125% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $4.2 million of debt issuance costs related to these notes, which is included in “Debt issuance costs” on the accompanying balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. In the event of certain changes in control of Swift Energy, each holder of notes will have the right to require us to repurchase all or any part of the notes at a purchase price in cash equal to 101% of the principal amount, plus accrued and unpaid interest to the date of purchase. The terms of these notes include, among other restrictions, a limitation on how much of our own common stock we may repurchase. We are currently in compliance with the provisions of the indenture governing these senior notes.

Interest expense on the 7-1/8% senior notes due 2017, including amortization of debt issuance costs, totaled $10.6 million for the year ended December 31, 2007.

The maturities on our long-term debt are $0 for 2008, 2009 and 2010, $337 million for 2011, and $250 million thereafter.

We have capitalized interest on our unproved properties in the amount of $9.5 million, $9.2 million, and $7.2 million, in 2007, 2006, and 2005, respectively.

5. Commitments and Contingencies

Rental and lease expenses which were included in “General and administrative, net” on our accompanying consolidated statements of income were $3.7 million in 2007, $2.7 million in 2006, and $2.5 million in 2005. Rental and lease expenses which were included in “Lease operating cost” on our accompanying consolidated statements of income were $6.7 million in 2007, $3.6 million in 2006, and $1.9 million in 2005. Our remaining minimum annual obligations under non-cancelable operating lease commitments are $7.7 million for 2008, $4.9 million for 2009 and $3.4 million for 2010, $3.2 million for both 2011 and 2012, and $7.0 million thereafter or $29.3 million in the aggregate. The rental and lease expenses and remaining minimum annual obligations under non-cancelable operating lease commitments primarily relate to the lease of our office space in Houston, Texas which is a ten year lease and expires in 2015.

In the ordinary course of business, we have entered into agreements with drilling contractors for such services and tubing and pipe inventory commitments. The remaining commitments at December 31, 2007 for these services and materials totaled $34.2 million for 2008.

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 natural gas wells. In management’s 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.

6. Stockholders’ Equity

Stock-Based Compensation Plans. We have three stock option plans that awards are currently granted under, the 2005 Stock Compensation Plan, which was adopted by our Board of Directors in March 2005 and was approved by shareholders at the 2005 annual meeting of shareholders, the 2001 Omnibus Stock Compensation Plan, which was adopted by our Board of Directors in February 2001 and was approved by shareholders at the 2001 annual meeting of shareholders, and the 1990 Non-Qualified Stock Option Plan solely for our independent directors. No further grants, other than stock option reload grants, will be made under the 2001 Omnibus Stock Compensation Plan or the 1990 Non-Qualified Stock Option Plan, both of which were replaced by the 2005 Stock Compensation Plan, although options remain outstanding under both plans and are accordingly included in the tables below. In addition, we have an employee stock purchase plan and an employee stock ownership plan.

Under the 2005 plan, stock options and other equity based awards may be granted to employees, directors, and consultants, with directors only eligible to receive restricted awards. Under the 2001 plan, stock options and other equity based awards may be granted to employees. The 1990 non-qualified plan, non-employee members of our Board of Directors were automatically granted options to purchase shares of common stock on a formula basis. All three plans provide that the exercise prices equal 100% of the fair value of the common stock on the date of grant. Restricted stock grants become vested in various terms ranging from three years to five years, stock options become exercisable in various terms ranging from one year to five years. Options granted typically expire ten years after the date of grant or earlier in the event of the optionee’s separation from employment. At the time the stock options are exercised, the cash received is credited to common stock and additional paid-in capital. Options issued under these plans also include a reload feature where additional options are granted at the then current market price when mature shares of Swift Energy common stock are used to satisfy the exercise price of an existing stock option grant. When Swift Energy common stock is used to satisfy the exercise price, the net shares actually issued are reflected in the accompanying Statement of Stockholders’ Equity (see note 1 to table below). We view all awards of stock compensation as a single award with an expected life equal to the average expected life of component awards and amortize the award on a straight-line basis over the life of the award.

The employee stock purchase plan, which began in 1993, provides eligible employees the opportunity to acquire shares of Swift Energy common stock at a discount through payroll deductions. Through May 31, 2006, the prior plan year was from June 1 to the following May 31. A transition period from June 1 to December 31 was used during the second half of 2006 and a new plan year, from January 1 to December 31, began being used in 2007. To date, employees have been allowed to authorize payroll deductions of up to 10% of their base salary during the plan year by making an election to participate prior to the start of a plan year. The purchase price for stock acquired under the plan is 85% of the lower of the closing price of our common stock as quoted on the New York Stock Exchange at the beginning or end of the plan year (or a date during the year chosen by the participant through the plan year, for plan years ending on or before May 31, 2006). Under this plan for the last three years, we have issued 17,678 shares at a price of $35.00 in 2007, 22,425 shares at a price range of $29.84 to $32.80 in 2006, and 32,495 shares at a price range of $15.56 to $18.12 in 2005. As of December 31, 2007, 58,721 shares remained available for issuance under this plan.

As a result of adopting SFAS No. 123R on January 1, 2006, our income from continuing operations before income taxes, income from continuing operations, net income and basic and diluted earnings per share for the year ended December 31, 2006, were $3.4 million, $2.8 million, $2.8 million, $0.09, and $0.09 lower, respectively. Upon adoption of SFAS 123R, we recorded an immaterial cumulative effect of a change in accounting principle as a result of our change in policy from recognizing forfeitures as they occur to one recognizing expense based on our expectation of the amount of awards that will vest over the requisite service period for our restricted stock awards. This amount was recorded in “General and Administrative, net” in the accompanying consolidated statements of income.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the stock is sold over the exercise price of the options. In addition, we receive an additional tax deduction when restricted stock vests at a higher value than the value used to recognize compensation expense at the date of grant. Prior to adoption of SFAS No. 123R, we reported all tax benefits resulting from the award of equity instruments as operating cash flows in our consolidated statements of cash flows. In accordance with SFAS No. 123R, we are required to report excess tax benefits from the award of equity instruments as financing cash flows. These benefits were $3.3 million for the year ended December 31, 2006. For 2007 an estimated excess benefit of $0.6 million has been realized and credited to paid-in capital. Unrealized benefits of $1.2 million will not be recognized until the period in which the related carryover tax assets are realized.

Net cash proceeds from the exercise of stock options were $3.2 million and $11.8 million for the years ended December 31, 2007 and 2006. The actual income tax benefit from stock option exercises was $1.9 million and $4.8 million for the same periods.

Stock compensation expense for both stock options and restricted stock issued to both employees and non-employees is recorded in “General and Administrative, net” in the accompanying consolidated statements of income, and was $9.4 million, $6.3 million, and $1.5 million for the years ended December 31, 2007, 2006, and 2005 respectively. We also capitalized $4.2 million, $3.4 million, and $1.0 million of stock compensation in 2006, 2005, and 2004, respectively.

Our shares available for future grant under our stock compensation plans were 714,103 at December 31, 2007. Each stock option granted reduces the aforementioned total by one share, while each restricted stock grant reduces the shares available for future grant by 1.44 shares.

Stock Options. We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards with the following weighted-average assumptions for the indicated periods.

	Years Ended December 31,
	2007	2006	2005

Dividend yield	0%	0%	0%
Expected volatility	38.5%	39.3%	41.6%
Risk-free interest rate	4.7%	4.8%	3.8%
Expected life of options (in years)	6.0	4.8	3.9
Weighted-average grant-date fair value	$19.61	$18.03	$12.84

The expected term has been calculated using the Securities and Exchange Commission Staff’s shortcut approach from Staff Accounting Bulletin No. 107. We have analyzed historical volatility and based on an analysis of all relevant factors use a three-year period to estimate expected volatility of our stock option grants.

At December 31, 2007, $2.9 million of unrecognized compensation cost related to stock options is expected to be recognized over a weighted-average period of 1.5 years.

