Edgar Filing: SWIFT ENERGY CO

e2ndqtr2007.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2007

Commission File Number 1-8754

______________________________

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in its Charter)

TEXAS (State of Incorporation)	20-3940611 (I.R.S. Employer Identification No.)

16825 Northchase Drive, Suite 400 Houston, Texas (Address of principal executive offices)	77060 (Zip Code)

(281) 874-2700

(Registrant’s telephone number, including area code)

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 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

Indicate the number of shares outstanding of each of the Issuer’s classes

of common stock, as of the latest practicable date.

Common Stock

($.01 Par Value)

(Class of Stock)

30,050,678 Shares

(Outstanding at July 31, 2007)

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2007

INDEX

PART I. FINANCIAL INFORMATION			PAGE

	Item 1.	Condensed Consolidated Financial Statements

		Condensed Consolidated Balance Sheets	3
		- June 30, 2007 and December 31, 2006

		Condensed Consolidated Statements of Income	4
		- For the Three month and Six month periods ended June 30, 2007 and 2006

		Condensed Consolidated Statements of Stockholders’ Equity	5
		- For the Six month period ended June 30, 2007 and year ended December 31, 2006

		Condensed Consolidated Statements of Cash Flows	6
		- For the Six month periods ended June 30, 2007 and 2006

		Notes to Condensed Consolidated Financial Statements	7

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk	35

	Item 4.	Controls and Procedures	36

PART II. OTHER INFORMATION

	Item 1.	Legal Proceedings	37
	Item 1A.	Risk Factors	37
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	None
	Item 3.	Defaults Upon Senior Securities	None
	Item 4.	Submission of Matters to a Vote of Security Holders	37
	Item 5.	Other Information	None
	Item 6.	Exhibits	38

SIGNATURES			39

Item 1.

Condensed Consolidated Balance Sheets

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)

	June 30, 2007			December 31, 2006
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	7,216		$	1,058
Accounts receivable-
Oil and gas sales		58,676			63,935
Joint interest owners		1,220			1,844
Other Receivables		1,318			1,231
Deferred tax asset		2,383			2,383
Other current assets		25,448			22,122
Total Current Assets		96,261			92,573

Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties		2,459,404			2,264,832
Unproved properties		108,745			112,136
		2,568,149			2,376,968
Furniture, fixtures, and other equipment		31,593			28,041
		2,599,742			2,405,009
Less – Accumulated depreciation, depletion, and amortization		(1,019,663	)		(921,697	)
		1,580,079			1,483,312
Other Assets:
Debt issuance costs		7,562			7,382
Restricted assets		2,485			2,415
		10,047			9,797
	$	1,686,387		$	1,585,682
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	60,567		$	74,425
Accrued capital costs		57,542			55,282
Accrued interest		6,867			8,764
Undistributed oil and gas revenues		2,189			7,504
Total Current Liabilities		127,165			145,975
Long-Term Debt		400,000			381,400
Deferred Income Taxes		257,004			224,967
Asset Retirement Obligation		34,696			33,695
Lease Incentive Obligation		1,609			1,728

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, 30,414,427 and 30,170,004 shares issued, and 29,998,629 and 29,742,918 shares outstanding, respectively		305			302
Additional paid-in capital		398,005			387,556
Treasury stock held, at cost, 415,798 and 427,086 shares, respectively		(6,609	)		(6,125	)
Retained earnings		473,989			415,868
Accumulated other comprehensive income, net of income tax		223			316
		865,913			797,917
	$	1,686,387		$	1,585,682

See accompanying notes to condensed consolidated financial statements.

Condensed Consolidated Statements of Income (Unaudited)

Swift Energy Company and Subsidiaries

(in thousands, except per share amounts)

	Three Months Ended				Six Months Ended
	06/30/07		06/30/06		06/30/07		06/30/06
Revenues:
Oil and gas sales	$	167,674	$	144,994	$	308,703	$	279,947
Price-risk management and other, net		495		2,183		559		3,399
		168,169		147,177		309,262		283,346

Costs and Expenses:
General and administrative, net		10,501		7,618		19,030		15,305
Depreciation, depletion and amortization		49,679		38,877		97,326		74,284
Accretion of asset retirement obligation		396		203		782		494
Lease operating costs		20,126		18,523		38,430		32,918
Severance and other taxes		18,565		15,968		35,313		30,720
Interest expense, net		7,297		5,799		14,042		11,660
Debt retirement cost		12,765		---		12,765		---
		119,329		86,988		217,688		165,381

Income Before Income Taxes		48,840		60,189		91,574		117,965

Provision for Income Taxes		17,330		22,021		32,476		42,482

Net Income	$	31,510	$	38,168	$	59,098	$	75,483

Per Share Amounts

Basic: Net Income	$	1.05	$	1.31	$	1.98	$	2.59

Diluted: Net Income	$	1.03	$	1.27	$	1.93	$	2.52

Weighted Average Shares Outstanding		29,930		29,160		29,880		29,116

See accompanying notes to condensed consolidated financial statements.

Condensed Consolidated Statements of Stockholders’ Equity

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)

	Common Stock (1)		Additional Paid-in Capital			Treasury Stock			Unearned Compensation			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
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) (2)		-		953			471			-			-			-			1,424
Stock options exercised (112,409 shares) (2)		1		1,623			-			-			-			-			1,624
Purchase of treasury shares (21,529 shares) (2)		-		-			(955	)		-			-			-			(955	)
Adoption of FIN 48 (2)		-		-			-			-			(977	)		-			(977	)
Employee stock purchase plan (17,678 shares) (2)		1		619			-			-			-			-			620
Issuance of restricted stock (114,336 shares) (2)		1		(1	)		-			-			-			-			-
Amortization of stock Compensation (2)		-		7,255			-			-			-			-			7,255
Comprehensive income:
Net income (2)		-		-			-			-			59,098			-			59,098
Other comprehensive loss (2)		-		-			-			-			-			(93	)		(93	)
Total comprehensive income (2)																			59,005
Balance, June 30, 2007 (2)	$	305	$	398,005		$	(6,609	)	$	-		$	473,989		$	223		$	865,913

(1)$.01 par value.
(2)Unaudited.

See accompanying notes to condensed consolidated financial statements.

Condensed Consolidated Statements of Cash Flows (Unaudited)

Swift Energy Company and Subsidiaries

(in thousands)

	Six Months Ended June 30,
	2007			2006
Cash Flows from Operating Activities:
Net income	$	59,098		$	75,483
Adjustments to reconcile net income to net cash provided
by operating activities-
Depreciation, depletion, and amortization		97,326			74,284
Accretion of asset retirement obligation		782			494
Deferred income taxes		32,443			41,098
Stock-based compensation expense		5,147			3,241
Debt retirement cost – cash and non-cash		12,765			---
Other		(2,987	)		(2,817	)
Change in assets and liabilities-
(Increase) decrease in accounts receivable		5,883			(9,092	)
Increase (decrease) in accounts payable and accrued liabilities		(1,531	)		516
Increase (decrease) in income taxes payable		(974	)		549
Decrease in accrued interest		(1,897	)		(1	)
Net Cash Provided by Operating Activities		206,055			183,755

Cash Flows from Investing Activities:
Additions to property and equipment		(189,646	)		(183,856	)
Proceeds from the sale of property and equipment		215			20,306
Net cash distributed as operator of oil and gas properties		(17,263	)		(5,911	)
Net cash received as operator of partnerships and joint ventures		485			226
Other		---			572
Net Cash Used in Investing Activities		(206,209	)		(168,663	)

Cash Flows from Financing Activities:
Proceeds from long-term debt		250,000			---
Payments of long-term debt		(200,000	)		---
Net payments of bank borrowings		(31,400	)		---
Net proceeds from issuances of common stock		2,244			3,081
Excess tax benefits from stock-based awards		---			896
Purchase of treasury shares		(955	)		---
Payments of debt retirement costs		(9,376	)		---
Payments of debt issuance costs		(4,201	)		---
Net Cash Provided by Financing Activities		6,312			3,977

Net Increase in Cash and Cash Equivalents	$	6,158		$	19,069

Cash and Cash Equivalents at Beginning of Period		1,058			53,005

Cash and Cash Equivalents at End of Period	$	7,216		$	72,074

Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	$	15,275		$	11,079
Cash paid during period for income taxes	$	1,007		$	835

See accompanying notes to condensed consolidated financial statements.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SWIFT ENERGY COMPANY AND SUBSIDIARIES

(1) General Information

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission. We believe that the disclosures presented are adequate to allow the information presented not to be misleading. The condensed consolidated financial statements should be read in conjunction with the audited financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006 as filed with the Securities and Exchange Commission.

