Edgar Filing: SWIFT ENERGY CO

edgar2q2010.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, 2010

Commission File Number 1-8754

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in Its Charter)

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

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

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 has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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

Smaller reporting company

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)

37,878,628 Shares

(Outstanding at July 31, 2010)

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2010

INDEX

		Page
Part I	FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements

	Condensed Consolidated Balance Sheets	3
	- June 30, 2010 and December 31, 2009

	Condensed Consolidated Statements of Operations	4
	- For the Three month and Six month periods ended June 30, 2010 and 2009

	Condensed Consolidated Statements of Stockholders’ Equity	5
	- For the Six month period ended June 30, 2010 and year ended December 31, 2009

	Condensed Consolidated Statements of Cash Flows	6
	- For the Six month periods ended June 30, 2010 and 2009

	Notes to Condensed Consolidated Financial Statements	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24

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	37
Item 3.	Defaults Upon Senior Securities	None
Item 5.	Other Information	37
Item 6.	Exhibits	37
SIGNATURES		38
Exhibit Index		39
Certification of CEO Pursuant to rule 13a-14(a)
Certification of CFO Pursuant to rule 13a-14(a)
Certification of CEO & CFO Pursuant to Section 1350

Condensed Consolidated Balance Sheets

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)

	June 30, 2010 (Unaudited)			December 31, 2009
ASSETS
Current Assets:
Cash and cash equivalents	$	43,484		$	38,469
Accounts receivable		40,022			54,273
Deferred tax assets		4,468			3,171
Other current assets		18,514			12,123
Current assets held for sale		564			564
Total Current Assets		107,052			108,600

Property and Equipment:
Oil and gas properties, using full-cost accounting		3,689,276			3,530,110
Less – Accumulated depreciation, depletion, and amortization		(2,292,193	)		(2,214,146	)
Property and Equipment, Net		1,397,083			1,315,964

Other Long-Term Assets		9,710			10,201
Total Assets	$	1,513,845		$	1,434,765

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	62,748		$	60,823
Accrued capital costs		47,236			33,199
Accrued interest		10,982			3,745
Undistributed oil and gas revenues		5,775			5,837
Total Current Liabilities		126,741			103,604

Long-Term Debt		471,508			471,397
Deferred Income Taxes		143,444			123,577
Asset Retirement Obligation		57,230			55,298
Other Long-Term Liabilities		1,871			1,990

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, 38,316,362 and 37,887,126 shares issued, and 37,876,893 and 37,456,603 shares outstanding, respectively		383			379
Additional paid-in capital		559,303			551,606
Treasury stock held, at cost, 439,469 and 430,523 shares, respectively		(9,713	)		(9,221	)
Retained earnings		163,022			136,358
Accumulated other comprehensive income (loss), net of income tax		56			(223	)
Total Stockholders’ Equity		713,051			678,899
Total Liabilities and Stockholders’ Equity	$	1,513,845		$	1,434,765

See accompanying Notes to Consolidated Financial Statements.

Condensed Consolidated Statements of Operations (Unaudited)

Swift Energy Company and Subsidiaries

(in thousands, except share amounts)

	Three Months Ended						Six Months Ended
	06/30/10			06/30/09			06/30/10			06/30/09
Revenues:
Oil and gas sales	$	105,051		$	82,783		$	215,076		$	159,201
Price-risk management and other, net		1,849			138			1,670			79
Total Revenues		106,900			82,921			216,746			159,280

Costs and Expenses:
General and administrative, net		8,037			7,581			17,288			16,000
Depreciation, depletion, and amortization		39,029			40,365			77,303			84,299
Accretion of asset retirement obligation		975			717			1,929			1,419
Lease operating cost		19,936			18,818			38,584			38,626
Severance and other taxes		11,641			9,908			23,213			18,594
Interest expense, net		8,214			7,813			16,540			15,280
Write-down of oil and gas properties		---			---			---			79,312
Total Costs and Expenses		87,832			85,202			174,857			253,530


Income (Loss) from Continuing Operations Before Income Taxes		19,068			(2,281	)		41,889			(94,250	)

Provision (Benefit) for Income Taxes		6,555			(71	)		15,136			(33,037	)

Income (Loss) from Continuing Operations		12,513			(2,210	)		26,753			(61,213	)

Loss from Discontinued Operations, net of taxes		(54	)		(57	)		(89	)		(183	)

Net Income (Loss)	$	12,459		$	(2,267	)	$	26,664		$	(61,396	)

Per Share Amounts-

Basic: Income (Loss) from Continuing Operations	$	0.32		$	(0.07	)	$	0.70		$	(1.97	)
Loss from Discontinued Operations, net of taxes		(0.00	)		(0.00	)		(0.00	)		(0.01	)
Net Income (Loss)	$	0.32		$	(0.07	)	$	0.69		$	(1.97	)

Diluted: Income (Loss) from Continuing Operations	$	0.32		$	(0.07	)	$	0.69		$	(1.97	)
Loss from Discontinued Operations, net of taxes		(0.00	)		(0.00	)		(0.00	)		(0.01	)
Net Income (Loss)	$	0.32		$	(0.07	)	$	0.69		$	(1.97	)

Weighted Average Shares Outstanding		37,845			31,175			37,749			31,103


See accompanying Notes to 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			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
Balance, December 31, 2008	$	313	$	435,307		$	(10,431	)	$	175,688		$	-		$	600,877

Stock issued for benefit plans (94,023 shares)		-		(716	)		2,094			-			-			1,378
Stock options exercised (26,056 shares)		-		326			-			-			-			326
Public stock offering (6,210,000 shares)		62		108,689			-			-			-			108,751
Purchase of treasury shares (56,662 shares)		-		-			(884	)		-			-			(884	)
Tax benefits from stock compensation		-		(4,041	)		-			-			-			(4,041	)
Employee stock purchase plan (50,690 shares)		1		724			-			-			-			725
Issuance of restricted stock (263,908 shares)		3		(3	)		-			-			-			-
Amortization of stock compensation		-		11,320			-			-			-			11,320
Net loss		-		-			-			(39,330	)		-			(39,330	)
Other comprehensive loss		-		-			-			-			(223	)		(223	)
Total comprehensive loss																(39,553	)
Balance, December 31, 2009	$	379	$	551,606		$	(9,221	)	$	136,358		$	(223	)	$	678,899

Stock issued for benefit plans (59,335 shares) (2)		-		242			1,271			-			-			1,513
Stock options exercised (58,798 shares) (2)		-		824			-			-			-			824
Purchase of treasury shares (68,281 shares) (2)		-		-			(1,763	)		-			-			(1,763	)
Employee stock purchase plan (66,564 shares) (2)		1		950			-			-			-			951
Issuance of restricted stock (303,874 shares) (2)		3		(3	)		-			-			-			-
Amortization of stock compensation (2)		-		5,684			-			-			-			5,684
Net Income (2)		-		-			-			26,664			-			26,664
Other comprehensive income (2)		-		-			-			-			279			279
Total comprehensive income (2)																26,943
Balance, June 30, 2010 (2)	$	383	$	559,303		$	(9,713	)	$	163,022		$	56		$	713,051

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


See accompanying Notes to Consolidated Financial Statements.

Condensed Consolidated Statements of Cash Flows (Unaudited)

Swift Energy Company and Subsidiaries

(in thousands)	Six Months Ended June 30,
	2010			2009
Cash Flows from Operating Activities:
Net income (loss)	$	26,664		$	(61,396	)
Plus loss from discontinued operations, net of taxes		89			183
Adjustments to reconcile net income (loss) to net cash provided by operation activities -
Depreciation, depletion, and amortization		77,303			84,299
Write-down of oil and gas properties		---			79,312
Accretion of asset retirement obligation		1,929			1,419
Deferred income taxes		20,502			(29,905	)
Stock-based compensation expense		4,905			4,645
Other		(1,741	)		10,162
Change in assets and liabilities-
Decrease in accounts receivable		2,951			2,526
Decrease in accounts payable and accrued liabilities		(10,780	)		(7,406	)
Decrease in income taxes payable		(41	)		(241	)
Increase (decrease) in accrued interest		7,237			(25	)
Cash provided by operating activities – continuing operations		129,018			83,573
Cash provided by (used in) operating activities – discontinued operations		4			(337	)
Net Cash Provided by Operating Activities		129,022			83,236

Cash Flows from Investing Activities:
Additions to property and equipment		(129,116	)		(135,801	)
Proceeds from the sale of property and equipment		97			52
Cash used in investing activities – continuing operations		(129,019	)		(135,749	)
Cash provided by investing activities – discontinued operations		5,000			5,000
Net Cash Used in Investing Activities		(124,019	)		(130,749	)

Cash Flows from Financing Activities:
Net proceeds from bank borrowings		---			47,300
Net proceeds from issuances of common stock		1,775			818
Purchase of treasury shares		(1,763	)		(657	)
Cash provided by financing activities – continuing operations		12			47,461
Cash provided by financing activities – discontinued operations		---			---
Net Cash Provided by financing activities		12			47,461

Net Increase (decrease) in Cash and Cash Equivalents		5,015		$	(52	)

Cash and Cash Equivalents at Beginning of Period		38,469			283

Cash and Cash Equivalents at End of Period	$	43,484		$	231

Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	$	8,725		$	14,579
Cash paid during period for income taxes	$	168		$	229


See accompanying Notes to 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 (“Swift Energy” or the “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, 2009 as filed with the Securities and Exchange Commission.