The following table represents stock option activity for the years ended December 31, 2007, 2006 and 2005:

	2007		2006		2005
	Shares	Wtd Avg. Exer. Price	Shares	Wtd, Avg. Exer. Price	Shares	Wtd. Avg. Exer. Price

Options outstanding, beginning of period	1,549,140	$24.59	2,118,179	$21.28	2,998,668	$18.51
Options granted	201,691	$43.40	234,110	$45.73	176,262	$35.17
Options canceled	(41,800)	$37.15	(51,739)	$22.25	(45,142)	$18.94
Options exercised1	(259,791)	$18.13	(751,410)	$22.02	(1,011,609)	$9.78
Options outstanding, end of period	1,449,240	$28.47	1,549,140	$24.59	2,118,179	$21.28
Options exercisable, end of period	967,429	$25.70	884,876	$22.60	1,085,509	$20.98

The aggregate intrinsic value and weighted average remaining contract life of options outstanding and exercisable at December 31, 2007 was $23.2 million and 5.2 years and $18.3 million and 4.1 years, respectively. The total intrinsic value of options exercised during the year ended December 31, 2007 was $6.1 million.

The following table summarizes information about stock options outstanding at December 31, 2007:

	Options Outstanding			Options Exercisable
Range of Exercise Prices	Number Outstanding at 12/31/06	Wtd. Avg. Remaining Contractual Life	Wtd. Avg. Exercise Price	Number Exercisable at 12/31/06	Wtd. Avg. Exercise Price
$ 6.00 to $20.99	503,471	4.7	$13.64	401,371	$13.35
$21.00 to $35.99	473,870	4.4	$28.14	382,790	$28.88
$36.00 to $52.00	471,899	6.6	$44.62	183,268	$46.08
$ 6.00 to $52.00	1,449,240	5.2	$28.47	967,429	$25.70

1 The plans allow for the use of a “stock swap” in lieu of a cash exercise for options, under certain circumstances. The delivery of Swift Energy common stock, held by the optionee for a minimum of six months, which are considered mature shares, with a fair market value equal to the required purchase price of the shares to which the exercise relates, constitutes a valid “stock swap.” Options issued under a “stock swap” also include a reload feature where additional options are granted at the then current market price when mature shares of Swift stock are used to satisfy the exercise price of an existing stock option grant. The terms of the plans provide that the mature shares delivered, as full or partial payment in a “stock swap”, shall again be available for awards under the plans. In 2007, 2006 and 2005 respectively, 19,191, 98,581 and 170,762 mature shares were delivered in “stock swap” transactions, which resulted in the issuance of an equal number of reload option grants.

Restricted Stock. In 2007, 2006 and 2005, the Company issued 329,290, 324,640 and 158,500 shares, respectively, of restricted stock to employees, consultants, and directors. These shares vest over a three-year to five-year period and remain subject to forfeiture if vesting conditions are not met. The fair value of these shares when issued was approximately $43 per share in 2007 and 2006 and $38 per share in 2005.

The compensation expense for these awards was determined based on the market price of our stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of December 31, 2007, we have unrecognized compensation expense of approximately $16.2 million associated with these awards which are expected to be recognized over a weighted-average period of 1.6 years. The total fair value of shares vested during the year ended December 31, 2007 was $7.5 million.

The following is a summary of our restricted stock issued to employees, consultants, and directors under these plans as of December 31, 2007, 2006, and 2005:

	2007		2006		2005
	Shares	Wtd. Avg. Grant Price	Shares	Wtd. Avg.Grant Price	Shares	Wtd. Avg. Grant Price

Restricted shares outstanding, beginning of period	503,184	$40.04	236,950	$34.79	100,900	$23.92
Restricted shares granted	329,290	$43.17	324,640	$43.21	158,500	$38.31
Restricted shares canceled	(47,595)	$39.63	(22,630)	$38.01	(7,450)	$39.03
Restricted shares vested	(188,289)	$40.05	(35,776)	$24.57	(15,000)	$---
Restricted shares outstanding, end of period	596,590	$41.60	503,184	$40.04	236,950	$34.79

Employee Stock Ownership Plan. In 1996, we established an Employee Stock Ownership Plan (“ESOP”) effective January 1, 1996. All employees over the age of 21 with one year of service are participants. This plan has a five-year cliff vesting. The ESOP is designed to enable our employees to accumulate stock ownership. While there will be no employee contributions, participants will receive an allocation of stock that has been contributed by Swift Energy. Compensation expense is recognized upon vesting when such shares are released to employees. The plan may also acquire Swift Energy common stock, purchased at fair market value. The ESOP can borrow money from Swift Energy to buy Swift Energy common stock. ESOP payouts will be paid in a lump sum or installments, and the participants generally have the choice of receiving cash or stock. At December 31, 2007, 2006, and 2005, all of the ESOP compensation was earned. Our contribution to the ESOP plan totaled $0.4 million for the years ended December 31, 2007 and 2006 and $0.2 million for the year ended December 31, 2005, and were made all in common stock, and are recorded as “General and administrative, net” on the accompanying consolidated statements of income. The shares of common stock contributed to the ESOP plan totaled 9,218, 8,927, and 4,438 shares for the 2007, 2006, and 2005 contributions, respectively.

Employee Savings Plan. We have a savings plan under Section 401(k) of the Internal Revenue Code. Eligible employees may make voluntary contributions into the 401(k) savings plan with Swift contributing on behalf of the eligible employee an amount equal to 100% of the first 2% of compensation and 75% of the next 4% of compensation based on the contributions made by the eligible employees. Our contributions to the 401(k) savings plan were $1.3 million for 2007, $1.0 million for 2006, and $0.8 million for 2005, and are recorded as “General and administrative, net” on the accompanying consolidated statements of income. The contributions in 2007, 2006, and 2005 were made all in common stock. The shares of common stock contributed to the 401(k) savings plan totaled 29,934, 23,890, and 17,920 shares for the 2007, 2006, and 2005 contributions, respectively.

Treasury Shares. In March 1997, our Board of Directors approved a common stock repurchase program that terminated as of June 30, 1999. Under this program, we spent approximately $13.3 million to acquire 927,774 shares in the open market at an average cost of $14.34 per share. At December 31, 2007, 436,414 shares remain in treasury (net of 533,505 shares used to fund the ESOP, 401(k) contributions and acquisitions) with a total cost of $7.5 million and are included in “Treasury stock held, at cost” on the accompanying consolidated balance sheets.

Shareholder Rights Plan. Our Rights Agreement was initially adopted by the Board of Directors in 1997 for a ten year term. The Board of Directors renewed and extended the Rights Agreement for an additional ten year term from December 21, 2006. Pursuant to the Rights Agreement as amended, for each share of Swift Energy common stock a holder has the right to purchase one one-thousandth of a share of Swift Energy preferred stock for $250 upon the occurrence of certain events triggered when a person or entity purchases 15% or more beneficial ownership of Swift Energy’s outstanding common stock. The rights are not exercisable by such 15% or more beneficial owner.

7. Related-Party Transactions

We receive research, technical writing, publishing, and website-related services from Tec-Com Inc., a corporation located in Knoxville, Tennessee and controlled and majority owned by the aunt of the Company’s Chairman of the Board and Chief Executive Officer. We paid approximately $0.6 million to Tec-Com for such services pursuant to the terms of the contract in 2007, $0.5 million in 2006 and $0.4 million in 2005. The contract was renewed on June 30, 2007 on substantially the same terms as the previous contract and expires June 30, 2010. We believe that the terms of this contract are consistent with third party arrangements that provide similar services.

As a matter of corporate governance policy and practice, related party transactions are annually presented and considered by the Corporate Governance Committee of our Board of Directors in accordance with the Committee’s charter.

8. Discontinued Operations

In December 2007, Swift agreed to sell substantially all of our New Zealand assets for approximately $87.8 million. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of income and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. We began a strategic review of our New Zealand assets in the second quarter of 2007 which culminated in the agreement to sell substantially all of these assets, with an expected closing towards the end of the first quarter of 2008. Proceeds from the New Zealand assets sale will most likely be used to pay down a portion of our credit facility.

We expect to sell our remaining permit in New Zealand sometime in 2008. The remaining book value for this permit is approximately $0.5 million which we believe is less than the current fair value of the property. If net proceeds from the sale of this permit exceed $0.5 million then a gain on sale of property will be recorded. If net proceeds from the sale of this permit are less than $0.5 million then a loss on sale of property will be recorded.