(2) Summary of Significant Accounting Policies

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 continued to trade on the New York Stock Exchange. The purposes of this new holding company structure are to separate Swift Energy’s domestic and international 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 three 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 amended 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.

Property and Equipment

We follow the “full-cost” method of accounting for oil and 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 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 six months ended June 30, 2007 and 2006, such internal costs capitalized totaled $15.5 million and $12.6 million, respectively. Interest costs are also capitalized to unproved oil and gas properties. For the six months ended June 30, 2007 and 2006, capitalized interest on unproved properties totaled $5.0 million and $4.3 million, respectively. Interest not capitalized and general and administrative costs related to production and general overhead are expensed as incurred.

No gains or losses are recognized upon the sale or disposition of oil and gas properties, except in transactions involving a significant amount of reserves or where the proceeds from the sale of oil and gas properties would significantly alter the relationship between capitalized costs and proved reserves of oil and 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 gas property costs are amortized.

We compute the provision for depreciation, depletion, and amortization of oil and gas properties

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

by the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and gas properties—including future development costs, natural 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 gas produced during the period by the total estimated units of proved oil and 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, held at cost, are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two 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 country-by-country 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, foreign currency exchange rates, the political stability in the countries in which we have an investment, and available geological and geophysical information. Any impairment assessed is added to the cost of proved properties being amortized. To the extent costs accumulate in countries where there are no proved reserves, any costs determined by management to be impaired are charged to expense.

Full-Cost Ceiling Test.

At the end of each quarterly reporting period, the unamortized cost of oil and 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 June 30, 2007 consisted of natural gas price floors with strike prices higher than the period end prices and did not materially affect prices used in this calculation. This calculation is performed 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 gas that are ultimately recovered.

Given the volatility of oil and gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and gas reserves could change in the near term. If oil and gas prices decline 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 gas properties could occur in the future.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of Swift Energy Company 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, as well as onshore oil and natural gas reserves in New Zealand. Our undivided interests in natural gas processing plants are accounted for using the proportionate consolidation method, whereby our proportionate share of assets, liabilities, revenues, and

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

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.

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. Beginning in 2007, processing costs for natural gas and natural gas liquids (NGLs) that are paid in-kind are recorded in “Lease operating costs,” prior to that these costs were deducted from revenues. 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 June 30, 2007, we did not have any material natural gas imbalances.

Reclassification of Prior Period Balances

Certain reclassifications have been made to prior period amounts to conform to the current year presentation.

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 June 30, 2007 and December 31, 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.

Inventories

We value inventories at the lower of cost or market. Cost of crude oil inventory is determined using the weighted average method and all other inventory is accounted for using the first in, first out method (“FIFO”). The major categories of inventories, which are included in “Other current assets” on the accompanying balance sheets, are shown as follows:

(in thousands)	Balance at June 30, 2007		Balance at December 31, 2006

Materials, Supplies and Tubulars	$	10,795	$	10,611
Crude Oil		468		474
Total	$	11,263	$	11,085

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 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,

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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

·	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.

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 our deferred tax liability. This is also the total balance of our unrecognized tax benefits, which would fully impact our effective tax rate if recognized. We do not expect to 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, 2006 and June 30, 2007 no interest or penalties relating to income taxes have been recognized.

Our U.S. Federal and State of Louisiana income tax returns from 1998 forward remain subject to examination by tax authorities. Our Texas franchise tax returns for 2005 and prior years have been audited by the Texas State Comptroller. There are no unresolved items related to those audits. No other state returns are significant to our financial position. Our New Zealand income tax returns from 2002 forward remain subject to examination by the local tax authority.

Accounts Payable and Accrued Liabilities

Included in “Accounts payable and accrued liabilities,” on the accompanying balance sheets, at June 30, 2007 and December 31, 2006 are liabilities of approximately $8.1 million and $13.9 million, respectively, representing the amount by which checks issued, but not presented by vendors to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.

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 June 30, 2007, we recorded $0.2 million, net of taxes of $0.1 million, of derivative gains in “Accumulated other comprehensive income, net of income tax” on the accompanying

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

balance sheet. The components of accumulated other comprehensive Income (loss) and related tax effects 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		(795	)		295			(500	)
Effect of cash flow hedges settled during the period		647			(240	)		407
Other comprehensive income at June 30, 2007	$	355		$	(132	)	$	223

Total comprehensive income was $31.9 million and $37.3 million for the second quarter of 2007 and 2006, respectively. Total comprehensive income was $59.0 and $75.1 million for the first six months of 2007 and 2006, respectively.

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 the second quarters of 2007 and 2006, we recognized a net loss of $0.4 million and a net gain of $1.1 million, respectively, relating to our derivative activities. During the first six months of 2007 and 2006, we recognized a net loss of $0.7 million and a net gain of $2.0 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of income. At June 30, 2007, the Company had recorded $0.2 million, net of taxes of $0.1 million, of derivative gains 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 amount of ineffectiveness reported in “Price-risk management and other, net” for the first six months of 2007 and 2006 was not material. We expect to reclassify all amounts currently held in “Accumulated other comprehensive income (loss), net of income tax” into the statement of income within the next three months when the forecasted sale of hedged production occurs.

At June 30, 2007, we had in place price floors in effect for July 2007 through the September 2007 contract month for natural gas that cover a portion of our domestic natural gas production for July 2007 to September 2007. The natural gas price floors cover notional volumes of 1,350,000 Mmbtu with a weighted average floor price of $7.11 per Mmbtu. Our natural gas price floors in place at June 30, 2007 are expected to cover approximately 35% to 40% of our estimated domestic natural gas production from July 2007 to September 2007.

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 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 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 statement of income. The fair value of our derivatives is computed using the Black-Scholes-Merton option pricing model and is periodically verified against quotes from brokers. The fair value of these instruments at June 30, 2007, was $0.6 million and is recognized on the accompanying balance sheet in “Other current assets.”

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

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 are recorded as a reduction to “General and administrative, net” based on our estimate of the costs incurred to operate the wells. The total amount of supervision fees charged to the wells we operate were $5.3 million and $4.2 million in the first six months of 2007 and 2006, respectively.

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 related asset 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 useful life 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 cost pool. 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. SFAS No. 143 was adopted by us effective January 1, 2003. The following provides a roll-forward of our asset retirement obligation:

(in thousands)	2007		2006

Asset Retirement Obligation recorded as of January 1	$	34,460	$	19,356
Accretion expense for the six months ended June 30		782		494
Liabilities incurred for new wells and facilities construction		251		311
Reductions due to sold, or plugged and abandoned wells		---		---
Increase (decrease) due to currency exchange rate fluctuations		79		(88	)
Asset Retirement Obligation as of June 30	$	35,572	$	20,073

At both June 30, 2007 and December 31, 2006, approximately $0.9 million and $0.8 million of our asset retirement obligation is classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying balance sheets.

New Accounting Pronouncements

Effective January 1, 2007, the Company adopted FASB Interpretation (FIN) No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement No. 109" ("FIN 48"). This interpretation provides guidance for recognizing and measuring uncertain tax positions, as defined in SFAS No. 109, “Accounting for Income Taxes.” See additional discussion of FIN 48 in the Income Taxes section of the footnotes. 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 deferred tax liability.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 addresses how companies should approach measuring fair value when required by GAAP; it does not create or modify any current GAAP requirements to apply fair value accounting. SFAS No. 157 provides a single definition for fair value that is to be applied consistently for all accounting applications, and also generally describes and prioritizes, according to reliability, the methods and inputs used in valuations. SFAS No. 157 prescribes various disclosures about financial statement categories and amounts which are measured at fair value, if such disclosures are not already specified elsewhere in GAAP. The new measurement and disclosure requirements of SFAS No. 157 are effective for us in the first quarter 2008. The Company has not yet determined what impact, if any, this statement will have on its financial position or results of operations.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

(3) Share-Based Compensation

We have various types of share-based compensation plans. Refer to Note 6 of our consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, for additional information related to these share-based compensation plans.

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. Prior to the adoption of SFAS No. 123R, we accounted for stock option grants in accordance with Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method), and accordingly, recognized no compensation expense for employee stock option grants.