(2) Summary of Significant Accounting Policies

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

Discontinued Operations. Unless otherwise indicated, information presented in the notes to the financial statements relates only to Swift Energy’s continuing operations. Information related to discontinued operations is included in Note 6 and in some instances, where appropriate, is included as a separate disclosure within the individual footnotes.

Subsequent Events. We have evaluated subsequent events of our consolidated financial statements. There were no material subsequent events requiring additional disclosure in or amendments to these financial statements.

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

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

·	estimates related to the collectability of accounts receivable and the credit worthiness of our customers,

·	estimates of the counterparty bank risk related to letters of credit that our customers may have issued on our behalf,

·	estimates of future costs to develop and produce reserves,

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

·	estimates of insurance recoveries related to property damage, and the solvency of insurance providers,

·	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.

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the six months ended June 30, 2010 and 2009, such internal costs capitalized totaled $11.9 million and $12.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the six months ended June 30, 2010 and 2009, capitalized interest on unproved properties totaled $3.7 million and $3.0 million, respectively. Interest not capitalized and general and administrative costs related to production and general corporate overhead are expensed as incurred.

The “Property and Equipment” balances on the accompanying condensed consolidated balance sheets are summarized for presentation purposes. The following is a detailed breakout of our “Property and Equipment” balances.

Property and Equipment (in thousands)	June 30, 2010			December 31, 2009

Oil and gas properties, using full-cost accounting
Proved properties	$	3,575,208		$	3,421,340
Unproved properties		77,097			71,640
Furniture, fixtures, and other equipment		36,971			37,130
Less – Accumulated depreciation, depletion, and amortization		(2,292,193	)		(2,214,146	)
Property and Equipment, Net	$	1,397,083		$	1,315,964

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

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

We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method. Under this method, we compute the provision by multiplying the total unamortized costs of oil and natural gas properties—including future development costs, gas processing facilities, and both capitalized asset retirement obligations and undiscounted abandonment costs of wells to be drilled, net of salvage values, but excluding costs of unproved properties—by an overall rate determined by dividing the physical units of oil and natural gas produced during the period by the total estimated units of proved oil and natural gas reserves at the beginning of the period. This calculation is done on a country-by-country basis, and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between 2 and 20 years. Repairs and maintenance are charged to expense as incurred. Renewals and betterments are capitalized.

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

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, 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, 2010 did not materially affect this calculation. This calculation is done on a country-by-country basis.

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

As a result of low oil and natural gas prices at March 31, 2009, we reported a non-cash write-down on a before-tax basis of $79.3 million on our oil and natural gas properties.

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

Revenue Recognition. Oil and gas revenues are recognized when production is sold to a purchaser at a fixed or determinable price, when delivery has occurred and title has transferred, and if collectability of the revenue is probable. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying consolidated balance sheets. 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, 2010, 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.

Fair Value of Financial Instruments. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. The fair values of the bank borrowings approximate the carrying amounts as of June 30, 2010 and December 31, 2009, and were determined based upon variable interest rates currently available to us for borrowings with similar terms. Based upon quoted market prices as of June 30, 2010 and December 31, 2009, the fair value of our senior notes due 2017, were $238.8 million, or 96% of face value, and 239.1 million, or 96% of face value, respectively. Based upon quoted market prices as of June 30, 2010 and December 31, 2009, the fair values of our senior notes due 2020, which were issued in November 2009, were $224.2 million, or 99% of face value and 234.0 million, or 104% of face value, respectively. The carrying value of our senior notes due 2017 was $250.0 million at June 30, 2010 and December 31, 2009, while the carrying value of our senior notes due 2020 was $221.5 million and $221.4 million at June 30, 2010 and December 31, 2009, respectively.

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At June 30, 2010 and December 31, 2009, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

At June 30, 2010 our “Accounts Receivable” balance includes $33.3 million for oil and gas sales, $2.7 million for joint interest owners and $4.0 million for other receivables. At December 31, 2009 our “Accounts Receivable” balance includes $36.4 million for oil and gas sales, $2.6 million for joint interest owners and $15.3 million for other receivables.

Insurance Claims. In 2008, we filed insurance claims related to 2008 Hurricanes Gustav and Ike. In April 2009, we settled our marine insurance claim relating to Hurricane Gustav for a net amount after deductible of $6.8 million, and in September 2009 settled our onshore claim relating to Hurricane Ike for a net amount after deductible of $0.8 million. Both of these reimbursements related to both capital costs and lease operating expense, and we have no additional hurricane related claims outstanding.

We have several open insurance claims filed in the ordinary course of business, none of which are material at the present time.

Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. The guidance 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 statement of operations 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 natural gas prices, mainly through the purchase of price floors and collars. During the second quarter of 2010 and 2009, we recognized a net gain of $1.5 million and a net loss of less than $0.1 million, respectively, relating to our derivative activities. During the first six months of 2010 and 2009, we recognized a net gain of $1.0 million and a net loss of less than $0.1 million, respectively, relating to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. Had these losses been recognized in the oil and gas sales account they would not materially change our per unit sales prices received. At June 30, 2010, the Company had recorded less than $0.1 million, net of taxes of less than $0.1 million, as derivative gains in “Accumulated other comprehensive loss, net of income tax” on the accompanying consolidated balance sheet. This amount represents the change in fair value for the effective portion of our hedging transactions that qualified as cash flow hedges. The ineffectiveness reported in “Price-risk management and other, net” at June 30, 2010 and 2009 was not material. All amounts currently held in “Accumulated other comprehensive loss, net of income tax” will be realized within the next three months when the forecasted sale of hedged production occurs.

At June 30, 2010, we had natural gas price floors in effect for the contract months of July through August 2010 that cover natural gas production of 1,725,000 MMBtu from July through August 2010 with strike prices ranging between $4.60 and $4.95. We also had oil price floors in effect for the contract month of July 2010 that cover oil production of 45,000 Boe for July 2010 with a strike price of $79.50.

When we entered into these transactions discussed above, they were designated as a hedge of the variability in cash flows associated with the forecasted sale of oil and natural gas production. Changes in the fair value of a hedge that is highly effective and is designated and documented and qualifies as a cash flow hedge, to the extent that the hedge is effective, are recorded in “Accumulated other comprehensive loss, net of income tax.” When the hedged transactions are recorded upon the actual sale of the oil and natural gas, these gains or losses are reclassified from “Accumulated other comprehensive income (loss), net of income tax” on the accompanying condensed consolidated balance sheet and recorded in “Price-risk management and other, net” on the accompanying consolidated statements of operations. The fair values of our derivatives are computed using the Black-Scholes-Merton option pricing model and are periodically verified against quotes from brokers. The fair value of these instruments at June 30, 2010 and December 31, 2009, was $0.5 million and $0.8 million, respectively and was recognized on the accompanying condensed consolidated balance sheet in “Other current assets.” At June 30, 2010, we had $0.7 million in receivables for concluded natural gas hedges covering July 2010 production and oil hedges covering June 2010 production which were recognized on the accompanying balance sheet in “Other Receivables” and were subsequently collected in July 2010.

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees, to the extent they do not exceed actual costs incurred, are recorded as a reduction to “General and administrative, net.” Our supervision fees are based on COPAS guidelines. The amount of supervision fees charged in the first six months of 2010 and 2009 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operate was $6.0 million and $5.7 million in the first six months of 2010 and 2009, respectively.

Inventories. Inventories consist primarily of tubulars and other equipment that we expect to place in service in production operations. Inventories carried at cost (weighted average method) are included in “Other current assets” on the accompanying condensed consolidated balance sheets totaling $13.0 million at June 30, 2010 and $10.0 million at December 31, 2009.

Income Taxes. Under guidance contained in FASB ASC 740-10, 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.

We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25. Under this guidance, 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. Our current balance of unrecognized tax benefits is $1.0 million. If recognized, these tax benefits would fully impact our effective tax rate.

Our policy is to record interest and penalties relating to income taxes in income tax expense. As of June 30, 2010, we did not have any amount accrued for interest and penalties on uncertain tax positions.

Our U.S. Federal income tax returns for 2002 forward, our Louisiana income tax returns from 1998 forward, our New Zealand income tax returns after 2003, and our Texas franchise tax returns after 2006 remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other state returns are significant to our financial position.

Accounts Payable and Accrued Liabilities. Included in “Accounts payable and accrued liabilities,” on the accompanying condensed consolidated balance sheets, at June 30, 2010 and December 31, 2009 are liabilities of approximately $2.2 million and $7.5 million, respectively, which represent the amounts by which checks issued, but not presented by vendors to the Company’s banks for collection, exceeded balances in the applicable disbursement bank accounts.

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

Restricted Cash. These balances primarily include amounts held in escrow accounts to satisfy domestic plugging and abandonment obligations. As of June 30, 2010 and December 31, 2009 these assets include approximately $1.3 million in other long-term assets on the balance sheet. These amounts are restricted as to their current use, and will be released when we have satisfied all plugging and abandonment obligations in certain fields.

Accumulated Other Comprehensive Income (Loss), Net of Income Tax. We follow the guidance contained in FASB ASC 220-10, 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, 2010, the Company had recorded less than $0.1 million, net of taxes of less than $0.1 million, as derivative gains in “Accumulated other comprehensive income (loss), net of income tax” on the accompanying consolidated balance sheet. The components of accumulated other comprehensive income and related tax effects for 2010 were as follows (in thousands):

	Gross Value			Tax Effect			Net of Tax Value

Other comprehensive loss at December 31, 2009	$	(354	)	$	131		$	(223	)
Change in fair value of cash flow hedges		1,313			(485	)		828
Effect of cash flow hedges settled during the period		(870	)		321			(549	)
Other comprehensive income at June 30, 2010	$	89		$	(33	)	$	56

Total comprehensive income (loss) was $11.6 million and ($2.5) million for the second quarters of 2010 and 2009, respectively. Total comprehensive income (loss) was $26.9 million and ($61.6) million for the six months of 2010 and 2009, respectively.

