10-Q

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 September 30, 2014

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 þ No o

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 þ No o

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

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o

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

Yes o No þ

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) 43,859,472 Shares (Outstanding at October 31, 2014)

1

Preliminary Note

Immediately prior to the filing of this report, we filed a Form 10-K/A report for the fiscal year ended December 31, 2013 and Form 10-Q/A reports for the fiscal quarters ended March 31, 2014 and June 30, 2014, restating our financial statements for these periods. These filings were made to correct errors we discovered in our ceiling test calculations for prior periods and to make certain other adjustments with respect to the periods covered by those reports. Certain details regarding those errors and adjustments are discussed in Note 1A - “Restatement of Previously Issued Condensed Consolidated Financial Statements” of this Form 10-Q.

Restatement Background

On November 10, 2014, the Audit Committee of our Board of Directors (the “Audit Committee”), after discussion with management and Ernst & Young LLP (“EY”), our independent registered public accounting firm, determined that the following financial statements previously filed with the SEC should no longer be relied upon: (1) the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2013; (2) the unaudited condensed consolidated financial statements included in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2013, June 30, 2013, and September 30, 2013; and (3) the unaudited condensed consolidated financial statements included our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2014 and June 30, 2014.

In connection with the preparation of our financial statements for the quarter ended September 30, 2014, we determined that an error occurred in our model used for the ceiling test calculation we prepared at December 31, 2013, March 31, 2009 and December 31, 2008, to determine whether the net book value of the Company's oil and gas properties exceed the ceiling. Specifically, this error related to incorrectly including the deferred income tax effect of the Company's asset retirement obligations when computing the ceiling test limitation of its oil and natural gas properties under the full-cost method of accounting. The Company determined that the error caused a material overstatement of its full-cost ceiling test write-down of oil and gas properties in periods prior to 2014.

As a result of this error, we are restating our unaudited consolidated financial statements for the three and nine months ended September 30, 2013. The correction of the error principally resulted in an increase in our depreciation, depletion and amortization expense for the three and nine months ended September 30, 2013 of approximately $0.3 million and $1.0 million, respectively, and decreased net income for the three and nine months ended September 30, 2013 by approximately $0.2 million and $0.6 million, respectively, (net of an decrease to the income tax provision for the three and nine months ended September 30, 2013, of approximately $0.1 million and $0.4 million, respectively). Please refer to Note 1A - “Restatement of Previously Issued Consolidated Financial Statements” of this Form 10-Q for more information regarding the impact of these adjustments.

Along with restating our financial statements to correct the error discussed above, we are making adjustments for certain previously identified immaterial accounting errors related to the periods covered by this form 10-Q. When these financial statements were originally issued, we assessed the impact of these errors and concluded that they were not material to our financial statements for the three and nine months ended September 30, 2013. However, in conjunction with our need to restate our financial statements as a result of the error noted above, we have determined that it would be appropriate within this Form 10-Q to make adjustments for all such previously unrecorded adjustments. Please refer to Note 1A - “Restatement of Previously Issued Consolidated Financial Statements” of this Form 10-Q for more information regarding the impact of these adjustments.

Because these revisions are treated as corrections of errors to our prior period financial results, the revisions are considered to be a “restatement” under U.S. generally accepted accounting principles. Accordingly, the revised financial information included in this Quarterly Report on Form 10-Q has been identified as “restated”.

Internal Control Consideration

Our management has determined that there was a deficiency in our internal control over financial reporting that constitutes a material weakness, as defined by SEC regulations, at September 30, 2014. For a discussion of management’s consideration of our disclosure controls and procedures and the material weakness identified, see Part I, Item 4 included in this Form 10-Q.