The following table summarizes the amounts included in income (loss) from discontinued operations for all periods presented. These revenues and expenses were historically reported under our New Zealand operating segment, and are now reported in discontinued operations (in thousands except per share amounts):

	2007			2006		2005
Oil and gas sales	$	42,394		$	64,039	$	67,894
Other revenues		1,221			862		999
Total revenues		43,615			64,901		68,893

Depreciation, depletion, and amortization		23,147			30,051		26,354
Other operating expenses		22,491			20,872		20,230
Non-cash write-down of property and equipment		143,152			---		---
Total expenses		188,790			50,923		46,584

Income (loss) from discontinued operations before income taxes		(145,175	)		13,978		22,309
Income tax expense (benefit)		(13,874	)		3,487		4,412
Income (loss) from discontinued operations, net of taxes	$	(131,301	)	$	10,491	$	17,898

Earnings per common share from discontinued operations-diluted	$	(4.29	)	$	0.35	$	0.61
Annual sales volumes (MBoe)		1,387			2,252		2,758
Total assets	$	110,585		$	235,997	$	241,943
Cash flow provided by operating activities	$	25,620		$	41,680	$	48,543
Capital expenditures	$	9,466		$	56,707	$	50,844

For the years 2007, 2006, and 2005, our capitalized general and administrative expenses totaled $4.2 million, $4.1 million, and $4.3 million.

Total income taxes differed from the amount computed by applying the statutory income tax rate to income from discontinued operations. The sources of these differences are as follows (in thousands):

	2007			2006			2005
Income (loss) before tax from discontinued operations	$	(145,175	)	$	13,978		$	22,309

Income taxes computed at U.S. statutory rate (35%)	$	(50,811	)	$	4,892		$	7,809
Effect of foreign operations		6,336			(293	)		(452	)
Currency exchange impact on foreign tax calculation		(1,659	)		(1,346	)		(2,769	)
Valuation allowance		33,502			---			---
Other		(1,242	)		234			(176	)

Total income tax expense related to discontinued operations	$	(13,874	)	$	3,487		$	4,412
Effective tax rate		9.6	%		24.9	%		19.8	%

The tax effects of temporary differences that give rise to significant portions of the deferred assets (liabilities) associated with assets held for sale at December 31, 2007 and 2006 are as follows (in thousands):

	2007		2006
Non-Current deferred tax assets
Loss carryover items net of valuation allowance	$	—	$	(55,197	)
Other		—		(1,204	)

Total deferred tax assets		—		(56,401	)

Non-current deferred tax liabilities
Oil and gas exploration and development costs		—		68,910

Total deferred tax liabilities		—		68,910

Net Deferred tax liabilities	$	—	$	12,509

The 2007 write-down of properties held for sale resulted in an estimated net deferred tax asset balance of $33.5 million, calculated using the New Zealand tax rate of 30%. This estimated net asset is attributable to New Zealand tax loss carryovers in excess of the amounts that will be utilized to offset the proceeds from the $87.8 million asset sale. As of December 31, 2007, management assessed that the probability of generating additional taxable income to utilize these loss carryovers was less than more likely than not. Accordingly, the provision for income tax for discontinued operations includes a valuation allowance charge for the full amount of the deferred tax asset. If the Company’s remaining assets are sold in excess of tax basis, these loss carryovers will be available to offset such a gain.

Until the decision was made to sell the Company’s New Zealand assets, no provision had been made for U.S. income tax on New Zealand earnings. Management had maintained a plan to reinvest earnings from New Zealand indefinitely. Because of the losses on liquidation, we anticipate that the distribution of sales proceeds to the U.S. will be deemed a return of capital for U.S. income tax purposes. Accordingly, no provision has been made for U.S. income tax.

The following presents the main classes of assets and liabilities associated with the New Zealand operations that are held for sale as of December 31, 2007 and 2006 (in thousands).

	2007		2006
ASSETS
Property and equipment, net	$	96,549	$	---
Total Current assets held for sale	$	96,549	$	---
Property and equipment, net		---	$	252,380
Total Long-term assets held for sale	$	---	$	252,380
LIABILITIES
Asset retirement obligation	$	8,066	$	---
Deferred income taxes		—		---
Total Current liabilities associated with assets held for sale	$	8,066	$	---
Asset retirement obligation	$	—	$	5,666
Deferred income taxes		—		12,509
Total Long-term liabilities associated with assets held for sale	$	—	$	18,175

9. Acquisitions and Dispositions

In October 2007, we acquired interests in three South Texas fields in the Maverick Basin from Escondido Resources, LP. The property interests are located in the Sun TSH field in La Salle County, the Briscoe Ranch field primarily in Dimmit County, and the Las Tiendas field in Webb County. We refer to these properties as the Cotulla properties. We paid approximately $248.2 million in cash for these interests including purchase price adjustments. After taking into account internal acquisition costs of $2.5 million, our total cost was $250.7 million. We allocated $241.8 million of the acquisition price to “Proved Properties,” $8.9 million to “Unproved Properties,” and recorded a liability for $0.6 million to “Asset retirement obligation” on our accompanying consolidated balance sheet. These acquisitions were accounted for by the purchase method of accounting. We made these acquisitions to increase our exploration and development opportunities in South Texas. The revenues and expenses from these properties have been included in our accompanying consolidated statement of income from the date of acquisition forward; however, given that the acquisitions closed in the fourth quarter of 2007, these amounts were not material to our full year 2007 results.

In October 2006, we acquired interests in five South Louisiana fields. The property interests are located in: Bayou Sale, Horseshoe Bayou and Jeanerette fields (all located in St. Mary Parish), High Island field in Cameron Parish and Bayou Penchant field in Terrebonne Parish. We paid approximately $167.9 million in cash for these interests. After taking into account internal acquisition costs of $4.0 million, our total cost was $171.9 million. We allocated $143.1 million of the acquisition price to “Proved Properties,” $28.8 million to “Unproved Properties,” and recorded a liability for $11.5 million to “Asset retirement obligation” on our accompanying consolidated balance sheet. These acquisitions were accounted for by the purchase method of accounting. We made these acquisitions to increase our exploration and development opportunities in South Louisiana. The revenues and expenses from these properties have been included in our accompanying consolidated statements of income from the date of acquisition forward; however, given the acquisitions closed in the fourth quarter of 2006, these amounts were not material to our full year 2006 results.

In December 2006, we acquired additional interests in our Lake Washington field. We paid approximately $20.0 million in cash for these interests. After taking into account internal acquisition costs of $0.4 million, our total cost was $20.4 million. We allocated $17.9 million of the acquisition price to “Proved Properties,” $2.5 million to “Unproved Properties,” and recorded a liability for $0.8 million to “Asset retirement obligation” on our accompanying consolidated balance sheet. This acquisition was accounted for by the purchase method of accounting. We made this acquisition to increase our exploration and development opportunities in South Louisiana. The revenues and expenses from this acquisition have been included in our accompanying consolidated statements of income from the date of acquisition forward; however, given the acquisition closed in December 2006, these amounts were not material to our full year 2006 results.

In April 2006, we sold our minority interest in the Brookeland natural gas processing plant for approximately $20.3 million in cash. Under the “full-cost” method of accounting for oil and natural gas property and equipment costs, the proceeds of this sale were applied against our oil and natural gas properties and equipment balance, and no gain or loss was recognized on this transaction.

In November 2005, we acquired interests in the South Bearhead Creek field in Central Louisiana. We paid approximately $24.3 million in cash for these interests. After taking into account internal acquisition costs of $2.6 million and assumed liabilities of $1.4 million, our total cost was $28.3 million. We allocated $26.2 million of the acquisition price to “Proved Properties,” $2.5 million to “Unproved Properties,” and recorded a liability for $0.4 million to “Asset retirement obligation” on our accompanying consolidated balance sheet. In December 2006, we acquired additional interests in this field. We paid approximately $4.5 million in cash for these additional interests. After taking into account internal acquisition costs of $0.1 million, our total cost was $4.6 million. We allocated $4.1 million of the acquisition price to “Proved Properties” and $0.5 million to “Unproved Properties” on our accompanying consolidated balance sheet. These acquisitions were accounted for by the purchase method of accounting. We made these acquisitions to increase our exploration and development opportunities in this area. The revenues and expenses from these properties have been included in our accompanying consolidated statements of income from the date the acquisition closed. However, given the acquisitions closed in November 2005 and December 2006, these amounts were immaterial for both the 2005 and 2006 periods.