Asset Retirement Obligation. We record these obligations in accordance with the guidance contained in FASB ASC 410-20. This guidance 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 expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis over the estimated oil and natural gas reserves of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the full cost balance. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

The following provides a roll-forward of our asset retirement obligation:

(in thousands)	2010			2009

Asset Retirement Obligation recorded as of January 1	$	64,236		$	48,785
Accretion expense		1,929			1,420
Liabilities incurred for new wells and facilities construction		524			3,234
Reductions due to sold and abandoned wells		(75	)		(504	)
Revisions in estimated cash flows		---			306
Asset Retirement Obligation as of June 30	$	66,614		$	53,241

At June 30, 2010 and December 31, 2009, approximately $9.4 million and $8.9 million, respectively, of our asset retirement obligation is classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

Public Stock Offering. In August 2009, we issued 6.21 million shares of our common stock in an underwritten public offering at a price of $18.50 per share. The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million.

New Accounting Pronouncements. In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries – Oil and Gas”) with the requirements of SEC release 33-8995. This release is effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The most significant changes include:

Changes to prices used in reserves calculations, for use in both disclosures and accounting impairment tests. Prices will no longer be based on a single-day, period-end price. Rather, they will be based on either the preceding 12-months’ average price based on closing prices on the first day of each month, or prices defined by existing contractual arrangements.

·	Disclosure of probable and possible reserves is allowed.

·	The estimation of reserves will allow the use of reliable technology that was not previously recognized by the SEC.

·	Numerous changes in reserves disclosures mandated by SEC Form 10K.

·	Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

The change in prices used to calculate reserves did not have a material impact upon our reserves estimation in the current period. These changes could have a material impact upon our financial statements in future periods due to the uncertainty of oil and gas prices.

(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, 2009, for additional information related to these share-based compensation plans.

We follow guidance contained in FASB ASC 718 to account for share-based compensation.

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. 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. In accordance with guidance contained in FASB ASC 718, we are required to report excess tax benefits from the award of equity instruments as financing cash flows. For the six months ended June 30, 2010, we did not recognize any excess tax benefit or shortfall. For the six months ended June 30, 2009, we recognized a tax benefit shortfall of $1.8 million as restricted stock vested at a lower value than the value used to record compensation expense at the date of grant, offset by a reduction to additional paid-in capital.

Net cash proceeds from the exercise of stock options were $0.8 million and $0.1 million for the six months ended June 30, 2010 and 2009. The actual income tax benefit from stock option exercises was $0.2 million for the six months ended June 30, 2010 and less than $0.1 million for the six months ended June 30, 2009.

Stock compensation expense for both stock options and restricted stock issued to both employees and non-employees, which were recorded in “General and administrative, net” in the accompanying condensed consolidated statements of income, were $2.3 million and $2.4 million for the quarters ended June 30, 2010 and 2009, respectively, and were $4.4 million and $4.1 million for the six month periods ended June 30, 2010 and 2009. Stock compensation recorded in lease operating cost was $0.1 million for the quarters ended June 30, 2010 and 2009, and was $0.2 million for the six month periods ended June 30, 2010 and 2009. We also capitalized $0.4 million and $0.7 million of stock compensation in the second quarters of 2010 and 2009, respectively, and capitalized $0.8 million and $1.1 million of stock compensation in the six month periods ended June 30, 2010 and 2009, 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 service period of the award.

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 options issued during the indicated periods:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010			2009		2010			2009

Dividend yield		0	%		N/A		0	%		0	%
Expected volatility		68.4	%		N/A		63.0	%		50.5	%
Risk-free interest rate		0.6	%		N/A		2.1	%		1.8	%
Expected life of options (in years)		2.0			N/A		4.3			4.5
Weighted-average grant-date fair value	$	11.12			N/A	$	12.60		$	6.32

The expected term for grants issued is based on an analysis of historical employee exercise behavior and considered all relevant factors including expected future employee exercise behavior. We have analyzed historical volatility, and based on an analysis of all relevant factors, we have used a 5.5 year look-back period to estimate expected volatility of our 2010 and 2009 stock option grants.

At June 30, 2010, we had $3.3 million of unrecognized compensation cost related to stock options, which are expected to be recognized over a weighted-average period of 1.4 years. The following table represents stock option activity for the six months ended June 30, 2010:

	Shares			Wtd. Avg. Exer. Price

Options outstanding, beginning of period		1,289,194		$	29.72
Options granted		267,378		$	24.94
Options canceled		(16,592	)	$	43.82
Options exercised		(80,176	)	$	18.25
Options outstanding, end of period		1,459,804		$	29.18
Options exercisable, end of period		853,357		$	30.98

The aggregate intrinsic value and weighted average remaining contract life of options outstanding and exercisable at June 30, 2010 was $6.9 million and 5.9 years and $4.0 million and 4.1 years, respectively. Total intrinsic value of options exercised during the six months ended June 30, 2010 was $1.0 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, 2009, 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 three years).

The compensation expense for these awards was determined based on the closing 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, 2010, we had unrecognized compensation expense of $10.3 million related to restricted stock awards which are expected to be recognized over a weighted-average period of 1.9 years. The grant date fair value of shares vested during the six months ended June 30, 2010 was $8.4 million.

The following table represents restricted stock activity for the six months ended June 30, 2010:

	Shares			Wtd. Avg. Grant Price

Restricted shares outstanding, beginning of period		703,856		$	24.15
Restricted shares granted		368,950		$	25.07
Restricted shares canceled		(29,695	)	$	24.67
Restricted shares vested		(303,874	)	$	27.61
Restricted shares outstanding, end of period		739,237		$	22.66

(4) Earnings Per Share

The Company computes earnings per share in accordance with FASB ASC 260-10. Under the guidance, unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents are participating securities and, therefore, are included in computing earnings per share (EPS) pursuant to the two-class method. The two-class method determines earnings per share for each class of common stock and participating securities according to dividends or dividend equivalents and their respective participation rights in undistributed earnings. Unvested share-based payments that contain non-forfeitable rights to dividends or dividend equivalents are now included in the basic weighted average share calculation under the two-class method. These shares were previously included in the diluted weighted average share calculation under the treasury stock method.

Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. As we recognized a net loss for the first six months of 2009, the unvested share-based payments and stock options were not recognized in diluted earnings per share (“Diluted EPS”) calculations as they would be antidilutive. Diluted EPS for the quarter ended June 30, 2010 assumes, as of the beginning of the period, exercise of stock options using the treasury stock method. Certain of our stock options that would potentially dilute Basic EPS in the future were also antidilutive for the three and six month periods ended June 30, 2010, 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 three and six month periods ended June 30, 2010 and 2009 (in thousands, except per share amounts):

	Three Months Ended June 30, 2010							Three Months Ended June 30, 2009
	Income from continuing operations			Shares		Per Share Amount		Income from continuing operations			Shares		Per Share Amount
Basic EPS:
Income (Loss) from continuing operations, and Share Amounts	$	12,513			37,845			$	(2,210	)		31,175
Less: Income (Loss) from continuing operations allocated to unvested shareholders		(242	)		---				---			---
Income (Loss) from continuing operations allocated to common shares	$	12,271			37,845	$	0.32	$	(2,210	)		31,175	$	(0.07	)
Dilutive Securities:
Plus: Income (Loss) from continuing operations allocated to unvested shareholders		242			---				---			---
Less: Income (Loss) from continuing operations re-allocated to unvested shareholders		(241	)		---				---			---
Stock Options		---			258				---			---
Diluted EPS:
Income (Loss) from continuing operations allocated to common shares, and assumed share conversions	$	12,272			38,103	$	0.32	$	(2,210	)		31,175	$	(0.07	)

	Six Months Ended June 30, 2010							Six Months Ended June 30, 2009
	Income from continuing operations			Shares		Per Share Amount		Income from continuing operations			Shares		Per Share Amount
Basic EPS:
Income (Loss) from continuing operations, and Share Amounts	$	26,753			37,749			$	(61,213	)		31,103
Less: Income (Loss) from continuing operations allocated to unvested shareholders		(512	)		---				---			---
Income (Loss) from continuing operations allocated to common shares	$	26,241			37,749	$	0.70	$	(61,213	)		31,103	$	(1.97	)
Dilutive Securities:
Plus: Income (Loss) from continuing operations allocated to unvested shareholders		512			---				---			---
Less: Income (Loss) from continuing operations re-allocated to unvested shareholders		(509	)		---				---			---
Stock Options		---			230				---			---
Diluted EPS:
Income (Loss) from continuing operations allocated to common shares, and assumed share conversions	$	26,244			37,979	$	0.69	$	(61,213	)		31,103	$	(1.97	)

Options to purchase approximately 1.5 million shares at an average exercise price of $29.18 were outstanding at June 30, 2010, while options to purchase approximately 1.3 million shares at an average exercise price of $29.27 were outstanding at June 30, 2009. Approximately 1.2 million stock options to purchase shares were not included in the computation of Diluted EPS for the three and six months ended June 30, 2010, respectively, because these stock options were antidilutive, in that the sum of the stock option price, unrecognized compensation expense and excess tax benefits recognized as proceeds in the treasury stock method was greater than the average closing market price for the common shares during those periods. All of the 1.3 million stock options to purchase shares outstanding for the three and six months ended June 30, 2009, were not included in the computation Diluted EPS as they would be antidilutive given the net loss from continuing operations.