2

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2014

INDEX

		Page
Part I	FINANCIAL INFORMATION
Item 1.	Condensed Consolidated Financial Statements
	Condensed Consolidated Balance Sheets	4
	Condensed Consolidated Statements of Operations	5
	Condensed Consolidated Statements of Stockholders’ Equity	6
	Condensed Consolidated Statements of Cash Flows	7
	Notes to Condensed Consolidated Financial Statements	8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	33
Part II	OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 1A.	Risk Factors	34
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34
Item 3.	Defaults Upon Senior Securities	34
Item 4.	Mine Safety Disclosures	34
Item 5.	Other Information	34
Item 6.	Exhibits	34
SIGNATURES		35
Exhibit Index		36

3

Condensed Consolidated Balance Sheets

Swift Energy Company and Subsidiaries (in thousands, except share amounts)

	September 30, 2014 (unaudited)			December 31, 2013 (As Restated)
ASSETS
Current Assets:
Cash and cash equivalents	$	9,041		$	3,277
Accounts receivable	63,385			70,897
Deferred tax asset	9,693			10,715
Other current assets	42,063			7,600
Total Current Assets	124,182			92,489
Property and Equipment:
Property and Equipment, including $65,767 and $71,452 of unproved property costs not being amortized, respectively	5,863,650			5,714,099
Less – Accumulated depreciation, depletion, and amortization	(3,326,908		)	(3,125,282		)
Property and Equipment, Net	2,536,742			2,588,817
Other Long-Term Assets	14,235			17,199
Total Assets	$	2,675,159		$	2,698,505
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	100,493		$	82,318
Accrued capital costs	48,498			61,164
Accrued interest	12,986			21,561
Undistributed oil and gas revenues	13,089			10,990
Total Current Liabilities	175,066			176,033
Long-Term Debt	1,079,269			1,142,368
Deferred Tax Liabilities	253,689			241,205
Asset Retirement Obligation	67,155			63,225
Other Long-Term Liabilities	9,631			10,324
Commitments and Contingencies	—			—
Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding	—			—
Common stock, $.01 par value, 150,000,000 shares authorized, 44,296,246 and 43,915,346 shares issued, and 43,857,765 and 43,401,920 shares outstanding, respectively	443			439
Additional paid-in capital	769,663			762,242
Treasury stock held, at cost, 438,481, and 513,426 shares, respectively	(9,744		)	(12,575		)
Retained earnings	329,987			315,244
Total Stockholders’ Equity	1,090,349			1,065,350
Total Liabilities and Stockholders’ Equity	$	2,675,159		$	2,698,505
See accompanying Notes to Condensed Consolidated Financial Statements.

4

Condensed Consolidated Statements of Operations (Unaudited)

Swift Energy Company and Subsidiaries (in thousands, except per-share amounts)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2014		2013 (As Restated)			2014			2013 (As Restated)
Revenues:
Oil and gas sales	$	133,896	$	152,981		$	441,440		$	442,015
Price-risk management and other, net	4,898		(2,048		)	(2,472		)	(714		)
Total Revenues	138,794		150,933			438,968			441,301
Costs and Expenses:
General and administrative, net	10,981		11,146			33,565			35,062
Depreciation, depletion, and amortization	65,331		67,274			201,072			187,503
Accretion of asset retirement obligation	1,445		1,478			4,246			4,732
Lease operating cost	22,067		23,078			70,606			76,919
Transportation and gas processing	5,107		5,783			16,412			15,386
Severance and other taxes	10,191		11,695			28,829			32,221
Interest expense, net	18,197		17,495			55,295			51,297
Total Costs and Expenses	133,319		137,949			410,025			403,120
Income Before Income Taxes	5,475		12,984			28,943			38,181
Provision for Income Taxes	3,001		5,625			14,200			15,235
Net Income	$	2,474	$	7,359		$	14,743		$	22,946
Per Share Amounts-
Basic:  Net Income	$	0.06	$	0.17		$	0.34		$	0.53
Diluted:  Net Income	$	0.06	$	0.17		$	0.33		$	0.53
Weighted Average Shares Outstanding - Basic	43,850		43,389			43,768			43,308
Weighted Average Shares Outstanding - Diluted	44,473		43,704			44,299			43,624
See accompanying Notes to Condensed Consolidated Financial Statements.