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 both six month periods ended June 30, 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 the new standard.

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 condensed consolidated statements of operations.

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 condensed 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 $0.7 and $0.9 million for the six months ended June 30, 2007 and 2006, respectively. The benefit for 2007 has not been recognized in the financial statements as these benefits have not been realized since we are in a tax net operating loss position for the first six months of 2007.

Net cash proceeds from the exercise of stock options were $1.6 million and $2.4 million for the six months ended June 30, 2007 and 2006. The actual income tax benefit realized from stock option exercises was $0.9 million and $1.3 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 condensed consolidated statements of income, and was $2.6 million and $1.4 million for the quarters ended June 30, 2007 and 2006, respectively. Stock compensation expense for the six months ended June 30, 2007 and 2006 was $4.8 million and $3.1 million, respectively. 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

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:

	Three Months Ended						Six Month Ended
	June 30,						June 30,
	2007			2006			2007			2006

Dividend yield		0	%		0	%		0	%		0	%
Expected volatility		37.7	%		39.3	%		38.5	%		39.5	%
Risk-free interest rate		5.1	%		5.1	%		4.8	%		4.9	%
Expected life of options (in years)		1.9			1.8			6.2			5.6
Weighted-average grant-date fair value	$	10.73		$	9.71		$	20.10		$	19.33

At June 30, 2007, there was $5.0 million of unrecognized compensation cost related to stock options which is expected to be recognized over a weighted-average period of 1.5 years. The following table represents stock option activity for the six months ended June 30, 2007:

	Shares			Wtd. Avg. Exer. Price

Options outstanding, beginning of period		1,549,140		$	24.59
Options granted		191,398		$	43.53
Options canceled		(7,940	)	$	41.70
Options exercised		(128,310	)	$	16.48
Options outstanding, end of period		1,604,288		$	27.41
Options exercisable, end of period		877,321		$	24.23

The aggregate intrinsic value and weighted average remaining contract life of options outstanding and exercisable at June 30, 2007 was $25.7 million and 5.6 years and $16.5 million and 4.2 years, respectively. Total intrinsic value of options exercised during the six months ended June 30, 2007 was $2.4 million.

Restricted Stock

The plans, as described in Note 6 of our consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended December 31, 2006, allow for the issuance of restricted stock awards that may not be sold or otherwise transferred until certain restrictions have lapsed. The unrecognized compensation cost related to these awards is expected to be expensed over the period the restrictions lapse (generally one to five years).

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 June 30, 2007, we had unrecognized compensation expense of approximately $21.8 million associated with these awards which are expected to be recognized over a weighted-average period of 2.0 years. The total fair value of shares vested during the first six months ended June 30, 2007 was $5.0 million.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

The following table represents restricted stock activity for the six months ended June 30, 2007:

	Shares			Wtd. Avg. Grant Price

Restricted shares outstanding, beginning of period		503,184		$	40.04
Restricted shares granted		311,840		$	43.19
Restricted shares canceled		(15,350	)	$	43.14
Restricted shares vested		(114,612	)	$	38.75
Restricted shares outstanding, end of period		685,062		$	41.65

(4) 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 to employees using the treasury stock method. Certain of our stock options, that could potentially dilute Basic EPS in the future, were anti-dilutive for periods ended June 30, 2007 and 2006, 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 periods ended June 30, 2007 and 2006:

(in thousands, except per share data)	Three Months Ended June 30,
	2007						2006
	Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	31,510		29,930	$	1.05	$	38,168		29,160	$	1.31
Dilutive Securities:
Restricted Stock		---		168				---		97
Stock Options		---		515				---		771
Diluted EPS:
Net Income and Assumed Share Conversions	$	31,510		30,613	$	1.03	$	38,168		30,028	$	1.27

(in thousands, except per share data)	Six Months Ended June 30,
	2007						2006
	Net Income		Shares		Per Share Amount		Net Income		Shares		Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	59,098		29,880	$	1.98	$	75,483		29,116	$	2.59
Dilutive Securities:
Restricted Stock		---		165				---		99
Stock Options		---		509				---		782
Diluted EPS:
Net Income and Assumed Share Conversions	$	59,098		30,554	$	1.93	$	75,483		29,997	$	2.52

Options to purchase approximately 1.6 million shares at an average exercise price of $27.41 were outstanding at June 30, 2007, while options to purchase 2.1 million shares at an average exercise price of $23.12 were outstanding at June 30, 2006. Approximately 1.1 million and 1.3 million options to purchase shares were not included in the computation of Diluted EPS for the three months ended June 30, 2007 and 2006, respectively, and 1.1 million and 1.3 million options to purchase shares were not included in the computation of Diluted EPS for the six months ended June 30, 2007 and 2006, respectively, because these options were anti-dilutive, in that the sum of the 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 516,719 shares and 241,781 shares were not included in the computation of Diluted EPS for the three months ended June 30, 2007 and 2006, respectively, and 520,289 shares and 239,963 shares were not included in the computation of Diluted EPS for the six months ended June 30, 2007 and 2006, respectively, because these restricted stock grants were anti-dilutive 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.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

(5) Long-Term Debt

Our long-term debt, including the current portion, as of June 30, 2007 and December 31, 2006, was as follows:

(in thousands)	June 30, 2007		December 31, 2006
Bank Borrowings	$	---	$	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	$	400,000	$	381,400

At June 30, 2007, the aggregate maturities on our long-term debt are $150.0 million for 2011 and $250 million for 2017.

Bank Borrowings

At June 30, 2007, we had no borrowings under our $500.0 million credit facility with a syndicate of ten banks that had a borrowing base of $350.0 million and expires in October 2011. The interest rate is either (a) the lead bank’s prime rate (8.25% at June 30, 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 $500.0 million from $400.0 million, increasing the commitment amount under the borrowing base to $250.0 million from $150.0 million, and extending its expiration to October 3, 2011 from October 1, 2008. In April 2007, we increased the borrowing base to $350.0 million from $250.0 million.

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 gas properties. We have also pledged 65% of the stock in our two New Zealand subsidiaries as collateral for this credit facility. 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 November 2007.

Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.1 million and $0.2 million for the three months ended June 30, 2007 and 2006, respectively, and $2.6 million and $0.4 million for the six months ended June 30, 2007 and 2006, respectively. The amount of commitment fees included in interest expense, net was $0.1 million for each of the three month periods ended June 30, 2007 and 2006, respectively, and $0.2 million and $0.3 million for both the six month periods ended June 30, 2007 and 2006, respectively.

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 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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

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 $1.5 million for both the three and six month periods ended June 30, 2007.

Senior Notes Due 2011

These notes consist of $150.0 million of 7-5/8% senior notes due 2011, 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. In addition, prior to July 15, 2007, we could have redeemed up to 35% of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 107.625% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $3.9 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. 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 $3.0 million for each of the three month periods ended June 30, 2007 and 2006, and $6.0 million for each of the six month periods ended June 30, 2007 and 2006.

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 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.

Interest expense on the 9-3/8% senior subordinated notes due 2012, including amortization of debt issuance costs totaled $4.1 million and $4.8 million for each of the three month periods ended June 30, 2007 and 2006, respectively, and $8.9 million and $9.6 million for the six month periods ended June 30, 2007 and 2006, respectively.

We have capitalized interest on our unproved properties in the amount of $2.4 million and $2.2 million for the three month periods ended June 30, 2007 and 2006, respectively, and $5.0 million and $4.3 million for the six month periods ended June 30, 2007 and 2006, respectively.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

(6) Foreign Activities

As of June 30, 2007, our gross capitalized oil and gas property costs in New Zealand totaled approximately $352.2 million. Approximately $337.5 million has been included in the “Proved properties” portion of our oil and gas properties, while $14.7 million is included as “Unproved properties.” Our functional currency in New Zealand is the U.S. dollar. Net assets of our New Zealand operations total $255.3 million at June 30, 2007.

(7) Acquisitions and Dispositions

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 $154.6 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.

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 $18.7 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.