(5) Long-Term Debt

Our long-term debt as of June 30, 2010 and December 31, 2009, was as follows (in thousands):

	June 30,		December 31,
	2010		2009
Bank Borrowings	$	---	$	---
7-1/8% senior notes due 2017		250,000		250,000
8-7/8% senior notes due 2020		221,508		221,397
Long-Term Debt	$	471,508	$	471,397

The maturities on our long-term debt are $250.0 million in 2017 and $225.0 million in 2020.

We have capitalized interest on our unproved properties in the amount of $1.9 million and $1.5 million for the three months ended June 30, 2010 and 2009, respectively, and $3.7 million and $3.0 million for the six month periods ended June 30, 2010 and 2009, respectively.

Bank Borrowings. At June 30, 2010 and December 31, 2009 we had no borrowings under our $500.0 million credit facility with a syndicate of ten banks that has a borrowing base of $277.5 million, and expires in October 2011. In November 2009, the borrowing base and commitment amount were re-set at $277.5 million, a reduction from previous levels due to the issuance of our Senior Notes due 2020, and this amount was re-affirmed in May 2010. Effective November 1, 2009, the interest rate is either (a) the lead bank’s prime rate plus applicable margin or (b) the adjusted London Interbank Offered Rate (“LIBOR”) plus the applicable margin depending on the level of outstanding debt. The applicable margins have increased to escalating rates of 100 to 250 basis points above the lead bank’s prime rate and escalating rates of 200 to 350 basis points for LIBOR rate loans. The commitment fee associated with the unfunded portion of the borrowing base is set at 50 basis points. At June 30, 2010, the lead bank’s prime rate was 3.25%.

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. Since inception, no cash dividends have been declared on our common stock. We are currently in compliance with the provisions of this agreement. The credit facility is secured by our domestic oil and natural gas properties. Under the terms of the credit facility, we can increase the 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 2010.

Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $0.4 million and $1.8 million for the three months ended June 30, 2010 and 2009, respectively, and $0.9 million and $3.2 million for the six months ended June 30, 2010 and 2009, respectively. The amount of commitment fees included in interest expense, net was $0.3 million and $0.1 million for each of the three month periods ended June 30, 2010 and 2009, respectively, and $0.7 million and $0.2 million for each of the six month periods ended June 30, 2010 and 2009.

Senior Notes Due 2020. These notes consist of $225 million of 8-7/8% senior notes issued at 98.389% of par, which equates to an effective yield to maturity of 9-1/8%. The notes were issued on November 25, 2009 with a discount of $3.6 million and will mature on January 15, 2020. The discount of $3.6 million is recorded in “Long-Term Debt” on our balance sheet and will be amortized over the life of the note. 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 January 15 and July 15 and commenced on November 25, 2009. On or after January 15, 2015, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 104.438% of principal, declining in twelve-month intervals to 100% in 2018 and thereafter. In addition, prior to January 15, 2013, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 108.875% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $5.0 million of debt issuance costs related to these notes, which is included in “Other assets – Deferred Charges” on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. 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 8-7/8% senior notes due 2020, including amortization of debt issuance costs and debt discount, totaled $5.1 million and $10.3 million for the three and six months ended June 30, 2010 and 2009, 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 commenced on December 1, 2007. On or after June 1, 2012, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.563% of principal, declining in twelve-month intervals to 100% in 2015 and thereafter. We incurred approximately $4.2 million of debt issuance costs related to these notes, which is included in “Debt issuance costs” on the accompanying consolidated balance sheets and will be amortized to interest expense, net over the life of the notes using the effective interest method. 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 $4.5 million for each of the three month periods ended June 30, 2010 and 2009, respectively, and $9.1 million for each of the six month periods ended June 30, 2010 and 2009, respectively.

Senior Notes Due 2011. These notes consisted of $150.0 million of 7-5/8% senior subordinated notes due July 2011, which were issued on June 23, 2004. Interest on these notes was payable semiannually on January 15 and July 15. As of December 10, 2009, we redeemed all $150.0 million of these notes. In the fourth quarter of 2009, we recorded a charge of $4.0 million related to the redemption of these notes. The costs were comprised of approximately $2.9 million of premium paid to redeem the notes, and $1.1 million to write-off unamortized debt issuance costs.

Interest expense on the 7-5/8% senior notes due 2011, including amortization of debt issuance costs totaled $3.0 million and $6.0 million for the three and six months periods ended June 30, 2010 and 2009, respectively.

(6) Discontinued Operations

In December 2007, Swift Energy agreed to sell substantially all of our New Zealand assets. Accordingly, the New Zealand operations have been classified as discontinued operations in the consolidated statements of operations and cash flows and the assets and associated liabilities have been classified as held for sale in the consolidated balance sheets. In June 2008, Swift Energy completed the sale of substantially all of our New Zealand assets for $82.7 million in cash after purchase price adjustments. Proceeds from this asset sale were used to pay down a portion of our credit facility. In August 2008, we completed the sale of our remaining New Zealand permit for $15.0 million; with three $5.0 million payments to be received six months after the sale, 18 months after the sale, and 30 months after the sale. All payments under this sale agreement are secured by unconditional letters of credit, with the first two payments received in February 2009 and February 2010, respectively. Due to ongoing litigation, we have evaluated the situation and determined that certain revenue recognition criteria have not been met at this time for the permit sale, and have deferred the potential gain on this property sale pending final resolution of this litigation.

In accordance with guidance contained in FASB ASC 360-10, the results of operations for the New Zealand operations have been excluded from continuing operations and reported as discontinued operations for the current and prior periods. Furthermore, the assets included as part of this divestiture have been reclassified as held for sale in the consolidated balance sheets.

The book value of our remaining New Zealand permit is approximately $0.6 million at June 30, 2010.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009

Other revenues	$	13		$	(1	)	$	32		$	20
Total revenues		13			(1	)		32			20

Other operating expenses	$	67		$	127		$	121		$	203
Total expenses		67			127			121			203

Loss from discontinued operations before income taxes	$	(54	)	$	(128	)	$	(89	)	$	(183	)
Income tax expense (benefit)		---			(71	)		---			---
Loss from discontinued operations, net of taxes		(54	)		(57	)		(89	)		(183	)

Loss per common share from discontinued operations-diluted	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.01	)
Cash flow provided by (used in) operating activities	$	(42	)	$	(93	)	$	4		$	(337	)

(7) Acquisitions and Dispositions

In August 2009, within our Central Louisiana/East Texas core area, we entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Burr Ferry field in Vernon Parish, LA. The Company, as fee mineral owner, leased a 50% working interest in approximately 33,623 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage as well as its fee mineral royalty rights, and received approximately $4.2 million related to this transaction. We used the proceeds from this joint venture to pay down a portion of the outstanding balance on our credit facility.

In November 2009, within our South Texas core area, we entered into a joint venture agreement with a large independent oil and gas producer active in the area for development and exploitation in and around the Eagle Ford Shale in McMullen County, TX. The Company, leased a 50% working interest in approximately 26,000 gross acres to the joint venture partner. Swift Energy retains a 50% working interest in the joint venture acreage and received approximately $26 million in cash consideration as well as consideration for approximately $13 million to fund future capital expenditures in the joint venture agreement, related to this transaction. As of June 30, 2010 we had approximately $2.6 million of the $13 million consideration remaining in our balance sheet. We used the proceeds from this joint venture to pay down a portion of the outstanding balance on our credit facility.

(8) Fair Value Measurements

FASB ASC 820-10 defines fair value, establishes guidelines for measuring fair value and expands disclosure about fair value measurements. It does not create or modify any current GAAP requirements to apply fair value accounting. However, it provides a single definition for fair value that is to be applied consistently for all prior accounting pronouncements. The adoption of this guidance did not have a material impact on our financial position or results of operations.

The following tables present our assets that are measured at fair value on a recurring basis during the three and six months ended June 30, 2010 and are categorized using the fair value hierarchy. The fair value of our oil and natural gas derivatives are computed using the Black-Scholes-Merton option pricing model and are periodically verified against quotes from brokers. The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):

	Fair Value Measurements at June 30, 2010
Assets	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Money Market Funds	$	40.9	$	40.9	$	---	$	---
Oil and Natural Gas Derivatives	$	0.5	$	---	$	0.5	$	---

Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category include money market funds as they have comparable fair values for identical assets.

Level 2 – Uses quoted prices for similar assets or liabilities in active markets or observable inputs for assets or liabilities in non-active markets. Instruments in this category include our commodity derivatives that we value using commonly accepted industry-standard models (such as Black-Scholes) and contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data, which are obtained from independent third-party sources.

Level 3 – Uses unobservable inputs for assets or liabilities that are in non-active markets. We do not have any assets or liabilities in this category that are not supported by market activity and have significant unobservable inputs.

Our derivative contracts are held with major financial institutions, all of which maintain investment grade credit ratings. Each of these financial institutions is a member of the bank syndicate for Swift Energy’s credit facility. We evaluate our credit risk each quarter and are exposed to credit risk to the extent of nonperformance by the counterparties in the derivative contracts discussed above. We believe the credit risk is minimal and do not anticipate nonperformance due the investment grade ratings of the financial institutions and short-term nature of our derivative contracts (all of our contracts covering periods of less than one-year).