10. Condensed Consolidating Financial Information

In December 2005, we amended the indenture for our 9-3/8% Senior Subordinated Notes due 2012, which were redeemed in June 2007, and our 7-5/8% Senior Notes due 2011 to reflect our new holding company organizational structure (as discussed in Note 1). As part of this restructuring our indentures were amended so that both Swift Energy Company and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of Swift Energy Company) became co-obligors of these senior notes and senior subordinated debt. The co-obligations on our Notes due 2011 are full and unconditional and are joint and several. Prior to this restructure, Swift Energy Company was the sole obligor. The following is condensed consolidating financial information for Swift Energy Company, Swift Energy Operating, LLC, and other subsidiaries:

Condensed Consolidating Balance Sheets

(in thousands)	December 31, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

ASSETS

Current assets	$	---	$	89,513	$	110,437	$	---		$	199,950
Property and equipment		---		1,760,195		---		---			1,760,195
Investment in subsidiaries (equity method)		836,054		---		760,158		(1,596,212	)		---
Other assets		---		28,828		---		(19,922	)		8,906
Total assets	$	836,054	$	1,878,536	$	870,595	$	(1,616,134	)	$	1,969,051


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	195,542	$	34,541	$	(19,922	)	$	210,161
Long-term liabilities		---		922,836		---		---			922,836
Stockholders’ equity		836,054		760,158		836,054		(1,596,212	)		836,054
Total liabilities and stockholders’ equity	$	836,054	$	1,878,536	$	870,595	$	(1,616,134	)	$	1,969,051

(in thousands)	December 31, 2006
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

ASSETS

Current assets	$	---	$	75,270	$	8,513	$	---		$	83,783
Property and equipment		---		1,239,722		---		---			1,239,722
Investment in subsidiaries (equity method)		797,917		---		590,720		(1,388,637	)		---
Other assets		---		42,519		253,085		(33,427	)		262,177
Total assets	$	797,917	$	1,357,511	$	852,318	$	(1,422,064	)	$	1,585,682


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	137,016	$	8,455	$	---		$	145,471
Long-term liabilities		---		629,775		45,946		(33,427	)		642,294
Stockholders’ equity		797,917		590,720		797,917		(1,388,637	)		797,917
Total liabilities and stockholders’ equity	$	797,917	$	1,357,511	$	852,318	$	(1,422,064	)	$	1,585,682

(in thousands)	December 31, 2005
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

ASSETS

Current assets	$	---	$	92,788	$	17,410	$	---		$	110,198
Property and equipment		---		862,717		---		---			862,717
Investment in subsidiaries (equity method)		607,318		---		410,612		(1,017,930	)		---
Other assets		---		31,955		221,855		(22,313	)		231,497
Total assets	$	607,318	$	987,460	$	649,877	$	(1,040,243	)	$	1,204,412


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	85,472	$	12,949	$	---		$	98,421
Long-term liabilities		---		491,376		29,610		(22,313	)		498,673
Stockholders’ equity		607,318		410,612		607,318		(1,017,930	)		607,318
Total liabilities and stockholders’ equity	$	607,318	$	987,460	$	649,877	$	(1,040,243	)	$	1,204,412

Condensed Consolidating Statements of Income

(in thousands)	Year Ended December 31, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)			Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Revenues	$	---		$	654,121	$	---		$	---		$	654,121
Expenses		---			409,565		---			---			409,565

Income (loss) before the following:		---			244,556		---			---			244,556
Equity in net earnings of subsidiaries		21,287			---		152,588			(173,875	)		---

Income from continuing operations, before income taxes		21,287			244,556		152,588			(173,875	)		244,556
Income tax provision (benefit)		---			91,968		---			---			91,968

Income from continuing operations		21,287			152,588		152,588			(173,875	)		152,588
Loss from discontinued operations, net of taxes		---			---		(131,301	)		---			(131,301	)

Net income	$	21,287		$	152,588	$	21,287		$	(173,875	)	$	21,287

(in thousands)	Year Ended December 31, 2006
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	550,836	$	---	$	---		$	550,836
Expenses		---		302,528		---		---			302,528

Income (loss) before the following:		---		248,308		---		---			248,308
Equity in net earnings of subsidiaries		161,565		---		151,074		(312,639	)		---

Income from continuing operations, before income taxes		161,565		248,308		151,074		(312,639	)		248,308
Income tax provision (benefit)		---		97,234		---		---			97,234

Income from continuing operations		161,565		151,074		151,074		(312,639	)		151,074
Income from discontinued operations, net of taxes		---		---		10,491		---			10,491

Net income	$	161,565	$	151,074	$	161,565	$	(312,639	)	$	161,565

(in thousands)	Year Ended December 31, 2005
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	354,365	$	---	$	---		$	354,365
Expenses		---		198,236		---		---			198,236

Income (loss) before the following:		---		156,129		---		---			156,129
Equity in net earnings of subsidiaries		115,778		---		97,880		(213,658	)		---

Income from continuing operations, before income taxes		115,778		156,129		97,880		(213,658	)		156,129
Income tax provision (benefit)		---		58,249		---		---			58,249

Income from continuing operations		115,778		97,880		97,880		(213,658	)		97,880
Income from discontinued operations, net of taxes		---		---		17,898		---			17,898

Net income	$	115,778	$	97,880	$	115,778	$	(213,658	)	$	115,778

Condensed Consolidating Statements of Cash Flow

(in thousands)	Year Ended December 31, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)			Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Cash flow from operations	$	---	$	442,282		$	25,620		$	---		$	467,902
Cash flow from investing activities		---		(636,501	)		(7,827	)		(13,358	)		(657,686	)
Cash flow from financing activities		---		194,349			(13,358	)		13,358			194,349

Net increase in cash		---		130			4,435			---			4,565
Cash, beginning of period		---		50			1,008			---			1,058

Cash, end of period	$	---	$	180		$	5,443		$	---		$	5,623

(in thousands)	Year Ended December 31, 2006
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)			Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Cash flow from operations	$	---	$	383,241		$	41,680		$	---		$	424,921
Cash flow from investing activities		---		(474,781	)		(59,881	)		11,115			(523,547	)
Cash flow from financing activities		---		46,679			11,115			(11,115	)		46,679

Net increase in cash		---		(44,861	)		(7,086	)		---			(51,947	)
Cash, beginning of period		---		44,911			8,094			---			53,005

Cash, end of period	$	---	$	50		$	1,008		$	---		$	1,058

(in thousands)	Year Ended December 31, 2005
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)			Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Cash flow from operations	$	---	$	236,791		$	48,543		$	---		$	285,334
Cash flow from investing activities		---		(194,909	)		(48,837	)		3,672			(240,074	)
Cash flow from financing activities		---		2,825			3,672			(3,672	)		2,825

Net increase in cash		---		44,706			3,379			---			48,085
Cash, beginning of period		---		205			4,715			---			4,920

Cash, end of period	$	---	$	44,911		$	8,094		$	---		$	53,005

Supplementary Information

Swift Energy Company and Subsidiaries

Oil and Gas Operations (Unaudited)

Capitalized Costs. The following table presents our aggregate capitalized costs relating to oil and natural gas producing activities and the related depreciation, depletion, and amortization (in thousands):

	Total			Domestic			Discontinued Operations
December 31, 2007:
Proved oil and gas properties	$	2,951,712		$	2,610,469		$	341,243
Unproved oil and gas properties		107,095			106,643			452
		3,058,807			2,717,112			341,695
Accumulated depreciation, depletion, and amortization		(1,234,401	)		(981,449	)		(252,952	)
Net capitalized costs	$	1,824,406		$	1,735,663		$	88,743
December 31, 2006:
Proved oil and gas properties	$	2,264,831		$	1,932,336		$	332,495
Unproved oil and gas properties		112,137			95,569			16,568
		2,376,968			2,027,905			349,063
Accumulated depreciation, depletion, and amortization		(915,397	)		(808,708	)		(106,689	)
Net capitalized costs	$	1,461,571		$	1,219,197		$	242,374

Of the $106.6 million of domestic Unproved property costs (primarily seismic and lease acquisition costs) at December 31, 2007, excluded from the amortizable base, $42.6 million was incurred in 2007, $49.2 million was incurred in 2006, $4.5 million was incurred in 2005, and $10.3 million was incurred in prior years. When we are in an active drilling mode, we evaluate the majority of these unproved costs within a two to four year time frame.