(8) Condensed Consolidating Financial Information

In December 2005, we amended the indenture for our 9-3/8% Senior Subordinated Notes due 2012 and our 7-5/8% Senior Notes due 2011 to reflect our new holding company organizational structure (as discussed in Note 2). Pursuant to the amendment, 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. Prior to amendment, Swift Energy Company was the sole obligor. Due to the redemption of the 9-3/8% senior subordinated notes, Swift Energy Company and Swift Energy Operating, LLC are no longer co-obligors under that indenture as of June 18, 2007, however, both companies are co-obligors of the 7-1/8% senior notes as of June 1, 2007. The co-obligations are full and unconditional and are joint and several. The following is condensed consolidating financial information for Swift Energy Company, Swift Energy Operating, LLC, and significant subsidiaries:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Condensed Consolidating Balance Sheets

(in thousands)	June 30, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

ASSETS

Current assets	$	---	$	76,493	$	19,768	$	---		$	96,261
Property and equipment		---		1,344,792		235,287		---			1,580,079
Investment in subsidiaries (equity method)		865,913		---		656,586		(1,522,499	)		---
Other assets		---		39,039		771		(29,763	)		10,047
Total assets	$	865,913	$	1,460,324	$	912,412	$	(1,552,262	)	$	1,686,387


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	121,713	$	5,452	$	---		$	127,165
Long-term liabilities		---		682,025		41,047		(29,763	)		693,309
Stockholders’ equity		865,913		656,586		865,913		(1,522,499	)		865,913
Total liabilities and stockholders’ equity	$	865,913	$	1,460,324	$	912,412	$	(1,552,262	)	$	1,686,387

(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	$	17,303	$	---		$	92,573
Property and equipment		---		1,239,722		243,590		---			1,483,312
Investment in subsidiaries (equity method)		797,917		---		590,720		(1,388,637	)		---
Other assets		---		42,519		705		(33,427	)		9,797
Total assets	$	797,917	$	1,357,511	$	852,318	$	(1,422,064	)	$	1,585,682


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	137,016	$	8,959	$	---		$	145,975
Long-term liabilities		---		629,775		45,442		(33,427	)		641,789
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

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Income

(in thousands)	Three Months Ended June 30, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	156,306	$	11,863		$	---		$	168,169
Expenses		---		107,749		11,580			---			119,329

Income (loss) before the following:		---		48,557		283			---			48,840
Equity in net earnings of subsidiaries		31,510		---		30,522			(62,032	)		---

Income before income taxes		31,510		48,557		30,805			(62,032	)		48,840
Income tax provision (benefit)		---		18,034		(704	)		---			17,330

Net income	$	31,510	$	30,523	$	31,509		$	(62,032	)	$	31,510

(in thousands)	Six Months Ended June 30, 2007
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries			Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	286,385	$	22,877		$	---		$	309,262
Expenses		---		195,910		21,778			---			217,688

Income (loss) before the following:		---		90,475		1,099			---			91,574
Equity in net earnings of subsidiaries		59,098		---		56,968			(116,066	)		---

Income before income taxes		59,098		90,475		58,067			(116,066	)		91,574
Income tax provision (benefit)		---		33,507		(1,031	)		---			32,476

Net income	$	59,098	$	56,968	$	59,098		$	(116,066	)	$	59,098

(in thousands)	Three Months Ended June 30, 2006
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	133,363	$	13,814	$	---		$	147,177
Expenses		---		75,184		11,803		---			86,988

Income (loss) before the following:		---		58,179		2,011		---			60,189
Equity in net earnings of subsidiaries		38,168		---		36,641		(74,809	)		---

Income before income taxes		38,168		58,179		38,651		(74,809	)		60,189
Income tax provision (benefit)		---		21,538		483		---			22,021

Net income	$	38,168	$	36,641	$	38,168	$	(74,809	)	$	38,168

(in thousands)	Six Months Ended June 30, 2006
	Swift Energy Co. (Parent and Co-obligor)		Swift Energy Operating, LLC (Co-obligor)		Other Subsidiaries		Eliminations			Swift Energy Co. Consolidated

Revenues	$	---	$	252,801	$	30,545	$	---		$	283,346
Expenses		---		140,982		24,399		---			165,381

Income (loss) before the following:		---		111,819		6,146		---			117,965
Equity in net earnings of subsidiaries		75,483		---		70,468		(145,951	)		---

Income before income taxes		75,483		111,819		76,614		(145,951	)		117,965
Income tax provision (benefit)		---		41,351		1,131		---			42,482

Net income	$	75,483	$	70,468	$	75,483	$	(145,951	)	$	75,483

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Condensed Consolidating Statements of Cash Flows

(in thousands)	Six Months Ended June 30, 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	$	---	$	193,383		$	12,672		$	---		$	206,055
Cash flow from investing activities		---		(195,009	)		(7,536	)		(3,664	)		(206,209	)
Cash flow from financing activities		---		6,312			(3,664	)		3,664			6,312

Net increase in cash	$	---	$	4,686		$	1,472		$	---		$	6,158
Cash, beginning of period		---		50			1,008			---			1,058

Cash, end of period	$	---	$	4,736		$	2,480		$	---		$	7,216

(in thousands)	Six Months Ended June 30, 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	$	---	$	160,938		$	22,817		$	---		$	183,755
Cash flow from investing activities		---		(139,553	)		(37,744	)		8,635			(168,663	)
Cash flow from financing activities		---		3,976			8,635			(8,635	)		3,977

Net increase in cash	$	---	$	25,361		$	(6,292	)	$	---			19,069
Cash, beginning of period		---		44,911			8,094			---			53,005

Cash, end of period	$	---	$	70,272		$	1,802		$	---		$	72,074

(9) Segment Information

The Company has two reportable segments, one domestic and one foreign, both of which are in the business of oil and natural gas exploration and production. The accounting policies of the segments are the same as those described in the summary of significant accounting policies. We evaluate our performance based on pre-tax profit or loss from oil and gas operations before price-risk management and other, net, general and administrative, net, debt retirement costs, and interest expense, net. Our reportable segments are managed separately based on their geographic locations. Financial information by operating segment is presented below:

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

(in thousands)	Three Months Ended June 30,
	2007						2006
	Domestic		New Zealand		Total		Domestic		New Zealand		Total

Oil and gas sales	$	156,311	$	11,363	$	167,674	$	131,290	$	13,704	$	144,994

Costs and Expenses:
Depreciation, depletion and amortization		43,854		5,825		49,679		31,972		6,905		38,877
Accretion of asset retirement obligation		349		47		396		166		37		203
Lease operating costs1		16,178		3,948		20,126		15,414		3,109		18,523
Severance and other taxes		17,790		775		18,565		15,099		869		15,968

Income from oil and gas operations	$	78,140	$	768	$	78,908	$	68,639	$	2,784	$	71,423

Price-risk management and other, net						495						2,183

General and administrative, net						10,501						7,618
Interest expense, net						7,297						5,799
Debt retirement cost						12,765						---

Income Before Income Taxes					$	48,840					$	60,189

(in thousands)	Six Months Ended June 30,
	2007						2006
	Domestic		New Zealand		Total		Domestic		New Zealand		Total

Oil and gas sales	$	286,533	$	22,170	$	308,703	$	249,374	$	30,573	$	279,947

Costs and Expenses:
Depreciation, depletion and amortization		85,576		11,750		97,326		59,995		14,289		74,284
Accretion of asset retirement obligation		690		92		782		421		73		494
Lease operating costs		31,892		6,538		38,430		26,722		6,196		32,918
Severance and other taxes		33,841		1,472		35,313		28,704		2,016		30,720

Income from oil and gas operations	$	134,534	$	2,318	$	136,852	$	133,532	$	7,999	$	141,531

Price-risk management and other, net						559						3,399

General and administrative, net						19,030						15,305
Interest expense, net						14,042						11,660
Debt retirement cost						12,765						---

Income Before Income Taxes					$	91,574					$	117,965

Total Assets	$	1,452,359	$	234,028	$	1,686,387	$	1,096,205	$	252,861	$	1,349,066

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

SWIFT ENERGY COMPANY AND SUBSIDIARIES

ITEM 2.

You should read the following discussion and analysis in conjunction with our financial information and our condensed consolidated financial statements and notes thereto included in this report and our Annual Report on Form 10-K for the year ended December 31, 2006. The following information contains forward-looking statements. For a discussion of limitations inherent in forward-looking statements, see “Forward-Looking Statements” on page 31 of this report.