(9) Condensed Consolidating Financial Information

Swift Energy Company is the issuer and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of Swift Energy Company) is a guarantor of our senior subordinated notes due 2017 and 2020. The guarantees on our senior subordinated notes due 2017 and 2020 are full and unconditional and joint and several. The following is condensed consolidating financial information for Swift Energy Company, Swift Energy Operating, LLC, and other subsidiaries:

Condensed Consolidating Balance Sheets

(in thousands)	June 30, 2010
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)		Other Subsidiaries		Eliminations			Swift Energy Company Consolidated

ASSETS
Current assets	$	---	$	101,421	$	5,631	$	---		$	107,052
Property and equipment		---		1,397,083		---		---			1,397,083
Investment in subsidiaries (equity method)		713,051		---		636,722		(1,349,773	)		---
Other assets		---		9,710		80,731		(80,731	)		9,710
Total assets	$	713,051	$	1,508,214	$	723,084	$	(1,430,504	)	$	1,513,845

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	116,708	$	10,033	$	---		$	126,741
Long-term liabilities		---		754,784		---		(80,731	)		674,053
Stockholders’ equity		713,051		636,722		713,051		(1,349,773	)		713,051
Total liabilities and stockholders’ equity	$	713,051	$	1,508,214	$	723,084	$	(1,430,504	)	$	1,513,845

(in thousands)	December 31, 2009
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)		Other Subsidiaries		Eliminations			Swift Energy Company Consolidated

ASSETS
Current assets	$	---	$	102,975	$	5,625	$	---		$	108,600
Property and equipment		---		1,315,964		---		---			1,315,964
Investment in subsidiaries (equity method)		678,899		---		602,483		(1,281,382	)		---
Other assets		---		10,201		75,850		(75,850	)		10,201
Total assets	$	678,899	$	1,429,140	$	683,958	$	(1,357,232	)	$	1,434,765

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities	$	---	$	98,545	$	5,059	$	---		$	103,604
Long-term liabilities		---		728,112		---		(75,850	)		652,262
Stockholders’ equity		678,899		602,483		678,899		(1,281,382	)		678,899
Total liabilities and stockholders’ equity	$	678,899	$	1,429,140	$	683,958	$	(1,357,232	)	$	1,434,765

Condensed Consolidating Statements of Income

(in thousands)	Three Months Ended June 30, 2010
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)		Other Subsidiaries			Eliminations			Swift Energy Company Consolidated

Revenues	$	---	$	106,900	$	---		$	---		$	106,900
Expenses		---		87,832		---			---			87,832

Income before the following:		---		19,068		---			---			19,068
Equity in net earnings of subsidiaries		12,459		---		12,513			(24,972	)		---

Income from continuing operations, before income taxes		12,459		19,068		12,513			(24,972	)		19,068
Income tax provision		---		6,555		---			---			6,555

Income from continuing operations		12,459		12,513		12,513			(24,972	)		12,513
Loss from discontinued operations, net of taxes		---		---		(54	)		---			(54	)

Net income	$	12,459	$	12,513	$	12,459		$	(24,972	)	$	12,459

(in thousands)	Six Months Ended June 30, 2010
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)		Other Subsidiaries			Eliminations			Swift Energy Company Consolidated

Revenues	$	---	$	216,746	$	---		$	---		$	216,746
Expenses		---		174,857		---			---			174,857

Income before the following:		---		41,889		---			---			41,889
Equity in net earnings of subsidiaries		26,664		---		26,753			(53,417	)		---

Income from continuing operations, before income taxes		26,664		41,889		26,753			(53,417	)		41,889
Income tax provision		---		15,136		---			---			15,136

Income from continuing operations		26,664		26,753		26,753			(53,417	)		26,753
Loss from discontinued operations, net of taxes		---		---		(89	)		---			(89	)

Net income	$	26,664	$	26,753	$	26,664		$	(53,417	)	$	26,664

(in thousands)	Three Months Ended June 30, 2009
	Swift Energy Company (Issuer)			Swift Energy Operating, LLC (Guarantor)			Other Subsidiaries			Eliminations		Swift Energy Company Consolidated

Revenues	$	---		$	82,921		$	---		$	---	$	82,921
Expenses		---			85,202			---			---		85,202

Loss before the following:		---			(2,281	)		---			---		(2,281	)
Equity in net earnings of subsidiaries		(2,267	)		---			(2,210	)		4,477		---

Loss from continuing operations, before income taxes		(2,267	)		(2,281	)		(2,210	)		4,477		(2,281	)
Income tax benefit		---			(71	)		---			---		(71	)

Loss from continuing operations		(2,267	)		(2,210	)		(2,210	)		4,477		(2,210	)
Loss from discontinued operations, net of taxes		---			---			(57	)		---		(57	)

Net Loss	$	(2,267	)	$	(2,210	)	$	(2,267	)	$	4,477	$	(2,267	)

(in thousands)	Six Months Ended June 30, 2009
	Swift Energy Company (Issuer)			Swift Energy Operating, LLC (Guarantor)			Other Subsidiaries			Eliminations		Swift Energy Company Consolidated

Revenues	$	---		$	159,280		$	---		$	---	$	159,280
Expenses		---			253,530			---			---		253,530

Loss before the following:		---			(94,250	)		---			---		(94,250	)
Equity in net earnings of subsidiaries		(61,396	)		---			(61,213	)		122,609		---

Loss from continuing operations, before income taxes		(61,396	)		(94,250	)		(61,213	)		122,609		(94,250	)
Income tax benefit		---			(33,037	)		---			---		(33,037	)

Loss from continuing operations		(61,396	)		(61,213	)		(61,213	)		122,609		(61,213	)
Loss from discontinued operations, net of taxes		---			---			(183	)		---		(183	)

Net Loss	$	(61,396	)	$	(61,213	)	$	(61,396	)	$	122,609	$	(61,396	)

Condensed Consolidating Statements of Cash Flow

(in thousands)	Six Months Ended June 30, 2010
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)			Other Subsidiaries			Eliminations			Swift Energy Company Consolidated
Cash flow from operations	$	---	$	129,018		$	4		$	---		$	129,022
Cash flow from investing activities		---		(124,019	)		5,000			(5,000	)		(124,019	)
Cash flow from financing activities		---		12			(5,000	)		5,000			12

Net increase (decrease) in cash		---		5,011			4			---			5,015
Cash, beginning of period		---		33,405			5,064			---			38,469

Cash, end of period	$	---	$	38,416		$	5,068		$	---		$	43,484

(in thousands)	Six Months Ended June 30, 2009
	Swift Energy Company (Issuer)		Swift Energy Operating, LLC (Guarantor)			Other Subsidiaries			Eliminations			Swift Energy Company Consolidated
Cash flow from operations	$	---	$	83,573		$	(337	)	$	---		$	83,236
Cash flow from investing activities		---		(131,007	)		5,000			(4,742	)		(130,749	)
Cash flow from financing activities		---		47,461			(4,742	)		4,742			47,461

Net increase (decrease) in cash		---		27			(79	)		---			(52	)
Cash, beginning of period		---		87			196			---			283

Cash, end of period	$	---	$	114		$	117		$	---		$	231

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, 2009. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 32 of this report.

Overview

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

We are one of the largest producers of crude oil in the state of Louisiana, due to our South Louisiana operations. Oil production accounted for 48% of our second quarter of 2010 production, and combined oil and natural gas liquids production (“NGLs”) made up 62% of our second quarter of 2010 production. This emphasis has allowed us to benefit from better margins for oil production than natural gas production thus far in 2010.

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

2010 Oil and Natural Gas Pricing

Significantly increased prices for oil and NGLs in 2010 have had a positive impact on our cash flow, earnings, and liquidity when compared to the same period in 2009. Oil and NGL prices we received for the first half of 2010 were 62% and 71% higher, respectively, than the average prices we received in first half of 2009, while natural gas prices increased 16% in that same period. Prices in the second quarter of 2010 declined when compared to prices in the first quarter of 2010; as oil prices declined less than 1% and NGL prices decreased 6% while natural gas prices decreased 22%.

Financial Condition

We raised $108.8 million through an underwritten public stock offering in August 2009. We issued 6.21 million shares of our common stock at a price of $18.50 per share. The gross proceeds from these sales were approximately $114.9 million, before deducting underwriting commissions and issuance costs totaling $6.1 million.

In November 2009, we issued $225.0 million of 8-7/8% senior notes due 2020 at 98.389% of par, which equates to an effective yield to maturity of 9-1/8%.

In December 2009, we redeemed all $150.0 million of our 7-5/8% senior notes due 2011 and recorded a charge of $4.0 million related to the redemption of these notes, which is recorded in “Debt retirement costs” on the accompanying consolidated statement of operations. The costs were comprised of approximately $2.9 million of premium paid to redeem the notes, and $1.1 million to write-off unamortized debt issuance costs.

We used the proceeds from this stock sale and note offering, less costs to redeem our senior notes due 2011, to pay down the outstanding balance on our credit facility. At December 31, 2009 and June 30, 2010, we had no amounts drawn under our credit facility.

Our net debt to capitalization ratio was essentially unchanged from year-end 2009, and was 38% at June 30, 2010, as compared to 39% at year-end 2009.

Operating Results – Prior Year Comparison

In the second quarter of 2010 we had revenues of $106.9 million, an increase of 29% compared to revenues in the same quarter in 2009. Our weighted average price received increased 41% to $51.80 per Boe received for the second quarter of 2010 from $36.71 per Boe in the 2009 period. This approximately $24.0 million increase in revenues from 2009 levels resulted mainly from higher oil and NGL prices during the second quarter of 2010, offset partially by a 10% decrease in production mainly due to natural declines in our Southeast Louisiana core area.