5

Condensed Consolidated Statements of Stockholders’ Equity

Swift Energy Company and Subsidiaries (in thousands, except share amounts)

	Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Total
Balance, December 31, 2012 (As Restated)	$	435	$	748,517		$	(13,855	)	$	317,686		$	1,052,783
Stock issued for benefit plans (104,890 shares)	—		(1,171		)	2,793			—			1,622
Shares issued from option exercises (1,125 shares)	—		4			—			—			4
Purchase of treasury shares (98,020 shares)	—		—			(1,513		)	—			(1,513		)
Tax shortfall from share-based compensation	—		(1,607		)	—			—			(1,607		)
Employee stock purchase plan (72,273 shares)	1		945			—			—			946
Issuance of restricted stock (391,581 shares)	3		(3		)	—			—			—
Amortization of share-based compensation	—		15,557			—			—			15,557
Net Loss	—		—			—			(2,442		)	(2,442		)
Balance, December 31, 2013 (As Restated)	$	439	$	762,242		$	(12,575	)	$	315,244		$	1,065,350
Stock issued for benefit plans (154,665 shares) (1)	—		(1,876		)	3,785			—			1,909
Purchase of treasury shares (79,720 shares) (1)	—		—			(954		)	—			(954		)
Employee stock purchase plan (71,825 shares) (1)	1		823			—			—			824
Issuance of restricted stock (309,075 shares) (1)	3		(3		)	—			—			—
Amortization of share-based compensation (1)	—		8,477			—			—			8,477
Net Income (1)	—		—			—			14,743			14,743
Balance, September 30, 2014	$	443	$	769,663		$	(9,744	)	$	329,987		$	1,090,349
(1) Unaudited
See accompanying Notes to Condensed Consolidated Financial Statements.

6

Condensed Consolidated Statements of Cash Flows (Unaudited)

Swift Energy Company and Subsidiaries (in thousands)

	Nine Months Ended September 30,
	2014			2013 (As Restated)
Cash Flows from Operating Activities:
Net income	$	14,743		$	22,946
Adjustments to reconcile net income to net cash provided by operating activities-
Depreciation, depletion, and amortization	201,072			187,503
Accretion of asset retirement obligation	4,246			4,732
Deferred income taxes	13,507			15,235
Share-based compensation expense	5,571			8,454
Other	(390		)	(4,093		)
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other current assets	14,159			(3,293		)
Increase (decrease) in accounts payable and accrued liabilities	7,299			2,588
Increase (decrease) in income taxes payable	543			(208		)
Increase (decrease) in accrued interest	(8,575		)	(8,257		)
Net Cash Provided by Operating Activities	252,175			225,607
Cash Flows from Investing Activities:
Additions to property and equipment	(316,972		)	(435,722		)
Proceeds from the sale of property and equipment	145,535			6,990
Funds withdrawn from restricted cash account	6,501			—
Funds deposited into restricted cash account	(18,345		)	—
Net Cash Used in Investing Activities	(183,281		)	(428,732		)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	639,000			968,500
Payments of bank borrowings	(702,000		)	(764,900		)
Net proceeds from issuances of common stock	824			946
Purchase of treasury shares	(954		)	(1,494		)
Net Cash Provided by (Used in) Financing Activities	(63,130		)	203,052
Net increase (decrease) in Cash and Cash Equivalents	5,764			(73		)
Cash and Cash Equivalents at Beginning of Period	3,277			170
Cash and Cash Equivalents at End of Period	$	9,041		$	97
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	$	61,983		$	57,990
Cash paid during period for income taxes	$	150		$	208
See accompanying Notes to Condensed Consolidated Financial Statements.

7

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,” the “Company,” or “we”) 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 note 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/A for the fiscal year ended December 31, 2013 as filed with the Securities and Exchange Commission on November 17, 2014.