Overview

Swift Energy had a successful second quarter that included both strong domestic production and the refinancing of our 9-3/8% notes with 7-1/8% notes during a favorable market window. Given the current commodity price environment, our production weighting of 72% crude oil and NGLs continues to aid our overall price realizations. Due to timing delays with projects and market constraints domestically, and production declines in New Zealand, we are reducing our estimation of full year production to a range of 1% to 3% growth over 2006 levels from the previously estimated range of 7% to 10%. Although no change is being made to our estimation of reserves growth of 4% to 6% for the year, we currently believe that it will come in at the low end of that range. Facility, pressure maintenance and pipeline expansions scheduled for completion in 2008 will help alleviate the production constraints in our South Louisiana region.

During the second quarter of 2007, we began a review of strategic alternatives for our New Zealand operating unit, Swift Energy New Zealand, Ltd., often referred to as “SENZ.” Such alternatives include an outright sale or merger of some or all of the properties and facilities, entry into joint ventures or reshaping of long-term operational strategy there. We retained Scotia Waterous (USA) Inc. as an advisor to the potential sale of some or all of our New Zealand assets owned and operated by SENZ. The strategic review is expected to be completed by year-end.

In the second quarter of 2007 as compared to the same period in 2006, our revenues increased 14% to $168.2 million but total costs increased 37% during the same period to $119.3 million, resulting in net income of $31.5 million, a 17% decrease. Our revenue increase is attributable to higher natural gas and NGL prices both domestically and in New Zealand and higher oil prices in New Zealand and our increased levels of domestic production; offset by lower oil prices domestically and decreased production in New Zealand. Our production increased 9% to 17.8 Bcfe for the second quarter of 2007 as compared to second quarter 2006 production, due to our continued drilling success in our South Louisiana region along with production from the five new fields we acquired in that region in October 2006. Second quarter 2007 production included domestic production of 15.6 Bcfe, a 19% increase, and 2.2 Bcfe produced in New Zealand, a 30% decrease, in both cases when compared to production in the same period in 2006. For the six months ended June 30, 2007, net income decreased 22% to $59.1 million, revenues increased 9% to $309.3 million, and production increased 7% to 35.3 Bcfe, all as compared to the same period in 2006.

Our net income in the second quarter of 2007 was lower than during the same period in 2006 due to debt retirement expense of $12.8 million, or $0.26 per diluted share, $3.4 million of this amount was a non-cash charge. Had we not incurred this debt retirement cost, our net income in the second quarter 2007 would have been higher than our net income in the same period of 2006. Reported net income was $31.5 million or $1.03 per share. Cash flow provided by operating activities increased 20% to $120 million for the second quarter of 2007, again compared to the cash flow provided by operating activities in the second quarter of 2006. Production during the second quarter increased 9% to 17.8 Bcfe when compared to production in the comparable quarter in 2006. Weighted average domestic commodity prices were essentially flat while per unit costs excluding debt retirement costs increased 12%. The oil and gas sector, including Swift Energy Company, continued to see third party vendor costs increase during the second quarter.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Geoscience and engineering expertise is the backbone of our organization, demonstrated by our continued drilling success during the second quarter. In Lake Washington, we drilled and completed another Newport area well, the SL 17990 #11, which tested at 1,272 barrels of oil per day. The SL 212 #140 was drilled to a depth of approximately 10,600 feet and produced 1,002 barrels of oil and 966 Mcf of natural gas per day. In Bay de Chene, the UA #139 (Faria prospect) was brought on production during the second quarter at more than 6 Mmcfe per day increasing production 80% at Bay de Chene, while the BDC UB #142 which was drilling when the second quarter ended has logged 78 feet of net pay in 5 zones and is still drilling to evaluate deeper potential. These drilling results continue to reflect the high quality of our project inventory in these fields. Although we are experiencing short term constraints, it is evident that the opportunity for continued growth exists.

To allow for further production increases in our South Louisiana region, construction has begun on a new barge mounted production facility, which will add 10,000 Bbl/d of handling capacity in Lake Washington during the first half of 2008, and planning for an expansion of pipeline capacity in Bay de Chene began during the second quarter that is also expected to be completed in 2008.

Swift Energy will continue to utilize its proprietary merged 3D seismic data set in and around our asset base. This data set is allowing our high impact exploration inventory to grow in conjunction with an improved developmental drilling program. During the second half of 2007, we expect to drill 1 well in Cote Blanche Island, 3 wells in Bay de Chene, 6 wells in Lake Washington and up to 5 wells in the five new fields we acquired in our South Louisiana region last year. No drilling activity occurred in our New Zealand region during the first six months of 2007 and due to the on-going strategic review, no new drilling activity is planned for the remainder of the year.

Results of Operations – Three Months Ended June 30, 2007 and 2006

Revenues. Our revenues in the second quarter of 2007 increased by 14% compared to revenues in the same period in 2006, due primarily to an increase in production from our South Louisiana region, which includes the properties acquired during the fourth quarter of 2006, along with higher natural gas prices. These gains were partially offset by lower oil prices. In the second quarter of 2007, oil production made up 65% of total production, natural gas made up 28%, and NGL represented 7%. In the second quarter of 2006, oil production made up 60% of total production, natural gas made up 35%, and NGL represented 5%. The percentage of our total production from oil increased as production in South Louisiana fields, which are predominantly oil, increased over second quarter of 2006 levels.

Our second quarter 2007 weighted average prices increased 6% to $9.44 per Mcfe from $8.91 in the second quarter of 2006, with oil prices decreasing 5% to $66.48 per barrel from $69.63, natural gas prices increasing 31% to $6.26 per Mcf from $4.79, and NGL prices rising 37% to $40.60 per barrel from $29.72.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes for the periods ended June 30, 2007 and 2006:

	Three Months Ended June 30,
Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Sales Volumes (Bcfe)
	2007		2006		2007		2006
South Texas	$	14.3	$	15.2		1.7		2.1
Toledo Bend		11.5		8.1		1.2		0.9
South Louisiana		129.3		107.1		12.5		9.9
Other		1.2		0.9		0.2		0.2
Total Domestic	$	156.3	$	131.3		15.6		13.1
New Zealand		11.4		13.7		2.2		3.2
Total	$	167.7	$	145.0		17.8		16.3

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

The following table provides additional information regarding our quarterly oil and gas sales:

	Sales Volume								Average Sales Price
	Oil (MBbl)		NGL (MBbl)		Gas (Bcf)		Combined (Bcfe)		Oil (Bbl)		NGL (Bbl)		Gas (Mcf)
2007
Three Months Ended June 30:
Domestic		1,872		134		3.5		15.6	$	66.20	$	44.22	$	7.56
New Zealand		62		48		1.6		2.2	$	75.17	$	30.47	$	3.36
Total		1,934		182		5.1		17.8	$	66.48	$	40.60	$	6.26
2006
Three Months Ended June 30:
Domestic		1,554		70		3.3		13.1	$	69.40	$	40.85	$	6.12
New Zealand		82		68		2.3		3.2	$	73.90	$	18.14	$	2.83
Total		1,636		138		5.6		16.3	$	69.63	$	29.72	$	4.79

In the second quarter of 2007, our $22.7 million increase in oil, NGL, and natural gas sales resulted from:

Volume variances that had a $19.3 million favorable impact on sales, with $20.7 million of increases coming from the 298,000 Bbl increase in oil sales volumes, $1.3 million of increases attributable to the 44,000 Bbl increase in NGL sales volumes, partially offset by $2.7 million of decreases due to the 0.6 Bcf decrease in gas sales volumes; and

Price variances that had a $3.4 million favorable impact on sales, with $7.4 million of increases attributable to the 31% increase in average gas prices received, and $2.0 million of increases attributable to the 37% increase in average NGL prices received, partially offset by a $6.0 million decrease attributable to the 5% decrease in average oil prices received.

Costs and Expenses. Our expenses in the second quarter of 2007 increased $32.3 million, or 37%, compared to expenses in the same period of 2006. The increase was mainly due to a $10.8 million increase in DD&A as our production and the depletable oil and gas property base increased, and $12.8 million of debt retirement costs related to the redemption of our 9-3/8% Notes due 2012.

Our second quarter 2007 general and administrative expenses, net, increased $2.9 million, or 38%, from the level of such expenses in the same 2006 period. This increase was primarily due to an expansion of our workforce and an increase in stock compensation. Our stock compensation expense recorded in general and administrative, net, increased by $1.1 million, net of capitalized amounts, over second quarter of 2006 levels. For the second quarters of 2007 and 2006, our capitalized general and administrative costs, including capitalized stock compensation, totaled $7.1 million and $6.6 million, respectively. Our capitalized general and administrative expenses increased due to the expansion of our workforce and the capitalization of stock compensation related to the geological and geophysical workforce. Our net general and administrative expenses per Mcfe produced were $0.59 per Mcfe in the second quarter 2007 and $0.47 per Mcfe in the second quarter of 2006. The portion of supervision fees recorded as a reduction to general and administrative expenses was $2.7 million for the second quarter of 2007 and $2.2 million for the 2006 period.