Our overall costs and expenses increased in the second quarter of 2010 by $2.6 million when compared to costs incurred in the same period in 2009. Lease operating costs increased by 6%, or $1.1 million, due to higher lease supervision costs and higher salt water disposal costs. Severance and other taxes increased 17%, or $1.7 million, mainly due to increased oil and gas revenues. Depreciation, depletion and amortization expense decreased 3%, or $1.3 million, mainly due to lower production and higher reserves in the 2010 period when compared to the 2009 period.

Our income from continuing operations for the second quarter of 2010 was $12.5 million, while the 2009 period had a loss from continuing operations of $2.2 million, with the increase due primarily to higher revenue from higher commodity prices.

Operating Activities

In our South Texas core area, eight horizontal wells were drilled in McMullen County: four operated horizontal wells in the Eagle Ford shale, two operated horizontal wells in the Olmos, and two non-operated horizontal wells were drilled by a joint venture partner in the Eagle Ford shale. Two of the operated Eagle Ford wells were completed during the quarter, another was completed early in July, and the fourth is being completed in early August. The two Olmos wells were also completed in the second quarter. The non-operated wells are expected to be completed during the third quarter. We plan to perform 20 additional vertical well re-fracture operations in the second half of 2010.

In total, our Eagle Ford Shale position encompassed 100,312 gross and 80,658 net acres prospective in our South Texas region. A portion of this Eagle Ford acreage is below existing Olmos acreage that we also hold.

We plan to obtain a total of 304 square miles of additional 3D seismic data which includes 79 square miles of existing non-exclusive 3D seismic and 225 square miles of new, non-exclusive 3D seismic. To date we have taken delivery of about 160 square miles and plan to receive the remainder of the data before the end of 2010. This new data is aimed at imaging our leases in and around the AWP area.

In our Southeast Louisiana core area, three wells were drilled in the Lake Washington field. Two of these wells were completed during the second quarter and the third well was completed in July. Additionally during the second quarter of 2010, seven wells were re-completed, one gas lift modification and four sliding sleeve changes were performed. We have 3 additional re-completions planned for the remainder of 2010.

We have 4,000 square miles of proprietary merged and prestack depth-migrated (“PSDM”) 3D seismic data over our Southeast Louisiana and South Louisiana core areas. The use of these PSDM data has significantly improved and refined our understanding of the hydrocarbon traps associated with the complex salt bodies, faulting and overpressure that are evident in this province. These data enable us to more accurately plan and position our exploratory and development wells. The improved seismic image in our Southeast Louisiana and South Louisiana core areas described above has delivered additional high value prospects which could be drilled later this year or future periods depending upon the commodity pricing environment.

Capital Expenditures

Our capital expenditures on an accrual basis were $159.2 million in the first half of 2010, which was an increase from $63.7 million spent on an accrual basis in the 2009 period. The increase in the 2010 period was mainly due to additional drilling activity in our South Texas region. These 2010 expenditures were primarily funded by $129.0 million of cash provided by operating activities from continuing operations, the use of $10.0 million in carried interests from our Eagle Ford joint venture operations, and $5.0 million of cash provided from our discontinued operations.

We currently plan to fund our 2010 capital expenditures with our 2010 cash flow, cash on hand, and if needed availability under our credit facility. Our 2010 capital expenditures are currently budgeted at $360 million to $375 million, net of minor non-core dispositions. These expenditures are expected to include: a continuation of the horizontal well drilling program in the Olmos sands in our AWP field, an ongoing horizontal well program in the Eagle Ford shale formation in the AWP and other South Texas areas, continuing our drilling activity in our Southeast Louisiana area by targeting shallow and intermediate depth oil prospects, drilling several wells in our Central Louisiana/East Texas area, continuing the recompletion program in our Southeast Louisiana core area and the fracture enhancement program in our South Texas core area.

Results of Continuing Operations — Three Months Ended June 30, 2010 and 2009

Revenues. Our revenues in the second quarter of 2010 increased by 29% compared to revenues in the same period in 2009, primarily due to higher commodity prices, partially offset by lower production volumes. Revenues for both periods were substantially comprised of oil and gas sales. Crude oil production was 48% of our production volumes in the second quarter of 2010 and 46% of our production in the second quarter of 2009. Natural gas production was 38% of our production volumes in the second quarter of 2010 and 41% in the second quarter of 2009.

Our properties are divided into core areas. The Southeast Louisiana core area includes the Lake Washington and Bay de Chene fields. The Central Louisiana/East Texas core area includes the Brookeland, Masters Creek and South Bearhead Creek fields. The South Louisiana core area includes the Cote Blanche Island, Horseshoe Bayou/Bayou Sale, Jeanerette, High Island, and Bayou Penchant fields. The South Texas core area includes the AWP, Briscoe Ranch, Las Tiendas, and Sun TSH fields. The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the three months ended June 30, 2010 and 2009:

Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MBoe)
	2010		2009		2010		2009
S. E. Louisiana	$	61.8	$	50.8		944		1,185
South Texas		25.8		17.2		732		669
Central Louisiana / E. Texas		9.6		9.6		175		233
South Louisiana		7.7		5.0		171		161
Other		0.2		0.2		6		7
Total	$	105.1	$	82.8		2,028		2,255

Oil and gas sales for the second quarter of 2010 increased by 27%, or $22.3 million, from the level of those revenues for the comparable 2009 period, and our net production volumes in the second quarter of 2010 decreased by 10%, or 0.2 MMBoe, compared to net production volumes in the second quarter of 2009. Average prices for oil increased to $77.83 per Bbl in the second quarter of 2010 from $55.42 per Bbl in the second quarter of 2009. Average natural gas prices increased to $3.72 per Mcf in the second quarter of 2010 from $3.11 per Mcf in the second quarter of 2009. Average NGL prices increased to $41.92 per Bbl in the second quarter of 2010 from $28.26 per Bbl in the second quarter of 2009.

In the second quarter of 2010, our $22.3 million increase in oil, NGL, and natural gas sales resulted from:

Price variances that had a $28.5 million favorable impact on sales, of which $21.9 million was attributable to the 40% increase in average oil prices received, $3.8 million was attributable to the 48% increase in NGL prices, and $2.8 million was attributable to the 19% increase in natural gas prices; and

Volume variances that had a $6.2 million unfavorable impact on sales, with a $2.6 million decrease attributable to the less than 0.1 million Bbl decrease in oil production volumes, a $0.8 million decrease due to the less than 0.1 million Bbl decrease in NGL production volumes and a $2.8 million decrease due to the 0.9 Bcf decrease in natural gas production volumes. The declines in production volumes were mainly due to natural declines in our Southeast Louisiana core area.

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

	Production Volume								Average Price
	Oil (MBbl)		NGL (MBbl)		Gas (Bcf)		Combined (MBoe)		Oil (Bbl)		NGL (Bbl)		Natural gas (Mcf)
	Oil (MBbl)		NGL (MBbl)		Gas (Bcf)		Combined (MBoe)		Oil (Bbl)		NGL (Bbl)		Natural gas (Mcf)

Three Months Ended June 30, 2010		979		279		4.6		2,028	$	77.83	$	41.92	$	3.72
Three Months Ended June 30, 2009		1,026		308		5.5		2,255	$	55.42	$	28.26	$	3.11

During the second quarter of 2010, we recorded a net gain of $1.5 million related to our derivative activities. During the second quarter of 2009 we recorded a net loss of less than $0.1 million. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of operations. Had these gains (losses) been recognized in the oil and gas sales account, our average oil price would have been $78.10 and $55.41 for the second quarters of 2010 and 2009, respectively, and our average natural gas price would have been $3.99 and $3.11 for the second quarters of 2010 and 2009, respectively.

Costs and Expenses. Our expenses in the second quarter of 2010 increased $2.6 million, or 3%, compared to expenses in the same period of 2009, principally due to cost reduction initiatives.

Our second quarter 2010 general and administrative expenses, net, increased $0.5 million, or 6%, from the level of such expenses in the same 2009 period mainly due to higher office rent. For the second quarters of 2010 and 2009, our capitalized general and administrative costs totaled $5.9 million and $5.7 million, respectively. Our net general and administrative expenses per Boe produced increased to $3.96 per Boe in the second quarter of 2010 from $3.36 per Boe in the second quarter of 2009. The portion of supervision fees recorded as a reduction to general and administrative expenses was $3.0 million and $2.8 million for three month periods ended June 30, 2010 and 2009, respectively.

DD&A decreased $1.3 million, or 3%, in the second quarter of 2010, from levels in the second quarter of 2009. The decrease was primarily due to lower production and higher reserves volumes, partially offset by higher future development costs. Our DD&A rate per Boe of production was $19.24 and $17.90 in the second quarters of 2010 and 2009, respectively.

We recorded $1.0 million and $0.7 million in accretion of our asset retirement obligation in the second quarters of 2010 and 2009, respectively.

Our lease operating costs increased $1.1 million, or 6%, compared to the level of such expenses in the same 2009 period. Lease operating costs increased as a result of higher supervision and salt water disposal costs. Our lease operating costs per Boe produced were $9.83 and $8.34 in the second quarters of 2010 and 2009, respectively.