(1A)       Restatement of Previously Issued Condensed Consolidated Financial Statements

Overview. In connection with the preparation of our financial statements for the quarter ended September 30, 2014, we determined that the ceiling test calculation we had prepared at December 31, 2013, March 31, 2009 and December 31, 2008, to determine whether the net book value of the Company's oil and gas properties exceed the ceiling, incorrectly included the deferred income tax effect of the Company's asset retirement obligations when computing the ceiling test limitation of its oil and natural gas properties under the full-cost method of accounting. The Company determined that the error caused a material overstatement of its full-cost ceiling test write-down of oil and gas properties in periods prior to 2014, more specifically in the fourth quarter of 2013, in the first quarter of 2009 and the fourth quarter of 2008, including associated depletion for all periods presented. As a result of this error, in this Form 10-Q we are restating our unaudited condensed consolidated financial information for the three and nine months ended September 30, 2013.

For the 2013 periods presented herein, the correction of the error principally results in an increase in our depreciation, depletion and amortization expense for the three and nine months ended September 30, 2013 of approximately $0.3 million and $1.0 million, respectively, and decreased net income for the three and nine months ended September 30, 2013 by approximately $0.2 million and $0.6 million, respectively (net of a decrease to the income tax benefit for the three and nine months ended September 30, 2013, of approximately $0.1 million and $0.4 million, respectively).

Along with restating our financial statements to correct the error discussed above, we have recorded adjustments for certain previously identified immaterial accounting errors related to the periods covered by this Form 10-Q. When these financial statements were originally issued, we assessed the impact of these errors and concluded that they were not material to our financial statements for the three and nine months ended September 30, 2013. However, in conjunction with our need to restate our financial statements as a result of the error noted above, we have determined that it would be appropriate to make adjustments within this Form 10-Q for all such previously unrecorded adjustments.

The combined impacts of all adjustments to the applicable line items in our unaudited condensed consolidated financial statements for the periods covered by this Form 10-Q are provided in the tables below.

8

The following tables present the effect of the correction of the error and other adjustments on selected line items of our previously reported unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2013 (in thousands):

	Condensed Consolidated Statements of Operations For the Three Months Ended September 30, 2013							Condensed Consolidated Statements of Operations For the Nine Months Ended September 30, 2013
	(As Reported)		Adjustments			(As Restated)		(As Reported)		Adjustments			(As Restated)
Oil and Gas Sales	$	155,049	$	(2,068	)	$	152,981	$	442,418	$	(403	)	$	442,015
Total Revenues	153,001		(2,068		)	150,933		441,704		(403		)	441,301
Depreciation, depletion, and amortization	66,948		326			67,274		186,526		977			187,503
Lease operating cost	23,078		—			23,078		77,459		(540		)	76,919
Transportation and gas processing	5,783		—			5,783		16,678		(1,292		)	15,386
Severance and other taxes	11,695		—			11,695		31,971		250			32,221
Total Costs and Expenses	137,623		326			137,949		403,725		(605		)	403,120
Income (Loss) from Continuing Operations Before Income Taxes	15,378		(2,394		)	12,984		37,979		202			38,181
Provision (Benefit) for Income Taxes	6,492		(867		)	5,625		15,162		73			15,235
Net Income (Loss)	8,886		(1,527		)	7,359		22,817		129			22,946
Basic EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.53	$	—		$	0.53
Diluted EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.52	$	0.01		$	0.53

	Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2013
	(As Reported)			Adjustments			(As Restated)
Net income (loss)	$	22,817		$	129		$	22,946
Depreciation, depletion, and amortization	186,526			977			187,503
Deferred income taxes	15,162			73			15,235
Other	(3,796		)	(297		)	(4,093		)
(Increase) decrease in accounts receivable	(3,696		)	403			(3,293		)
Increase (decrease) in accounts payable and accrued liabilities	3,873			(1,285		)	2,588
Net Cash Provided by Operating Activities	225,607			—			225,607

(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 gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in oil and gas properties 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.

Subsequent Events. We have evaluated subsequent events of our consolidated financial statements. There were no material subsequent events requiring additional disclosure in 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 amounts of certain assets

9

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 therefrom,

• 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 sales, 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 share-based 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,

• estimates in the calculation of the fair value of hedging assets and liabilities, and

• estimates in the assessment of current litigation claims against the company.

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 adjustments occur.

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.