Of the $0.5 million of New Zealand Unproved property costs at December 31, 2007, excluded from the amortizable base, $0.1 million was incurred in 2007, $0.1 million was incurred in 2006, $0.1 million was incurred in 2005, and $0.2 million was incurred in prior years.

Capitalized asset retirement obligations have been included in the Proved properties as of December 31, 2007, 2006, and 2005.

Costs Incurred. The following table sets forth costs incurred related to our oil and natural gas operations (in thousands):

	Year Ended December 31, 2007
	Total		Domestic		Discontinued Operations
Acquisition of proved and unproved properties	$	253,573	$	253,573	$	--
Lease acquisitions and prospect costs1		62,380		56,901		5,479
Exploration		65,815		65,815		---
Development 2		330,866		326,879		3,987
Total acquisition, exploration, and development 3, 4	$	712,634	$	703,168	$	9,466

	Year Ended December 31, 2006
	Total		Domestic		Discontinued Operations
Acquisition of proved and unproved properties	$	212,499	$	212,499	$	--
Lease acquisitions and prospect costs1		79,183		68,594		10,589
Exploration		29,286		13,225		16,061
Development 2		261,143		231,086		30,057
Total acquisition, exploration, and development 3, 4	$	582,111	$	525,404	$	56,707

	Year Ended December 31, 2005
	Total		Domestic		Discontinued Operations
Acquisition of proved and unproved properties	$	31,429	$	31,429	$	--
Lease acquisitions and prospect costs1		41,397		34,502		6,895
Exploration		52,350		38,425		13,925
Development 2		141,082		111,058		30,024
Total acquisition, exploration, and development 3, 4	$	266,258	$	215,414	$	50,844

(1) These are actual amounts as incurred by year, including both proved and unproved lease costs. The annual lease acquisition amounts added to proved oil and gas properties in 2007, 2006, and 2005 were $50.2 million, $70.5 million, and $30.4 million, respectively. Domestic costs for seismic data acquisition, included above, were $11.6 million, 23.1 million, and $4.2 million in 2007, 2006 and 2005, respectively. New Zealand costs for seismic data acquisition, included above were $0.5 million in 2007 and $3.8 million in 2006.

(2) Facility construction costs and capital costs have been included in development costs, and totaled $71.3 million, $16.5 million, and $26.9 million for the years ended December 31, 2007, 2006 and 2005.

(3) Includes capitalized general and administrative costs directly associated with the acquisition, exploration, and development efforts of approximately $30.6 million, $28.3 million, and $18.8 million in 2006, 2005, and 2004, respectively. In addition, the total includes $9.5 million, $9.2 million, and $7.2 million in 2007, 2006, and 2005, respectively, of capitalized interest on unproved properties.

(4) Asset retirement obligations incurred have been included in exploration, development and acquisition costs as applicable for the years ended December 31, 2007, 2006, and 2005.

Results of Operations (in thousands).

	Year Ended December 31, 2007
	Total			Domestic			Discontinued Operations

Oil and gas sales	$	695,250		$	652,856		$	42,394
Lease operating cost		(84,670	)		(70,893	)		(13,777	)
Severance and other taxes		(76,647	)		(73,813	)		(2,834	)
Depreciation, depletion, and amortization		(208,757	)		(186,086	)		(22,671	)
Accretion of asset retirement obligation		(1,625	)		(1,437	)		(188	)
Write down of oil and gas properties		(143,152	)		---			(143,152	)
		180,399			320,627			(140,228	)
Provision for income taxes		(108,056	)		(121,518	)		13,462
Results of producing activities	$	72,343		$	199,109		$	(126,766	)
Amortization per physical unit of production(equivalent bbl of oil)	$	17.39		$	17.53		$	16.34

	Year Ended December 31, 2006
	Total			Domestic			Discontinued Operations

Oil and gas sales	$	601,552		$	537,513		$	64,039
Lease operating cost		(62,475	)		(49,948	)		(12,527	)
Severance and other taxes		(65,452	)		(61,235	)		(4,217	)
Depreciation, depletion, and amortization		(166,518	)		(136,826	)		(29,692	)
Accretion of asset retirement obligation		(1,035	)		(885	)		(150	)
		306,072			288,619			17,453
Provision for income taxes		(117,493	)		(113,139	)		(4,354	)
Results of producing activities	$	188,579		$	175,480		$	13,099
Amortization per physical unit of production (equivalent Bbl of oil)	$	14.23		$	14.48		$	13.18

	Year Ended December 31, 2005
	Total			Domestic			Discontinued Operations

Oil and gas sales	$	423,767		$	355,873		$	67,894
Lease operating cost		(47,321	)		(34,941	)		(12,380	)
Severance and other taxes		(42,177	)		(37,806	)		(4,371	)
Depreciation, depletion and amortization		(106,038	)		(79,926	)		(26,112	)
Accretion of asset retirement obligation		(762	)		(627	)		(135	)
		227,469			202,573			24,896
Provision for income taxes		(80,484	)		(75,560	)		(4,924	)
Results of producing activities	$	146,985		$	127,013		$	19,972
Amortization per physical unit of production (equivalent Bbl of oil)	$	10.68		$	11.14		$	9.4

These results of operations do not include the gains from our hedging activities of $0.2 million and $4.0 million for 2007 and 2006, and losses from our hedging activities of $1.1 million for 2005, respectively. Our lease operating costs per Boe produced were $6.68 in 2007, $5.29 in 2006, and $4.87 in 2005.

The accretion of asset retirement obligation has been included in the 2007, 2006 and 2005 periods.

We used our effective tax rate in each country to compute the provision for income taxes in each year presented.

Supplementary Reserves Information. The following information presents estimates of our proved oil and natural gas reserves. Reserves were determined by us and audited by H. J. Gruy and Associates, Inc. (“Gruy”), independent petroleum consultants. Gruy has audited 100% of our domestic proved reserves in each of the last three years, and 100% of our New Zealand proved reserves for 2006 and 2005. 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 production histories and other geological, economic, and engineering data provided by us. Gruy’s report dated January 23, 2008, is set forth as an exhibit to the Form 10-K Report for the year ended December 31, 2007, and includes assumptions and references to the definitions that serve as the basis for the audit of proved reserves and future net cash flows.

Estimates of Proved Reserves	Total		Domestic		Discontinued Operations
	Natural Gas	Oil, NGL, and Condensate	Natural Gas	Oil, NGL, and Condensate	Natural Gas	Oil, NGL, and Condensate
	(Mcf)	(Bbls)	(Mcf)	(Bbls)	(Mcf)	(Bbls)

Proved reserves as of December 31, 2004	318,246,294	80,267,208	237,891,835	69,139,043	80,354,459	11,128,165
Revisions of previous estimates1	(21,461,605)	(2,199,673)	(13,751,124)	(1,023,808)	(7,710,481)	(1,175,866)
Purchases of minerals in place	9,336,088	3,262,761	9,336,088	3,262,761	---	---
Sales of minerals in place	(3,737,714)	(100,121)	(3,737,714)	(100,121)	---	---
Extensions, discoveries, and other additions	8,699,329	3,819,595	7,275,207	3,722,744	1,424,122	96,851
Production	(23,609,242)	(5,996,714)	(11,739,485)	(5,217,343)	(11,869,757)	(779,371)