Severance and other taxes increased $1.7 million, or 17%, from levels in the second quarter of 2009. The increase in the 2010 period was due primarily to higher revenue as a result of higher commodity prices. Severance and other taxes as a percentage of oil and gas sales were approximately 11.1% and 12.0% in the second quarters of 2010 and 2009, respectively, with the decrease due to reductions in ad valorem taxes in the 2010 period.

Our total interest cost in the second quarter of 2010 was $10.1 million, of which $1.9 million was capitalized. Our total interest cost in the second quarter of 2009 was $9.3 million, of which $1.5 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase in interest expense during the second quarter of 2010 was primarily due to interest on our new $225 million senior note which is at a higher interest rate than the debt that was retired in the fourth quarter of 2009.

Our overall effective tax rate was 34.4% and 3.1% for the second quarters of 2010 and 2009, respectively. The second quarter 2009 rate included a year-to-date cumulative effective rate decrease coupled with significantly lower income before taxes when compared to other periods.

Income (Loss) from Continuing Operations. Our income from continuing operations for the second quarter of 2010 of $12.5 million was higher than the second quarter 2009 loss from continuing operations of $2.2 million primarily due to higher revenue as a result of higher commodity prices.

Net Income (Loss). We had net income in the second quarter of 2010 of $12.5 million, due to higher revenue as a result of higher commodity prices, and had a net loss in the second quarter of 2009 of $2.3 million.

Results of Continuing Operations — Six Months Ended June 30, 2010 and 2009

Revenues. Our revenues in the first six months of 2010 increased by 36% compared to revenues in the same period in 2009, primarily due to higher commodity prices, partially offset by lower production volumes. Revenues for both periods were substantially comprised of oil and gas sales. Crude oil production was 47% of our production volumes in the first six months of 2010 and 46% of our production in the first six months of 2009. Natural gas production was 38% of our production volumes in the first six months of 2010 and 41% in the first six months of 2009.

The following table provides information regarding the changes in the sources of our oil and gas sales and volumes for the six months ended June 30, 2010 and 2009:

Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MBoe)
	2010		2009		2010		2009
S. E. Louisiana	$	123.2	$	93.5		1,880		2,360
South Texas		57.3		37.5		1,522		1,424
Central Louisiana / E. Texas		18.8		16.8		336		459
South Louisiana		15.4		11.1		323		363
Other		0.4		0.3		12		16
Total	$	215.1	$	159.2		4,073		4,622

Oil and gas sales for the first six months of 2010 increased by 35%, or $55.9 million, from the level of those revenues for the comparable 2009 period, and our net production volumes in the first six months of 2010 decreased by 12%, or 0.5 MMBoe, compared to net production volumes in the first six months of 2009. Average prices for oil increased to $77.96 per Bbl in the first six months of 2010 from $48.01 per Bbl in the first six months of 2009. Average natural gas prices increased to $4.24 per Mcf in the first six months of 2010 from $3.66 per Mcf in the first six months of 2009. Average NGL prices increased to $43.37 per Bbl in the first six months of 2010 from $25.40 per Bbl in the first six months of 2009.

In the first six months of 2010, our $55.9 million increase in oil, NGL, and natural gas sales resulted from:

Price variances that had a $73.5 million favorable impact on sales, of which $57.6 million was attributable to the 62% increase in average oil prices received, $10.5 million was attributable to the 71% increase in NGL prices, and $5.4 million was attributable to the 16% increase in natural gas prices; and

Volume variances that had a $17.6 million unfavorable impact on sales, with a $10.1 million decrease attributable to the 0.2 million Bbl decrease in oil production volumes, a $0.8 million decrease due to the less than 0.1 million Bbl decrease in NGL production volumes and a $6.7 million decrease due to the 1.8 Bcf decrease in natural gas production volumes. The declines in production volumes were mainly due to natural declines in our Southeast Louisiana core area.

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

	Production Volume								Average Price
	Oil (MBbl)		NGL (MBbl)		Gas (Bcf)		Combined (MBoe)		Oil (Bbl)		NGL (Bbl)		Natural gas (Mcf)
	Oil (MBbl)		NGL (MBbl)		Gas (Bcf)		Combined (MBoe)		Oil (Bbl)		NGL (Bbl)		Natural gas (Mcf)

Six Months Ended June 30, 2010		1,924		582		9.4		4,073	$	77.96	$	43.37	$	4.24
Six Months Ended June 30, 2009		2,135		615		11.2		4,622	$	48.01	$	25.40	$	3.66

During the first six months of 2010, we recorded a net gain of $1.0 million related to our derivative activities. During the first six months of 2009 we recorded a net loss of less than $0.1 million. This activity is recorded in “Price-risk management and other, net” on the accompanying statements of operations. Had this gain been recognized in the oil and gas sales account, our average oil price would have been $78.09 for the first six months of 2010, and our average natural gas price would have been $4.32 for the first six months of 2010. Prices were not impacted by our derivative hedging positions for the first six months of 2009 since we did not have material derivative gains or losses.

Costs and Expenses. Our expenses in the first six months of 2010 decreased $78.7 million, or 31%, compared to expenses in the same period of 2009, principally due to a 2009 non-cash write-down on a before-tax basis of $79.3 million ($50.0 million after tax) on our oil and gas properties as a result of lower oil and natural gas prices at June 30, 2009.

Our first six months 2010 general and administrative expenses, net, increased $1.3 million, or 8%, from the level of such expenses in the same 2009 primarily due to higher office rent. For the first six months of 2010 and 2009, our capitalized general and administrative costs totaled $11.9 million and $12.1 million, respectively. Our net general and administrative expenses per Boe produced increased to $4.24 per Boe in the first six months of 2010 from $3.46 per Boe in the first six months of 2009. The portion of supervision fees recorded as a reduction to general and administrative expenses was $6.0 million and $5.7 million for three month periods ended June 30, 2010 and 2009, respectively.

DD&A decreased $7.0 million, or 8%, in the first six months of 2010, from levels in the first six months of 2009. The decrease was primarily due to lower production and higher reserves volumes. Our DD&A rate per Boe of production was $18.98 and $18.24 in the first six months of 2010 and 2009, respectively.

We recorded $1.9 million and $1.4 million in accretion of our asset retirement obligation in the first six months of 2010 and 2009, respectively.

Our lease operating costs decreased less than $0.1 million, or less than 1%, compared to the level of such expenses in the same 2009 period. Lease operating costs decreased as a result of targeted cost reduction initiatives. Our lease operating costs per Boe produced were $9.47 and $8.36 in the first six months of 2010 and 2009, respectively.

Severance and other taxes increased $4.6 million, or 25%, from levels in the first six months of 2009. The increase in the 2010 period was due primarily to higher revenue as a result of higher commodity prices. Severance and other taxes as a percentage of oil and gas sales were approximately 10.8% and 11.7% in the first six months of 2010 and 2009, respectively, with the decrease due to reductions in ad valorem taxes in the 2010 period.

Our total interest cost in the first six months of 2010 was $20.2 million, of which $3.7 million was capitalized. Our total interest cost in the first six months of 2009 was $18.3 million, of which $3.0 million was capitalized. We capitalize a portion of interest related to unproved properties. The increase in interest expense during the first six months of 2010 was primarily due to interest on our new $225 million senior note which is at a higher interest rate than the debt that was retired in the fourth quarter of 2009.

Our overall effective tax rate was 36.1% and 35.1% for the first six months of 2010 and 2009, respectively. The effective tax rate for the first six months of 2010 and 2009 were higher than the U.S. federal statutory rate of 35% primarily because of state income taxes.

Income(Loss) from Continuing Operations. Our income from continuing operations for the first six months of 2010 of $26.8 million was higher than the first six months 2009 loss from continuing operations of $61.2 million primarily due to the non-cash write-down of oil and gas properties in the first six months of 2009.

Net Income (Loss). We had net income in the first six months of 2010 of $26.7 million and had a net loss of $61.4 million in the first six months of 2009.

Discontinued Operations

	Three Months Ended June 30,						Six Months Ended June 30,
	2010			2009			2010			2009

Other revenues	$	13		$	(1	)	$	32		$	20
Total revenues		13			(1	)		32			20

Other operating expenses	$	67		$	127		$	121		$	203
Total expenses		67			127			121			203

Loss from discontinued operations before income taxes	$	(54	)	$	(128	)	$	(89	)	$	(183	)
Income tax expense (benefit)		---			(71	)		---			---
Loss from discontinued operations, net of taxes		(54	)		(57	)		(89	)		(183	)

Loss per common share from discontinued operations-diluted	$	(0.00	)	$	(0.00	)	$	(0.00	)	$	(0.01	)
Cash flow provided by (used in) operating activities	$	(42	)	$	(93	)	$	4		$	(337	)

Share-Based Compensation

We follow guidance contained in FASB ASC 718 (formerly SFAS No. 123R) to account for share-based compensation. 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 options issued during the indicated periods:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2010			2009		2010			2009

Dividend yield		0	%		N/A		0	%		0	%
Expected volatility		68.4	%		N/A		63.0	%		50.5	%
Risk-free interest rate		0.6	%		N/A		2.1	%		1.8	%
Expected life of options (in years)		2.0			N/A		4.3			4.5
Weighted-average grant-date fair value	$	11.12			N/A	$	12.60		$	6.32

At June 30, 2010, there was $3.3 million of unrecognized compensation cost related to stock options, which are expected to be recognized over a weighted-average period of 1.4 years, and unrecognized compensation expense of $10.3 million related to restricted stock awards which are expected to be recognized over a weighted-average period of 1.9 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.