DD&A increased $10.8 million, or 28%, in the second quarter of 2007 from the level of those expenses in the same period of 2006. Domestically, DD&A increased $11.9 million in the second quarter of 2007 due to increases in the depletable oil and gas property base, including future development costs and higher production in the 2007 period. In New Zealand, DD&A decreased by $1.1 million in the second quarter of 2007 due to lower production during the 2007 period, partially offset by increases in the depletable oil and gas property base and lower reserves volumes. Our DD&A rate per Mcfe of production was $2.80 and $2.39 in the second quarters of 2007 and 2006, respectively.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

We recorded $0.4 million and $0.2 million of accretion to our asset retirement obligation in the second quarters of 2007 and 2006.

Our lease operating costs in the second quarter of 2007 increased $1.6 million, or 9%, over the level of such expenses in the same 2006 period. Domestically, lease operating costs increased $0.8 million due to higher production from our South Louisiana area, including costs from properties acquired in 2006, and higher insurance costs. Our lease operating costs in New Zealand increased by $0.8 million due to planned plant maintenance and workover activities and the strengthening New Zealand dollar. Our lease operating costs per Mcfe produced were $1.13 in the second quarter of 2007 and $1.14 in the second quarter of 2006.

In the second quarter of 2007, severance and other taxes increased $2.6 million, or 16%, over levels in the second quarter of 2006. The increase was due primarily to higher production in South Louisiana and increased pricing. 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 increases, the overall percentage of severance taxes to sales also increases. Severance and other taxes, as a percentage of oil and gas sales, were approximately 11.2% and 11.0% in the second quarters of 2007 and 2006, respectively.

Our total interest cost in the second quarter of 2007 was $9.7 million, of which $2.4 million was capitalized. Our total interest cost in the second quarter of 2006 was $8.0 million, of which $2.2 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase of interest expense in the second quarter of 2007 was primarily attributable to increased borrowings against our line of credit and was also impacted by our note refinancing as we recorded, in June 2007, a partial month of interest on our retired $200 million notes and a full month of interest on our new $250 million notes. These costs were partially offset by higher capitalized costs.

In the second quarter of 2007, we recorded $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 a $3.4 million write-off unamortized debt issuance costs.

Our overall effective tax rate was 35.5% and 36.6% in the second quarters of 2007 and 2006. The effective income tax rate for both periods was higher than the U.S. statutory rate primarily due to state income taxes, and was partially offset by reductions attributable to the currency effect on the New Zealand operations. The second quarter of 2007 benefited from a decrease in the New Zealand statutory tax rate.

Net Income. For the second quarter of 2007, our net income of $31.5 million was 17% lower, and Basic EPS of $1.05 was 20% lower, than our second quarter of 2006 net income of $38.2 million and Basic EPS of $1.31. Our Diluted EPS in the second quarter of 2007 of $1.03 was 19% lower than our second quarter of 2006 Diluted EPS of $1.27. These lower amounts are due to the $12.8 million in expenses related to our notes refinancing during the second quarter of 2007.

Results of Operations – Six Months Ended June 30, 2007 and 2006

Revenues. Our revenues in the first six months of 2007 increased by 9% compared to revenues in the same period in 2006, due primarily to an increase in production from our South Louisiana region, which includes the properties acquired during the fourth quarter of 2006, partially offset by lower production in New Zealand. These gains were increased by higher natural gas prices and were partially offset by lower oil prices. In the six months of 2007, oil production made up 64% of total production, natural gas made up 30%, and NGL represented 6%. In the first six months of 2006, oil production made up 59% of total production, natural gas made up 35%, and NGL represented 6%. The percentage of our total production from oil increased as production in South Louisiana fields, which are predominantly oil, increased over 2006 levels.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Our first six months of 2007 weighted average prices increased 3% to $8.75 per Mcfe from $8.52 in the first six months of 2006, with oil prices decreasing 4% to $62.39 per barrel from $65.26, natural gas prices increasing 12% to $5.68 per Mcf from $5.10, and NGL prices rising 28% to $38.56 per barrel from $30.04.

The following table provides additional information regarding the changes in the sources of our oil and gas sales and volumes for the six months ended June 30, 2007 and 2006:

	Six Months Ended June 30,
Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Sales Volumes (Bcfe)
	2007		2006		2007		2006
South Texas	$	26.8	$	33.6		3.6		4.4
Toledo Bend		19.1		17.3		2.3		2.1
South Louisiana		238.3		195.9		24.6		19.0
Other		2.3		2.5		0.3		0.4
Total Domestic	$	286.5	$	249.3		30.8		25.9
New Zealand		22.2		30.6		4.5		7.0
Total	$	308.7	$	279.9		35.3		32.9

The following table provides additional information regarding our oil & gas sales for the six months ended June 30, 2007 and 2006:

	Sales Volume				Average Sales Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (Bcfe)	Oil (Bbl)	NGL (Bbl)	Gas (Mcf)
2007
Six Months Ended June 30:
Domestic	3,645	267	7.3	30.8	$62.14	$42.07	$6.71
New Zealand	124	96	3.2	4.5	$69.57	$28.72	$3.36
Total	3,769	363	10.5	35.3	$62.39	$38.56	$5.68
2006
Six Months Ended June 30:
Domestic	3,041	160	6.6	25.9	$65.08	$40.24	$6.76
New Zealand	206	130	5.0	7.0	$68.02	$17.44	$2.87
Total	3,247	290	11.6	32.9	$65.26	$30.04	$5.10

In the first six months of 2007, our $28.8 million increase in oil, NGL, and natural gas sales resulted from:

Volume variances that had a $30.4 million favorable impact on sales, with $34.1 million of increases coming from the 522,000 Bbl increase in oil sales volumes, and $2.2 million of increases attributable to the 72,000 Bbl increase in NGL sales volumes, partially offset by $5.9 million of decreases due to the 1.2 Bcf decrease in gas sales volumes; and

Price variances that had a $1.6 million unfavorable impact on sales, of which $10.8 million was attributable to the 4% decrease in average oil prices received, partially offset by $6.2 million of increases attributable to the 12% increase in average gas prices received, and by $3.0 million of increases attributable to the 28% increase in average NGL prices received.

Costs and Expenses. Our expenses in the first six months of 2007 increased $52.3 million, or 32%, compared to expenses in the same period of 2006. The increase was due to a $23.0 million increase in DD&A as our production and depletable oil and gas property base increased, $12.8 million of debt retirement costs related to the redemption of our 9-3/8% Notes due 2012, a $5.5 million increase in lease operating expenses due to higher production and increased insurance premiums, and a $4.6 million increase in severance and other taxes due to increased domestic production volumes in the first six months of 2007.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Our first six months of 2007 general and administrative expenses, net, increased $3.7 million, or 24%, from the level of such expenses in the same 2006 period. This increase was primarily due to an expansion of our workforce and an increase in stock compensation expense. Our stock compensation expense recorded in general and administrative, net, increased by $1.6 million, net of capitalized amounts, over first six months of 2006 levels. For the first six months of 2007 and 2006, our capitalized general and administrative costs, including capitalized stock compensation, totaled $15.5 million and $12.6 million, respectively. Our capitalized general and administrative expenses increased due to the expansion of our workforce and the capitalization of stock compensation related to the geological and geophysical workforce. Our net general and administrative expenses per Mcfe produced were $0.54 per Mcfe in the first six months of 2007 and $0.47 per Mcfe in the first six months of 2006. The portion of supervision fees recorded as a reduction to general and administrative expenses was $5.3 million for the first six months of 2007 and $4.2 million for the 2006 period.

DD&A increased $23.0 million, or 31%, in the first six months of 2007 from the level of those expenses in the same period of 2006. Domestically, DD&A increased $25.5 million in the first six months of 2007 due to increases in the depletable oil and gas property base, including future development costs and higher production in the 2007 period. In New Zealand, DD&A decreased by $2.5 million in the first six months of 2007 due to lower production during the 2007 period, partially offset by increases in the depletable oil and gas property base and lower reserves volumes. Our DD&A rate per Mcfe of production was $2.76 and $2.26 in the first six months of 2007 and 2006, respectively.