Proved reserves as of December 31, 2005	287,473,150	79,053,056	225,274,807	69,783,276	62,198,343	9,269,779
Revisions of previous estimates1	(33,631,025)	3,127,635	(34,542,219)	3,135,885	911,194	(8,250)
Purchases of minerals in place	60,187,095	2,922,553	60,187,095	2,922,553	---	---
Sales of minerals in place	(6,122,283)	(708,691)	(6,122,283)	(708,691)	---	---
Extensions, discoveries, and other additions	39,012,428	5,627,297	38,466,980	5,512,795	545,448	114,502
Production	(22,787,948)	(7,902,766)	(13,603,589)	(7,181,287)	(9,184,359)	(721,479)

Proved reserves as of December 31, 2006	324,131,417	82,119,084	269,660,791	73,464,531	54,470,626	8,654,552
Revisions of previous estimates1	14,512,097	(2,227,517)	12,851,831	(1,947,699)	1,660,266	(279,818)
Purchases of minerals in place	37,748,518	6,571,426	37,748,518	6,571,426	---	---
Sales of minerals in place	---	---	---	---	---	---
Extensions, discoveries, and other additions	40,319,284	6,212,888	40,319,284	6,212,889	---	---
Production	(22,697,180)	(8,221,082)	(16,782,312)	(7,819,536)	(5,914,868)	(401,546)

Proved reserves as of December 31, 2007	394,014,136	84,454,799	343,798,112	76,481,611	50,216,024	7,973,188

Proved developed reserves: 2
December 31, 2004	193,310,761	42,037,852	140,549,052	36,628,873	52,761,709	5,408,979
December 31, 2005	152,001,133	37,989,821	125,367,690	35,298,324	26,633,443	2,691,497
December 31, 2006	151,276,834	34,956,469	133,815,108	33,345,567	17,461,726	1,610,902
December 31, 2007	187,152,308	36,752,529	172,973,952	35,547,583	14,178,356	1,204,946

(1) Revisions of previous estimates are related to upward or downward variations based on current engineering information for production rates, volumetrics, and reservoir pressure. Additionally, changes in quantity estimates are affected by the increase or decrease in crude oil, NGL, and natural gas prices at each year-end. Proved reserves, as of December 31, 2007, were based upon prices in effect at year-end. Our hedges at year-end 2007 consisted of oil and natural gas price floors with strike prices lower than the period end price and did not affect prices used in these calculations. The weighted average of 2007 year-end prices for total, domestic, and discontinued operations were $6.19, $6.65, and $3.08 per Mcf of natural gas, $93.24, $93.24, and $93.20 per barrel of oil, and $54.63, $56.28 and $36.98 per barrel of NGL, respectively. This compares to $5.46, $5.84, and $3.59 per Mcf of natural gas, $60.41, $60.07, and $63.51 per barrel of oil, and $30.93, $31.54 and $26.84 per barrel of NGL as of December 31, 2006, for total, domestic, and discontinued operations, respectively. The weighted average of 2005 year-end prices for total, domestic, and discontinued operations were $8.94, $10.36, and $3.79 per Mcf of natural gas, $60.12, $60.00, and $60.98 per barrel of oil, and $31.40, $33.28 and $19.20 per barrel of NGL, respectively.

(2) At December 31, 2007, 45% of our total reserves were proved developed, compared to 44% at December 31, 2006, and 50% at December 31, 2005. At December 31, 2007, 48% of our domestic reserves were proved developed, compared to 47% at December 31, 2006, and 52% at December 31, 2005. At December 31, 2007, 22% of our New Zealand reserves were proved developed, compared to 25% at December 31, 2006, and 36% at December 31, 2005.

Standardized Measure of Discounted Future Net Cash Flows. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows (in thousands):

	Year Ended December 31, 2007
	Total			Domestic			Discontinued Operations

Future gross revenues	$	9,547,840		$	8,745,424		$	802,416
Future production costs		(2,184,206	)		(1,814,660	)		(369,546	)
Future development costs		(1,220,492	)		(1,111,864	)		(108,628	)
Future net cash flows before income taxes		6,143,142			5,818,900			324,242
Future income taxes		(1,867,588	)		(1,856,143	)		(11,445	)
Future net cash flows after income taxes		4,275,554			3,962,757			312,797
Discount at 10% per annum		(1,639,111	)		(1,422,677	)		(216,434	)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,636,443		$	2,540,080		$	96,363

	Year Ended December 31, 2006
	Total			Domestic			Discontinued Operations

Future gross revenues	$	6,341,395		$	5,659,085		$	682,310
Future production costs		(1,393,634	)		(1,167,117	)		(226,517	)
Future development costs		(935,004	)		(886,843	)		(48,161	)
Future net cash flows before income taxes		4,012,757			3,605,125			407,632
Future income taxes		(1,187,859	)		(1,137,617	)		(50,242	)
Future net cash flows after income taxes		2,824,898			2,467,508			357,390
Discount at 10% per annum		(956,238	)		(835,593	)		(120,645	)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	1,868,660		$	1,631,915		$	236,745

	Year Ended December 31, 2005
	Total			Domestic			Discontinued Operations

Future gross revenues	$	6,917,104		$	6,194,561		$	722,543
Future production costs		(1,334,823	)		(1,122,638	)		(212,185	)
Future development costs		(710,344	)		(667,527	)		(42,817	)
Future net cash flows before income taxes		4,871,937			4,404,396			467,541
Future income taxes		(1,538,800	)		(1,461,578	)		(77,222	)
Future net cash flows after income taxes		3,333,137			2,942,818			390,319
Discount at 10% per annum		(1,173,767	)		(1,048,194	)		(125,573	)
Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves	$	2,159,370		$	1,894,624		$	264,746

The standardized measure of discounted future net cash flows from production of proved reserves was developed as follows:

1. Estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on year-end economic conditions.

2. The estimated future gross revenues of proved reserves are priced on the basis of year-end prices, except in those instances where fixed and determinable natural gas price escalations are covered by contracts limited to the price we reasonably expect to receive.

3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as asset retirement obligation costs, net of salvage value, based on year-end cost estimates and the estimated effect of future income taxes.

4. Future income taxes are computed by applying the statutory tax rate to future net cash flows reduced by the tax basis of the properties, the estimated permanent differences applicable to future oil and natural gas producing activities, and tax carry forwards.

The estimates of cash flows and reserves quantities shown above are based on year-end oil and natural gas prices for each period. Our hedges at year-end 2007 consisted mainly of oil and natural gas price floors with strike prices lower than the period end price and did not affect prices used in these calculations. Subsequent changes to such year-end oil and natural gas prices could have a significant impact on discounted future net cash flows. Under Securities and Exchange Commission rules, companies that follow the full-cost accounting method are required to make quarterly Ceiling Test calculations using hedge adjusted prices in effect as of the period end date presented (see Note 1 to the consolidated financial statements). Application of these rules during periods of relatively low oil and natural gas prices, even if of short-term seasonal duration, may result in non-cash write-downs.

The standardized measure of discounted future net cash flows is not intended to present the fair market value of our oil and natural gas property reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, an allowance for return on investment, and the risks inherent in reserves estimates.

The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):

	Year Ended December 31,
	2007			2006			2005

Beginning balance	$	1,868,660		$	2,159,369		$	1,464,945

Revisions to reserves proved in prior years--
Net changes in prices, and production costs		1,259,492			(658,283	)		1,232,877
Net changes in future development costs		(227,032	)		(166,891	)		(173,219	)
Net changes due to revisions in quantity estimates		7,013			(60,714	)		(138,969	)
Accretion of discount		266,852			314,345			199,799
Other		(337,698	)		(98,479	)		17,191
Total revisions		968,627			(670,022	)		1,137,679

New field discoveries and extensions, net of future production and development costs		305,843			212,629			152,462
Purchases of minerals in place		209,369			289,339			99,129
Sales of minerals in place		---			(20,378	)		(10,164	)
Sales of oil and gas produced, net of production costs		(533,934	)		(473,625	)		(334,268	)
Previously estimated development costs incurred		230,046			187,134			100,615
Net change in income taxes		(412,168	)		184,214			(451,029	)

Net change in standardized measure of discounted future net cash flows		767,783			(290,709	)		694,424
Ending balance	$	2,636,443		$	1,868,660		$	2,159,369

Selected Quarterly Financial Data (Unaudited). The following table presents summarized quarterly financial information for the years ended December 31, 2007 and 2006 (in thousands, except per share data):

	Revenues		Income from Continuing Operations Before Income Taxes		Income from Continuing Operations		Income (loss) from Discontinued Operations			Basic EPS from Continuing Operations		Diluted EPS from Continuing Operations
2007:
First	$	130,079	$	41,917	$	26,445	$	1,143		$	0.89	$	0.87
Second		156,410		48,557		30,523		987			1.02		1.00
Third		171,272		71,079		42,915		(633	)		1.43		1.40
Fourth		196,360		83,003		52,705		(132,798	)		1.75		1.71
Total	$	654,121	$	244,556	$	152,588	$	(131,301	)	$	5.09	$	4.98

2006:
First	$	119,440	$	53,641	$	33,829	$	3,487		$	1.16	$	1.13
Second		133,361		58,179		36,640		1,528			1.26		1.22
Third		153,447		75,870		46,342		4,469			1.58		1.54
Fourth		144,588		60,618		34,263		1,007			1.16		1.13
Total	$	550,836	$	248,308	$	151,074	$	10,491		$	5.16	$	5.03

There were no extraordinary items in 2007 or 2006. Our New Zealand operations are accounted for as discontinued operations.