Contractual Commitments and Obligations

We had no material changes in our contractual commitments and obligations from December 31, 2009 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, 2009.

In July 2010 we executed a strategic and exclusive 24 month multi-stage fracture service contract with a large oil field service company to further develop our South Texas properties.

Commodity Price Trends and Uncertainties

Oil and natural gas prices historically have been volatile and over the last year that volatility has increased to extreme levels, and this volatility is expected to continue for 2010 and possibly future periods. The price of oil declined significantly from 2008 into the first quarter of 2009, however, oil prices made some improvement in the later part of 2009 into the first and second quarters of 2010. Factors such as worldwide economic conditions and credit availability, worldwide supply disruptions, weather conditions, fluctuating currency exchange rates, and political conditions in major oil producing regions, especially the Middle East, can cause fluctuations in the price of oil. Domestic natural gas prices remained high during much of 2008 when compared to longer-term historical prices but began falling in 2008 and continued to fall throughout 2009, showing slight improvement in late 2009 and the first and second quarters of 2010. North American weather conditions, the industrial and consumer demand for natural gas, economic conditions and credit availability, storage levels of natural gas, the level of liquefied natural gas imports, and the availability and accessibility of natural gas deposits in North America can cause significant fluctuations in the price of natural gas.

Operational Risk Management

Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and natural gas, including blowouts, cratering, pipe failure, casing collapse, fires, and adverse weather conditions, each of which could result in severe damage to or destruction of oil and natural gas wells, production facilities or other property, or individual injuries. The oil and natural gas exploration business is also subject to environmental hazards, such as oil spills, natural gas leaks, and ruptures and discharges of toxic substances or gases that could expose us to substantial liability due to pollution and other environmental damage. See “1A. Risk Factors” in our Annual Report on Form 10K filed for the fiscal year ended December 31, 2009 for more details and for discussion of other risks. We maintain comprehensive insurance coverage, including general liability insurance and property damage insurance. We believe that our insurance is adequate and customary for companies of a similar size engaged in comparable operations, but if a significant accident or other event occurs that is uninsured or not fully covered by insurance, it could adversely affect us.

Income Taxes

The tax laws in the jurisdictions we operate in are continuously changing and professional judgments regarding such tax laws can differ. Under guidance contained in FASB ASC 740-10, 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.

We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25, Under this guidance, 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. Our current balance of unrecognized tax benefits is $1.0 million. If recognized, these tax benefits would fully impact our effective tax rate.

Liquidity and Capital Resources

Previous extreme volatility in worldwide credit and financial markets, combined with previous extreme volatility in prices for oil and natural gas, all of which began in 2008, may continue to have a significant impact on our cash flow, capital expenditures, and liquidity in future periods. See “Overview – Financial Condition.”

Net Cash Provided by Operating Activities. For the first six months of 2010, our net cash provided by operating activities from continuing operations was $129.0 million, representing a 54% increase as compared to $83.6 million generated during the 2009 period. The $45.4 million increase in 2010 was primarily due to an increase of $55.9 million in oil and gas sales, attributable to higher oil and natural gas prices, partially offset by lower production.

Accounts Receivable. We assess the collectability of accounts receivable, and, based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At both June 30, 2010 and December 31, 2009, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balances on the accompanying condensed consolidated balance sheets.

Existing Credit Facility. We had no borrowings under our bank credit facility at June 30, 2010, or at December 31, 2009. Our bank credit facility at June 30, 2010 consisted of a $500.0 million credit facility with a syndicate of ten banks, and expires in October 2011. In November 2009, the borrowing base and commitment amount were re-set at $277.5 million, a reduction from previous levels due to the issuance of our senior notes due 2020 and was re-affirmed at this level in May 2010. The next scheduled borrowing base review is November 2010.

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 and expect to remain in compliance with these provisions in 2010 and future periods. Our available borrowings under our line of credit facility provide us liquidity.

In light of credit market volatility, many financial institutions have experienced liquidity issues, and governments have intervened in these markets to create liquidity. We have reviewed the creditworthiness of the banks that fund our credit facility. However, if the current credit market volatility is prolonged, future extensions of our credit facility may contain terms and interest rates not as favorable as those of our current credit facility.

Working Capital. Our working capital decreased from a surplus of $5.0 million at December 31, 2009, to a deficit of $19.7 million at June 30, 2010. The change primarily resulted from an increase in accrued capital costs related to additional drilling activity in South Texas and an increase in accrued interest related to our new Senior Notes due 2020.

Debt Maturities. Our credit facility, which had no balance at June 30, 2010, expires on October 3, 2011. Our $250.0 million of 7-1/8% senior notes mature June 1, 2017, and our $225.0 million of 8-7/8% senior notes mature January 15, 2020

Cash Used in Investing Activities. For the first six months of 2010 our oil and gas property additions were $129.1 million. This amount decreased by $6.7 million as compared to our oil and gas property additions during the first six months of 2009, primarily due to a decrease in our spending on drilling and development in our Southeast Louisiana core area, partially offset by an increase in our spending on drilling and development in our South Texas core area. These 2010 expenditures were funded by $129.0 million of cash provided by operating activities from continuing operations.

We drilled sixteen operated and three non-operated wells during the first six months of 2010. This includes eleven horizontal wells and one vertical well in South Texas. Eight of these wells were completed prior to the end of the second quarter, one was completed in early July, and the remaining three are awaiting completion. In South Louisiana we drilled seven wells, of which three were successfully completed prior to the end of the second quarter, one was completed in July, and three were dry holes.

New Accounting Pronouncements

New Accounting Pronouncements. In January 2010, the FASB issued ASU 2010-03 to amend oil and gas reserve accounting and disclosure guidance that aligns the oil and gas reserve estimation and disclosure requirements of Topic 932 (“Extractive Industries – Oil and Gas”) with the requirements of SEC release 33-8995. These releases are effective for financial statements issued on or after January 1, 2010. We have adopted this guidance for all reporting periods ending on or after December 31, 2009. This release changes the accounting and disclosure requirements surrounding oil and natural gas reserves and is intended to modernize and update the oil and gas disclosure requirements, to align them with current industry practices and to adapt to changes in technology. The most significant changes include:

·	Disclosure of probable and possible reserves is allowed.

·	The estimation of reserves will allow the use of reliable technology that was not previously recognized by the SEC.

·	Numerous changes in reserves disclosures mandated by SEC for Form 10K.

·	Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.

Forward-Looking Statements

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Risk. Our major market risk exposure is the commodity pricing applicable to our oil and natural gas production. Realized commodity prices received for such production are primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas. Significant declines in oil and natural gas prices began in the last half of 2008, and such pricing volatility has continued through 2009 with some improvement during the last half of 2009 and into 2010.

Our price-risk management policy permits the utilization of agreements and financial instruments (such as futures, forward contracts, swaps and options contracts) to mitigate price risk associated with fluctuations in oil and natural gas prices. We do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our credit facility. Below is a description of the financial instruments we have utilized to hedge our exposure to price risk.

• Price Floors – At June 30, 2010, we had natural gas price floors in effect for the contract months of July through August 2010 that cover natural gas production of 1,725,000 MMBtu from July through August 2010 with strike prices ranging between $4.60 and $4.95. We also had oil price floors in effect for the contract month of July 2010 that cover oil production of 45,000 Boe for July 2010 with a strike price of $79.50.

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. Continued volatility in both credit and commodity markets may reduce the liquidity of our customer base. To manage customer credit risk, we monitor credit ratings of customers from certain customers we also obtain letters of credit, parent company guaranties if applicable, and other collateral as considered necessary to reduce risk of loss. Due to availability of other purchasers, we do not believe the loss of any single oil or natural gas customer would have a material adverse effect on our results of operations.

Interest Rate Risk. Our senior notes and senior subordinated notes both have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At June 30, 2010, we had no borrowings under our credit facility, which bears a floating rate of interest and therefore is susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 33 basis points and would not have a material adverse effect on our 2010 cash flows based on this same level of borrowing.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, consisting of controls and other procedures designed to give reasonable assurance that information we are required to disclose in the reports we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to management, including our chief executive officer and our chief financial officer, to allow timely decisions regarding such required disclosure. The Company’s chief executive officer and chief financial officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the first six months of 2010 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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 2009 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 2010:

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)

04/01/10 – 04/30/10 (1)		1,453	$	34.71		---	$	---
05/01/10 – 05/31/10 (1)		1,000	$	31.37		---		---
06/01/10 – 06/30/10 (1)		165	$	31.11		---		---
Total		2,618	$	33.21		---	$	---

(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 5. Other Information.

James M. Kitterman, Senior Vice President – Operations, has announced his retirement effective March 1, 2011. Mr. Kitterman has provided nearly 28 years of service to Swift Energy Company in various leadership capacities.

None.

Item 6. Exhibits.

	10.1	Amendment No. 3 to the Swift Energy Company First Amended and Restated 2005 Stock Compensation Plan incorporated by reference to Exhibit 10.1 to Form 8-K filed May 12, 2010.
	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 5, 2010	By:	/s/ Alton D. Heckaman, Jr.
		Alton D. Heckaman, Jr. Executive Vice President and Chief Financial Officer

Date: August 5, 2010	By:	/s/ Barry S. Turcotte
		Barry S. Turcotte Vice President, Controller and Principal Accounting Officer

Exhibit Index

10.1	Amendment No. 3 to the Swift Energy Company First Amended and Restated 2005 Stock Compensation Plan incorporated by reference to Exhibit 10.1 to Form 8-K filed May 12, 2010.
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