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 three months ended September 30, 2014 and 2013, such internal costs capitalized totaled $6.9 million and $7.9 million, respectively. For the nine months ended September 30, 2014 and 2013, such internal costs capitalized totaled $20.9 million and $23.9 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the three months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $1.2 million and $1.8 million, respectively. For the nine months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $3.7 million and $5.6 million, respectively. Interest not capitalized and general and administrative costs related to production and general corporate overhead are expensed as incurred.

10

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 (in thousands):

	September 30, 2014			December 31, 2013 (As Restated)
Property and Equipment
Proved oil and gas properties	$	5,755,886		$	5,600,279
Unproved oil and gas properties	65,767			71,452
Furniture, fixtures, and other equipment	41,997			42,368
Less – Accumulated depreciation, depletion, and amortization	(3,326,908		)	(3,125,282		)
Property and Equipment, Net	$	2,536,742		$	2,588,817

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 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 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 two and 20 years. Repairs and maintenance are charged to expense as incurred.

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 price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). This calculation is done on a country-by-country basis.

The calculations of the Ceiling Test and provision for DD&A are 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.

11

It is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the future and that non-cash write-downs of oil and natural gas properties could occur in the future. For example, if future capital expenditures out pace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, non-cash write-downs of our oil and natural gas properties could occur. We cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties.

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 condensed consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying condensed consolidated balance sheets when our ownership share of production exceeds sales. As of September 30, 2014 and December 31, 2013, we did not have any material natural gas imbalances.

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

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At September 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts of approximately $0.4 million and $0.1 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

At September 30, 2014, our “Accounts receivable” balance included $51.9 million for oil and gas sales, $1.9 million for joint interest owners, $7.9 million for severance tax credit receivables and $1.7 million for other receivables. At December 31, 2013, our “Accounts receivable” balance included $56.9 million for oil and gas sales, $1.6 million for joint interest owners, $11.6 million for severance tax credit receivables and $0.8 million for other receivables.

Debt Issuance Costs. Legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with extensions of our bank credit facility and public debt offerings were capitalized and are amortized on an effective interest basis over the life of each of the respective senior note offerings and credit facility.

The 7.125% senior notes due in 2017 mature on June 1, 2017, and the balance of their issuance costs at September 30, 2014, was $1.4 million. The 8.875% senior notes due in 2020 mature on January 15, 2020, and the balance of their issuance costs at September 30, 2014, was $3.2 million. The 7.875% senior notes due in 2022 mature on March 1, 2022, and the balance of their issuance costs at September 30, 2014, was $6.1 million. The balance of revolving credit facility issuance costs at September 30, 2014, was $2.5 million.

Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized in earnings. The changes in the fair value of our derivatives are recognized in "Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. 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 swaps, floors, calls, collars and participating collars.

During the three months ended September 30, 2014 and 2013, we recorded a net gain of $5.0 million and a net loss of $2.0 million, respectively, relating to our derivative activities. The 2014 amount includes a revenue increase of $1.2 million during the third quarter of 2014 for the non-cash fair value adjustments on commodity derivatives. For the nine months ended September 30, 2014 and 2013, we recorded net losses of $2.7 million and $0.8 million, respectively, relating to our derivative activities. The effects of our derivatives are included in the "Other" section of our operating activities on the accompanying condensed consolidated statements of cash flows.

The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. The fair value of our current unsettled derivative assets at September 30, 2014 was $0.7 million which was recognized on the accompanying condensed consolidated balance sheet in “Other current assets.” The fair values of our current and non-current unsettled derivative liabilities at September 30, 2014 were $0.5 million and $0.1 million which were recognized on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and “Other Long-Term Liabilities”, respectively.

12

At September 30, 2014, we had $1.0 million in receivables for settled derivatives which were recognized on the accompanying condensed consolidated balance sheet in “Accounts receivable” and were subsequently collected in October 2014. At September 30, 2014, we also had $0.1 million in payables for settled derivatives which were recognized on the accompanying condensed consolidated balance sheet in "Accounts payable and accrued liabilities" and were subsequently paid in October 2014.