The sum of the individual quarterly net income per common share amounts may not agree with year-to-date net income per common share as each quarterly computation is based on the weighted average number of common shares outstanding during that period. In addition, certain potentially dilutive securities were not included in certain of the quarterly computations of diluted net income per common share because to do so would have been antidilutive.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

The Company’s chief executive officer and chief financial officer have evaluated the Company’s disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”) as of the end of the period covered by this report. Based on that evaluation, they have concluded that such disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company required under the Exchange Act to be disclosed in this report. There were no significant changes in the Company’s internal controls that could significantly affect such controls subsequent to the date of their evaluation.

There was no change in our internal control over financial reporting during the quarter ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Management’s Report On Internal Control Over Financial Reporting as of December 31, 2007 is included in Item 8. Financial Statements and Supplementary Data. The Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting is also included in Item 8.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required under Item 10 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 13, 2008, annual shareholders’ meeting is incorporated herein by reference.

Item 11. Executive Compensation

The information required under Item 11 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 13, 2008, annual shareholders’ meeting is incorporated herein by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required under Item 12 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 13, 2008, annual shareholders’ meeting is incorporated herein by reference.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required under Item 13 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 13, 2008, annual shareholders’ meeting is incorporated herein by reference.

Item 14. Principal Accountant Fees and Services

The information required under Item 14 which will be set forth in our definitive proxy statement to be filed within 120 days after the close of the fiscal year end in connection with our May 13, 2008, annual shareholders’ meeting is incorporated by reference.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

·	1. The following consolidated financial statements of Swift Energy Company together with the report thereon of Ernst & Young LLP dated February 27, 2007, and the data contained therein are included in Item 8 hereof:

Management’s Report on Internal Control Over Financial Reporting	47
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	48
Report of Independent Registered Public Accounting Firm	49
Consolidated Balance Sheets	50
Consolidated Statements of Income	51
Consolidated Statements of Stockholders’ Equity	52
Consolidated Statements of Cash Flows	53
Notes to Consolidated Financial Statements	54

· Financial Statement Schedules

[None]

3. Exhibits

1.1		Underwriting Agreement dated May 17, 2007 among Swift Energy Company, Swift Energy Operating, LLC and J.P. Morgan Securities Inc. (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed May 30, 2007, File no. 1-08754)

2		Plan and Agreement and Articles of Merger to Form Holding Company, dated as of December 21, 2005, but effective at 9:00 a.m., local time in Austin, Texas on December 28, 2005, by and among Swift Energy Company, New Swift Energy Company and Swift Energy Operating, LLC (incorporated by reference as Exhibit 2.1 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

3.1		Restated Articles of Incorporation of Swift Energy Company (incorporated by reference as Exhibit 3.3 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

3.2		Amended and Restated Bylaws of Swift Energy Company, as amended through December 28, 2005 (incorporated by reference as Exhibit 3.5 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

3.3		Certificate of Designation of Series A Junior Participating Preferred Stock of Swift Energy Company (incorporated by reference as Exhibit 3.4 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

4.1		Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A., as Trustee (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed April 16, 2002, File No. 1-08754).


4.2		First Supplemental Indenture dated as of April 16, 2002, between Swift Energy Company and Bank One, N.A., including the form of 9 3/8% Senior Subordinated Notes due 2012 (incorporated by reference as Exhibit 4.2 to Swift Energy Company’s Form 8-K filed April 16, 2002, File No. 1-08754).

4.3		Second Supplemental Indenture dated as of December 28, 2005, between Swift Energy Company and J.P. Morgan Trust Company, National Association as successor Trustee to Bank One, NA (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

4.4		Indenture dated as of June 23, 2004, between Swift Energy Company and Wells Fargo Bank, National Association, as Trustee (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed June 25, 2004, File No. 1-08754).

4.5		First Supplemental Indenture dated as of June 23, 2004, between Swift Energy Company and Wells Fargo Bank, National Association, as Trustee, including the form of 7 5/8% Senior Notes (incorporated by reference as Exhibit 4.2 to Swift Energy Company’s Form 8-K filed June 25, 2004, File No. 1-08754).

4.6		Second Supplemental Indenture dated as of December 28, 2005, between Swift Energy Company and Wells Fargo Bank. National Association, as Trustee (incorporated by reference as Exhibit 4.2 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

4.7		Amended and Restated Rights Agreement between Swift Energy Company and American Stock Transfer & Trust Company, dated March 31, 1999 (incorporated by reference to Swift Energy Company’s Amendment No. 1 to Form 8-A filed April 7, 1999, File No. 1-08754).

4.8		Amendment No. 1 to the Rights Agreement dated December 12, 2005 between Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference as Exhibit 4.3 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

4.9		Assignment, Assumption, Amendment and Novation Agreement between Swift Energy Company, New Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent effective at 9:00 a.m. local time in Austin, Texas on December 28, 2005 (incorporated by reference as Exhibit 4.4 to Swift Energy Company’s Form 8-K filed December 29, 2005, File No. 1-08754).

4.10		Amendment No. 2 to the Rights Agreement dated December 21, 2006 between Swift Energy Company and American Stock Transfer & Trust Company, as Rights Agent (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed December 22, 2006, File No. 1-08754).

4.11		Form of indenture dated as of May 16, 2007 between Swift Energy Company and Wells Fargo Bank, National Association (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Registration Statement on Form S-3 filed May 17, 2007, File No. 333-143034).

4.12		First Supplemental Indenture dated as of June 1, 2007, between Swift Energy Company, Swift Energy Operating, LLC and Wells Fargo Bank, National Association relating to the 7-1/8% Senior Notes due 2017 (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form 8-K filed June 7, 2007, File No. 1-08754).


10.1 +		Amended and Restated Swift Energy Company 1990 Nonqualified Stock Option Plan, as of May 13, 1997 (incorporated by reference from Swift Energy Company’s definitive proxy statement for the annual shareholders meeting filed April 14, 1997, File No. 1-08754).

10.2 +		Amended and Restated Swift Energy Company 1990 Stock Compensation Plan, as of May 13, 1997 (incorporated by reference from Swift Energy Company’s definitive proxy statement for the annual shareholders meeting filed April 14, 1997, File No. 1-08754).

10.3 +		Amendment to the Swift Energy Company 1990 Stock Compensation Plan, as of May 9, 2000 (incorporated by reference as Exhibit 4.2 to the Swift Energy Company registration statement No. 333-67242 on Form S-8 filed August 10, 2001, File No. 1-08754).

10.4 +		Swift Energy Company 2001 Omnibus Stock Compensation Plan, as of January 1, 2001 (incorporated by reference as Exhibit 4.3 to the Swift Energy Company registration statement no. 333-67242 on Form S-8 filed August 10, 2001, File No. 1-08754).

10.5 +		Swift Energy Company 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.1 to the Swift Energy Company Form 8-K filed May 12, 2005, File No. 1-08754).