We recorded $0.8 million and $0.5 million of accretions to our asset retirement obligation in the first six months of 2007 and 2006.

Our lease operating costs in the first six months of 2007 increased $5.5 million, or 17%, over the level of such expenses in the same 2006 period. Domestically, lease operating costs increased $5.2 million due to higher production from our South Louisiana area, including costs from properties acquired in the fourth quarter of 2006, and higher insurance costs. Our lease operating costs in New Zealand increased by $0.3 million due to planned maintenance and the strengthening New Zealand dollar. Our lease operating costs per Mcfe produced were $1.09 in the first six months of 2007 and $1.00 in the first six months of 2006.

In the first six months of 2007, severance and other taxes increased $4.6 million, or 15%, over levels in the first six months of 2006. The increase was due primarily to higher production in South Louisiana, partially offset by lower oil prices. 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 increases, the overall percentage of severance taxes to sales also increases. Severance and other taxes, as a percentage of oil and gas sales, were approximately 11.5% and 11.0% in the first six months of 2007 and 2006, respectively.

Our total interest cost in the first six months of 2007 was $19.0 million, of which $5.0 million was capitalized. Our total interest cost in the first six months of 2006 was $16.0 million, of which $4.3 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase of interest expense in the first six months of 2007 was primarily attributable to increased borrowings against our line of credit and was also impacted by our note refinancing as we recorded, in June 2007, a partial month of interest on our retired $200 million notes and a full month of interest on our new $250 million notes. These increased costs were offset partially by higher capitalized costs. The increase in borrowings during the first six months of 2007 was primarily due to our fourth quarter 2006 property acquisitions.

In the second quarter of 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 35.5% and 36.0% in the first six months of 2007 and 2006, respectively. The effective income tax rate for both periods was higher than the U.S. statutory rate primarily due to state income taxes, and was partially offset by reductions attributable to the currency effect on the New Zealand operations. The six month period of 2007 benefited from a decrease in the New Zealand statutory tax rate.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Net Income. For the first six months of 2007, our net income of $59.1 million was 22% lower, and Basic EPS of $1.98 was 24% lower, than our first six months of 2006 net income of $75.5 million and Basic EPS of $2.59. Our Diluted EPS in the first six months of 2007 of $1.93 was also 23% lower than our first six months of 2006 Diluted EPS of $2.52. These lower amounts are due to an increase in costs that exceeded the increase in oil and gas revenues during the first six months quarter of 2007 and were also impacted by the $12.8 million in expenses related to our notes refinancing during the second quarter of 2007.

Share-Based Compensation

Effective January 1, 2006, the Company adopted SFAS No. 123R, “Share-Based Payment” utilizing the modified prospective approach. Prior to the adoption of SFAS No. 123R, we accounted for stock option grants in accordance with APB No. 25, “Accounting for Stock Issued to Employees” (the intrinsic value method), and accordingly, recognized no compensation expense for employee stock option grants. The adoption of SFAS No. 123R will increase our compensation expense related to employee stock option grants over pre-implementation period levels.

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 in both the three months ended June 30, 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 the new standard.

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 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 condensed consolidated statements of operations.

We continue to 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:

	Three Months Ended						Six Month Ended
	June 30,						June 30,
	2007			2006			2007			2006

Dividend yield		0	%		0	%		0	%		0	%
Expected volatility		37.7	%		39.3	%		38.5	%		39.5	%
Risk-free interest rate		5.1	%		5.1	%		4.8	%		4.9	%
Expected life of options (in years)		1.9			1.8			6.2			5.6
Weighted-average grant-date fair value	$	10.73		$	9.71		$	20.10		$	19.33

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 analysis of all relevant factors use a three-year period to estimate expected volatility of our stock option grants. 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.

At June 30, 2007, there was $5.0 million of unrecognized compensation cost related to stock options, which are expected to be recognized over a weighted-average period of 1.5 years, and unrecognized compensation expense of $21.8 million related to restricted stock awards which are expected to be recognized over a weighted-average period of 2.0 years. The compensation expense for restricted stock awards was determined based on the market price of our stock at the date of grant applied to the total numbers of shares that were anticipated to fully vest.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Contractual Commitments and Obligations

We had no material changes in our contractual commitments and obligations from December 31, 2006 amounts referenced under “Contractual Commitments and Obligations” in Management’s Discussion and Analysis” in our Annual Report on form 10-K for the period ending December 31, 2006.

Internal Control over Financial Reporting

We began an implementation of a new computer system in early 2006; and effective April 1, 2007, we went operational with core elements of the new system. When fully functional, this system will fully integrate our accounting processes from production of oil and gas to receipt of cash and from rocurement of products and services to payment for such costs. It also further automates our financial reporting processes. The system being replaced utilizes multiple systems that covered the production of oil and gas, procurement of products and services, and the financial reporting process. With this new computer system, we anticipate a positive impact on our internal control over financial reporting, and the Company has updated its internal control over financial reporting as necessary to accommodate these changes.

With any such change, management testing of the effectiveness of the new system’s impact on the Company’s internal control environment is ongoing, and most likely will not be complete until late 2007. Until the system is fully tested, management continues to perform other parallel procedures and analyses related to the financial closing and accrual processes to ensure the integrity of the Company’s financial statements.

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 in the first six months of 2007 from levels seen in late 2006 and it is currently significantly higher 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 and Africa, can cause wide fluctuations in the price of oil. Domestic natural gas prices continue to remain higher when compared to longer-term historical prices. North American weather conditions, the industrial and consumer demand for natural gas, storage levels of natural gas, availability of LNG from foreign sources, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas.

Income Tax Regulations

The tax laws in the jurisdictions in which we operate continuously change and professional judgments regarding such tax laws can differ.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Liquidity and Capital Resources

During the first six months of 2007, we relied upon our net cash provided by operating activities of $206.1 million to fund capital expenditures of $189.6 million. During the first six months of 2006, we relied upon our net cash provided by operating activities of $183.8 million and proceeds from the sale of property and equipment of $20.3 million to fund capital expenditures of $183.9 million.

Acquisitions. In October 2006, we acquired interests in five South Louisiana fields from BP America Production Company. The total price for these interests was approximately $168 million. The property interests are located primarily 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. In addition, we have acquired virtually all of the remaining outstanding interest in the South Bearhead Creek field, located in Beauregard Parish, Louisiana, for $4.5 million in November 2006.

Net Cash Provided by Operating Activities. For the first six months of 2007, our net cash provided by operating activities was $206.1 million, representing a 12% increase as compared to $183.8 million generated during the same 2006 period. The $22.3 million increase in the first six months of 2007 was primarily due to adding back increased DD&A and debt retirement costs, somewhat offset by a lower net income and deferred income taxes for the six months ended at June 30, 2007.

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 June 30, 2007 and December 31, 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 Bank Credit Facility. We had no borrowings at June 30, 2007 and $31.4 million in borrowings under our bank credit facility at December 31, 2006. At March 31, 2007, we had $64.0 million outstanding under the credit facility and on June 1, 2007; the facility was paid down with proceeds from the issuance of $250.0 million in senior notes issued on that date as described below along with cash flow from operating activities during that period. Our bank credit facility consists of a $500.0 million revolving line of credit with a $350.0 million borrowing base. The borrowing base is re-determined at least every six months and the next scheduled review is 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. 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 our operations, financial condition, prospects or properties, and would impair our 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.

Repurchase of Senior Subordinated Notes due 2012. On June 18, 2007, we redeemed all $200.0 million of our senior subordinated notes due 2012, and recorded debt retirement costs of $12.8 million related to this redemption.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

Issuance of 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. 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.

Debt Maturities. Our credit facility, which did not have a balance at June 30, 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.

Working Capital. Our working capital improved from a deficit of $53.4 million at December 31, 2006, to a deficit of $30.9 million at June 30, 2007. The improvement primarily resulted from a decrease in accounts payable and accrued liabilities balances during the first six months of 2007.

Capital Expenditures. In the first six months of 2007, we relied upon our net cash provided by operating activities of $206.1 million to fund capital expenditures of $189.6 million. Our total capital expenditures of approximately $189.6 million in the first six months of 2007 included Domestic expenditures of $182.8 million as follows:

·	$102.3 million for drilling and developmental activity costs, predominantly in our South Louisiana area;

·	$37.3 million of domestic prospect costs, principally related to seismic activities, prospect leasehold, and geological costs of unproved prospects;

·	$36.6 million for exploratory drilling;

·	$3.7 million primarily for leasehold improvements in our Houston office, software, computer equipment, vehicles, furniture, and fixtures;

·	$2.9 million for acquisitions of properties.