10.6 +		Amendment No. 1 to the Swift Energy Company 2005 Stock Compensation Plan, as of May 9, 2006 (incorporated by reference as Exhibit 10.1 to the Swift Energy Company Form 8-K filed May 12, 2006).

10.7 +		Employee Stock Purchase Plan (incorporated by reference as Exhibit 4(a) to Swift Energy Company’s Registration Statement No. 33-80228 on Form S-8 filed June 15, 1994, File No. 1-08754).

10.8 +		Amended and Restated Employee Stock Purchase Plan dated June 1, 2006 (incorporated by reference to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2006, File No. 1-08754).

10.9		Form of Indemnity Agreement for Swift Energy Company officers.

10.10		Form of Indemnity Agreement for Swift Energy Company directors.

10.11 +		Amended and Restated Employment Agreement dated as of November 15, 2000 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and A. Earl Swift (incorporated by reference as Exhibit 10.12 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-08754).

10.12 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and Terry E. Swift (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.13 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and James M. Kitterman (incorporated by reference as Exhibit 10.6 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).


10.14 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and Bruce H. Vincent (incorporated by reference as Exhibit 10.4 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.15 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and Joseph A. D’Amico (incorporated by reference as Exhibit 10.3 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.16 +		Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and Victor R. Moran (incorporated by reference as Exhibit 10.7 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.17 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company, predecessor to Swift Energy Operating, LLC, and Alton D. Heckaman, Jr. (incorporated by reference as Exhibit 10.5 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.18 +		Amended and Restated Employment Agreement dated as of May 9, 2001 between Swift Energy Company and Donald L. Morgan (incorporated by reference as Exhibit 10.8 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2001, File No. 1-08754).

10.19 +		Consulting Agreement between Swift Energy Company and A. Earl Swift effective as of July 1, 2006 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-08754).

10.20 +		Consulting Agreement between Swift Energy Company and Virgil N. Swift effective as of July 1, 2006 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2006, File No. 1-08754).

10.21 +		Fourth Amended and Restated Agreement and Release by and between Swift Energy Company and Virgil Neil Swift, dated November 20, 2000 (incorporated by reference as Exhibit 10.13 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2000, File No. 1-08754).

10.22 +		Description of executive officers’ compensation arrangements (incorporated by reference as Exhibit 10.25 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-08754).

10.23 +		Description of non-employee directors’ compensation arrangements (incorporated by reference as Exhibit 10.16 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-08754).

10.24 +		Forms of agreements for grant of incentive and non-qualified stock options and forms of agreement for grant of restricted stock under Swift Energy Company 2001 Omnibus Stock Compensation Plan (incorporated by reference as Exhibit 10.17 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2004, File No. 1-08754).


10.25 +		Forms of agreements for grant of incentive stock options and forms of agreement for grant of restricted stock under Swift Energy Company 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10.19 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-08754).

10.26		First Amended and Restated Credit Agreement effective as of June 29, 2004, among Swift Energy Company and Bank One, NA as Administrative Agent, Wells Fargo Bank, National Association as Syndication Agent, BNP Paribas, as Syndication Agent, Caylon, as Documentation agent, Societe Generale, as Documentation Agent and the Lenders Signatory Hereto and Banc One Capital Markets, Inc., as Sole Lead Arranger and Sole Book Runner (incorporated by reference as Exhibit 10.2 to the Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-08754).

10.27		First Amendment to First Amended and Restated Credit Agreement effective as of November 1, 2005 by and among Swift Energy Company, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities, Inc. as Sole Lead Arranger and Sole Book Runner, Wells Fargo Bank, National Association, as Sydication Agent, BNP Paribas, as Syndication Agent, Caylon, as Documentation Agent, and Societe Generale, as Documentation Agent. (incorporated by reference as Exhibit 10.1 to the Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2005, File No. 1-08754).

10.28		Second Amendment to First Amended and Restated Credit Agreement effective as of December 28, 2005, by and among Swift Energy Company and Swift Energy Operating, LLC, and, J.P. Morgan Chase Bank, N.A., as Administrative Agent, J.P. Morgan Securities, Inc. as Sole Lead Arranger and Sole Book Runner, Wells Fargo Bank, National Association, as Syndication Agent, BNP PARIBAS, as Syndication Agent, Calyon as Documentation Agent and Societe Generale as Documentation Agent (incorporated by reference as Exhibit 10.23 to Swift Energy Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2005, File No. 1-08754).

10.29		Third Amendment to First Amended and Restated Credit Agreement effective as of October 2, 2006, by and among Swift Energy Company and Swift Energy Operating, LLC, and, J.P. Morgan Chase Bank, N.A., as Administrative Agent, J.P. Morgan Securities, Inc. as Sole Lead Arranger and Sole Book Runner, Wells Fargo Bank, National Association, as Syndication Agent, BNP PARIBAS, as Syndication Agent, Calyon as Documentation Agent and Societe Generale as Documentation Agent (incorporated by reference to Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2006, File No. 1-08754).

10.30		Eighth Amendment to Lease Agreement between Swift Energy Company and Greenspoint Plaza Limited Partnership dated as of June 30, 2004 (incorporated by reference as Exhibit 10.1 to the Swift Energy Company Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004, File No. 1-08754).

10.31		Purchase and Sale Agreement dated as of August 24, 2006 but effective as of April 1, 2006, between Swift Energy Operating, LLC and BP America Production Company.

10.32+		Amendment No. 2 to the Swift Energy Company 2005 Stock Compensation Plan (incorporated by reference as Exhibit 99.1 to the Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2007 filed May 4, 2007).


10.33+		Amendment No. 3 to the Swift Energy Company 2005 Stock Compensation Plan (incorporated by reference as Exhibit 10 to Swift Energy Company’s Form 8-K filed May 11, 2007, File No. 1-08754).

10.34		Asset Purchase and Sale Agreement between Escondido Resources LP and Swift Energy Operating, LLC dated as of September 4, 2007 but effective as of July 1, 2007 (incorporated by reference as Exhibit 99.1 to the Swift Energy Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2007 filed May 4, 2007).

10.35*		Agreement for Sale and Purchase of Assets between Swift Energy New Zealand Limited, Swift Energy New Zealand Holdings Limited, Southern Petroleum (New Zealand) Exploration Limited, Origin Energy Recourses NZ (SPV1) Limited, Origin Energy Resources NZ (SPV2) Limited and Origin Energy Limited effective December 1, 2007.

12 *		Swift Energy Company Ratio of Earnings to Fixed Charges.

21 *		List of Subsidiaries of Swift Energy Company.

23.1 *		The consent of H.J. Gruy and Associates, Inc.

23.2 *		Consent of Ernst & Young LLP as to incorporation by reference regarding Forms S-8 and S-3 Registration Statements.

31.1 *		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32 *		Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99.1*		The summary of H.J. Gruy and Associates, Inc. reported January 23, 2008.

*Filed herewith.

+ Management contract or compensatory plan or arrangement.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SWIFT ENERGY COMPANY

	By:	/s/ Terry E. Swift
		Terry E. Swift
		Chairman of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant, Swift Energy Company, and in the capacities and on the dates indicated:

Signatures	Title	Date

	Director
/s/ Terry E. Swift	Chief Executive Officer	February 28, 2008
Terry E. Swift

	Executive Vice-President
/s/ Alton D. Heckaman, Jr.	Principal Financial Officer	February 28, 2008
Alton D. Heckaman, Jr.

	Controller
/s/ David W. Wesson	Principal Accounting Officer	February 28, 2008
David W. Wesson


/s/ Deanna L. Cannon	Director	February 28, 2008
Deanna L. Cannon


/s/ Raymond E. Galvin	Director	February 28, 2008
Raymond E. Galvin




/s/ Douglas J. Lanier	Director	February 28, 2008
Douglas J. Lanier


/s/Greg Matiuk	Director	February 28, 2008
Greg Matiuk


/s/ Henry C. Montgomery	Director	February 28, 2008
Henry C. Montgomery


/s/ Clyde W. Smith, Jr.	Director	February 28, 2008
Clyde W. Smith, Jr.


/s/ Charles J. Swindells	Director	February 28, 2008
Charles J. Swindells


/s/ Bruce H. Vincent	Director	February 28, 2008
Bruce H. Vincent