New Zealand expenditures of $6.8 million as follows:

·	$3.1 million for developmental activity, and gas processing plant costs;

·	$2.8 million on prospect costs and geological costs of unproved properties;

·	$0.8 million for exploratory activities;

·	and less than $0.1 million for computer equipment, software, furniture, and fixtures.

We completed 24 of 30 domestic wells in the first six months of 2007, for a success rate of 80%. A total of 19 wells were drilled in the Lake Washington area, of which 15 were completed, and 5 wells were drilled and completed in the South Bearhead Creek area. Two wells were also drilled and completed in the AWP Olmos area, and two out of four wells were drilled and completed in Bay de Chene. No drilling activity occurred in our New Zealand region during the first six months of 2007 and due to the previously announced review of strategic alternatives in New Zealand, no drilling activity is planned there for the remainder of the year.

Swift Energy adjusted its 2007 capital spending budget to a new range of $375 - $400 million from the previous range of $350 - $400 million, net of acquisitions and dispositions. Approximately 95% of the budget is targeted for domestic activities, predominantly in our South Louisiana region, with about 5% planned for maintenance activities in the New Zealand region. We are adjusting our 2007 annual production growth forecast to a range of 1% to 3% over 2006 levels, which includes domestic production growth of 10% to 13% over 2006 levels. While no change is being made to our reserves growth guidance of 4% to 6% over 2006 levels, we currently believe that it will come in at the low end of that range. We may also increase our capital expenditure budget if commodity prices rise during the year or if strategic opportunities warrant. If 2007 capital expenditures exceed our cash flow from operating activities, we can fund these expenditures with our credit facility.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

For the first half of 2007, Swift Energy spent $189.6 million on capital expenditures compared to $183.9 for the 2006 period. For the last six months of 2007, we expect to make capital expenditures of approximately $185 to $210 million. Capital expenditures for all of 2006 were $557.5 million.

During the last six months of 2007, we anticipate drilling or participation in the drilling of up to an additional 15 to 17 development and exploration wells in the South Louisiana region, an additional 6 to 8 development wells in the AWP Olmos area, and several additional wells, with varying working interest percentages, mainly in the Toledo Bend region.

Our 2007 capital expenditures continue to be focused on developing and producing long-lived reserves in South Louisiana, South Texas, and Toledo Bend regions, along with property acquisitions and an expansion of our Lake Washington facilities. We expect our 2007 total production to increase over 2006 levels, primarily from our South Louisiana area. Our production in the South Texas region is expected to remain relatively flat. We expect production in our other regions to decrease as a limited amount of new drilling is currently budgeted to offset the natural production decline of these regions.

New Accounting Pronouncements

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS-Continued

SWIFT ENERGY COMPANY AND SUBSIDIARIES

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 and 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, 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. Among the factors that could cause actual results to differ materially are the uncertainty of finding, replacing, developing or acquiring reserves; fluctuations in crude oil, natural gas and natural gas liquids prices or demand; adequate availability of markets, facilities, skilled personnel, services and supplies; hurricanes or tropical storms affecting operations; the uncertainty of drilling results; potential failure or delays in achieving reserve or production levels from existing and future oil and gas development projects due to operating hazards, drilling risks and the inherent uncertainties in predicting oil and gas reserves and oil and gas reservoir performance; requirements for 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 herein, and set forth from time to time in our other public reports, filings and public statements. Also, because of the volatility in oil and gas prices and other factors, interim results are not necessarily indicative of those for a full year.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Commodity Risk

Our major market risk exposure is the volatile 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 derivative instruments (such as futures, forward contracts, swaps, and option contracts such as floors and collars) to mitigate price risk associated with fluctuations in oil and natural gas prices. Below is a description of the derivative instruments we have utilized to hedge our exposure to price risk.

Price Floors – At June 30, 2007, we had in place price floors in effect through the September 2007 contract month for natural gas, which are expected to cover approximately 35% to 40% of our domestic natural gas production for July 2007 through September 2007. The natural gas floors cover notional volumes of 1,350,000 Mmbtu, and expire at various dates from July 2007 to September 2007, with a weighted average floor price of $7.11 per Mmbtu.

New Zealand Gas Contracts – All of our current gas production in New Zealand is sold under fixed-price contracts denominated in New Zealand dollars. These contracts protect against price volatility, and our revenue from these contracts will vary only due to production fluctuations and foreign exchange rates.

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 that the loss of any single oil or gas customer would have a material adverse effect on our financial position or results of operations.

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 obligations, all denominated in New Zealand dollars. We use the U.S. dollar as our functional currency in New Zealand and because of this; our results of operations, cash flows and effective tax rate are impacted from fluctuations between the U.S. dollar and the New Zealand dollar.

Interest Rate Risk

Our Senior Notes due 2011 and Senior Notes due 2017 have fixed interest rates; consequently we are not exposed to cash flow risk from market interest rate changes on these notes. However, there is a risk that market rates will decline and the required interest payments on our Senior Notes and Senior Subordinated Notes may exceed those payments based on the current market rate. At June 30, 2007, we had no borrowings under our credit facility, which is subject to floating rates and therefore susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 83 basis points and would not have a material adverse effect on our 2007 cash flows based on this same level or a modest level of borrowing.

Item 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in our filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Our chief executive officer and chief financial officer have evaluated our disclosure controls and procedures as of the end of the period covered by this report and have concluded that such disclosure controls and procedures are effective in ensuring that material information required to be disclosed in this report is accumulated and communicated to them and our management to allow timely decisions regarding required disclosure.

Internal Control Over Financial Reporting

Effective April 1, 2007, we went operational with core elements of the new computer system, which management considers a change in our internal control over financial reporting. An obvious contributor to the implementation decision was the anticipated enhancements of our internal control over financial reporting that the new system represents. When fully functional, this system will fully integrate our accounting processes from production of oil and gas to receipt of cash and from procurement of products and services to payment for such costs. It also further automates our financial reporting processes.

SWIFT ENERGY COMPANY

PART II. - OTHER INFORMATION

Item 1. Legal Proceedings.

No material legal proceedings are pending other than ordinary, routine litigation incidental to the Company’s business.

Item 1A. Risk Factors.

There have been no material changes in our risk factors from those disclosed in our 2006 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

The following table summarizes repurchases of our common stock occurring during the second quarter of 2007:

Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in thousands)

04/01/07 - 05/31/07 (1)	471	$41.80	---	$---
05/01/07 - 05/31/07 (1)	164	41.10	---	---
06/01/07 - 06/30/07 (1)	---	---	---	---
Total	635	$41.62	---	$---

(1) These shares were withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares.

Item 3. Defaults Upon Senior Securities.

None.

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

Our annual meeting of shareholders was held on May 8, 2007. At the record date, 29,888,761 shares of common stock were outstanding and entitled to one vote per share upon all matters submitted at the meeting. At the annual meeting, Raymond E. Galvin, Greg Matiuk and Henry C. Montgomery were elected to serve as directors of Swift Energy for three year terms to expire at the 2010 annual meeting of shareholders. These directors were elected by the following votes:

Nominees For Director	For	Withheld

Raymond E. Galvin	14,512,730	13,414,379
Greg Matiuk	14,387,009	13,540,100
Henry C. Montgomery	14,500,839	13,426,270

The following two proposals were also approved at the annual meeting:

	For	Against	Abstain	Broker Non-Vote

Proposal to amend the Company’s 2005 Stock Compensation Plan	22,888,786	2,384,644	23,918	2,629,761
Approval of Ratification of Ernst & Young LLP as Swift Energy Company’s Independent Auditors for the fiscal year ending December 31, 2006	27,892,519	26,507	8,083	0

Item 5. Other Information.

None.

Item 6. Exhibits.

		4.1	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).

		4.2	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	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).

		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.

*	Filed herewith

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	SWIFT ENERGY COMPANY (Registrant)

Date: August 2 2007	By:	/s/ Alton D. Heckaman, Jr.
		Alton D. Heckaman, Jr. Executive Vice President and Chief Financial Officer

Date: August 2, 2007	By:	/s/ David W. Wesson.
		David W. Wesson Controller and Principal Accounting Officer