The Company uses an International Swap and Derivatives Association "ISDA" master agreement for our derivative contracts. This is an industry standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. If all counterparties were in a default situation, the Company, under the right of set-off, would have shown a net derivative fair value asset of $0.1 million and liability of $0.1 million at September 30, 2014 and December 31, 2013, respectively. For further discussion related to the fair value of the Company's derivatives, refer to Note 7 of these condensed consolidated financial statements.

The following tables summarize the weighted average prices and future production volumes for our unsettled derivative contracts in place as of September 30, 2014:

				Collars
Natural Gas Derivatives (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Swap Fixed Price		Floor Price		Ceiling Price
2014 Contracts
Swaps	3,330,000	$	4.32
Collars	1,035,000			$	4.15	$	4.55
2015 Contracts
Swaps	900,000	$	4.42

Natural Gas Basis Derivatives (East Texas Houston Ship Channel Settlements)	Total Volumes (MMBtu)	Swap Fixed Price
2014 Contracts
Swaps	4,200,000	$	(0.11	)
2015 Contracts
Swaps	8,200,000	$	(0.02	)

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying condensed consolidated statements of operations. Our supervision fees are based on COPAS industry guidelines. The amount of supervision fees charged for the three and nine months ended September 30, 2014 and 2013 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $3.5 million and $2.8 million for the three months ended September 30, 2014 and 2013, respectively and $9.2 million and $8.9 million for the nine months ended September 30, 2014 and 2013, respectively.

Inventories. Inventories consist primarily of tubulars and other equipment and supplies 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 $3.1 million and $3.5 million at September 30, 2014 and December 31, 2013, respectively.

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

13

settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2014, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

Our U.S. Federal income tax returns for 2007 forward, our Louisiana income tax returns from 1999 forward and our Texas franchise tax returns after 2008 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 jurisdiction returns are significant to our financial position.

For the nine months ended September 30, 2014, we recognized an income tax expense increase of $2.1 million related to a shortfall between the tax deduction received with respect to prior restricted stock grants that vested during the year versus the actual book expense recorded over the life of those grants.

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):

	September 30, 2014		December 31, 2013 (As Restated)
Trade accounts payable (1)	$	25,624	$	30,769
Accrued operating expenses	14,451		16,016
Accrued payroll costs	11,212		10,938
Asset retirement obligation – current portion	13,292		15,859
Accrued taxes	9,626		5,845
Deposit liability (2)	22,685		—
Other payables	3,603		2,891
Total accounts payable and accrued liabilities	$	100,493	$	82,318

(1) Included in “trade accounts payable” are liabilities of approximately $9.6 million and $26.1 million at September 30, 2014 and December 31, 2013, respectively, for outstanding checks.

(2) This amount equals the liability related to funds received from Saka Energi that are maintained in a restricted cash account. Refer to the "Short-Term Restricted Cash" discussion below for further information.

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.

Short-Term Restricted Cash (Saka Energi Transaction). On July 15, 2014, we closed our transaction with PT Saka Energi Indonesia ("Saka Energi") to fully develop 8,300 acres of Fasken area Eagle Ford shale properties owned by Swift Energy in Webb County, Texas. Swift Energy sold a 36% full participating interest in the Fasken properties to Saka Energi.

Subject to the terms of the transaction, Swift Energy and Saka Energi are required to deposit cash on a monthly basis into a separate Swift Energy-owned bank account to fund their respective portions of the on-going Fasken development program for the following month. All cash deposited in the account is contractually restricted for use in the Fasken development program and therefore is recorded as restricted cash until the Company has performed the related development activities.

As of September 30, 2014, we recorded $34.5 million of restricted cash including $11.8 million for deposits from Swift Energy with the remaining deposits from Saka Energi. The restricted cash balance is reported in “Other current assets” while the related deposit liability is reported in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

During the quarter Saka Energi deposited $29.8 million into the account while $7.1 million was withdrawn from the account in order to fund on-going development operations in the Fasken area. The cash changes from the account relating to Saka Energi’s contributions are shown in the operating activities section of the accompanying condensed consolidated statements of cash flows. The cash changes from the account relating to Swift Energy’s contributions are reported in the investing activities section on the accompanying condensed consolidated statements of cash flows.

Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of September 30, 2014 and December 31, 2013, these assets were approximately $1.0 million.

14

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. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.

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 as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. 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):

	2014
Asset Retirement Obligation recorded as of January 1	$	79,084
Accretion expense	4,246
Liabilities incurred for new wells and facilities construction	470
Reductions due to sold and abandoned wells and facilities	(2,914		)
Revisions in estimates	(439		)
Asset Retirement Obligation as of September 30	$	80,447

At September 30, 2014 and December 31, 2013, approximately $13.3 million and $15.9 million of our asset retirement obligation was classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09, providing a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance. The guidance is effective for annual and interim reporting periods beginning after December 15, 2016 and upon adoption, entities are required to recognize revenue using the following five-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation. Adoption of this standard could result in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. We plan to review and assess the effect and implement any necessary requirements as needed.

(3)           Share-Based Compensation

We have various types of share-based compensation plans. Refer to our definitive proxy statement for our annual meeting of shareholders filed with the SEC on April 2, 2014, as well as Note 6 of our consolidated financial statements in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013, 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 stock options are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. We receive an additional tax deduction when restricted stock awards vest 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 three and nine months ended September 30, 2014, we recognized an income tax shortfall in earnings of $0.2 million and $2.1 million, respectively, primarily related to restricted stock awards that vested at a price lower than the grant date fair value. For the three and nine months ended September 30, 2013, we did not recognize any material excess tax benefit or shortfall in earnings. There were no stock option exercises for the nine months ended September 30, 2014 and 2013.

Share-based compensation expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations, was $1.7 million and

15

$2.2 million for the three months ended September 30, 2014 and 2013, respectively and $5.1 million and $7.8 million for the nine months ended September 30, 2014 and 2013, respectively. Share-based compensation recorded in lease operating cost was $0.1 million for the three months ended September 30, 2014 and 2013 and was $0.2 million for the nine months ended September 30, 2014 and 2013, respectively. We also capitalized $0.9 million and $1.2 million of share-based compensation for the three months ended September 30, 2014 and 2013, respectively, and capitalized $2.9 million and $4.4 million for the nine months ended September 30, 2014 and 2013, respectively. We view stock option awards and restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life of component awards and amortize the awards on a straight-line basis over the life of the awards.

Stock Option Awards

We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards. During the nine months ended September 30, 2014 and 2013 we did not grant any stock option awards.

At September 30, 2014, we had $0.2 million of unrecognized compensation cost related to stock option awards, which is expected to be recognized over a weighted-average period of 0.4 years. The following table represents stock option award activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Exercise Price
Options outstanding, beginning of period	1,488,314	$	33.38
Options granted	—	$	—
Options canceled	(90,527)	$	25.20
Options exercised	—	$	—
Options outstanding, end of period	1,397,787	$	33.88
Options exercisable, end of period	1,295,616	$	33.98

Our stock option awards outstanding and exercisable at September 30, 2014 were out of the money and therefore had no aggregate intrinsic value. At September 30, 2014, the weighted average contract life of stock option awards outstanding was 4.8 years and the weighted average contract life of stock option awards exercisable was 4.6 years. There were no stock option exercises for the nine months ended September 30, 2014 and 2013.

Restricted Stock Awards

The plans, as described in Note 6 of our consolidated financial statements in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013, allow for the issuance of restricted stock awards that generally 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 September 30, 2014, we had unrecognized compensation expense of $12.4 million related to restricted stock awards which is expected to be recognized over a weighted-average period of 1.7 years. The grant date fair value of shares vested during the nine months ended September 30, 2014 was $10.6 million.

The following table represents restricted stock award activity for the nine months ended September 30, 2014:

	Shares		Wtd. Avg. Grant Price
Restricted shares outstanding, beginning of period	1,267,110		$	21.54
Restricted shares granted	743,150		$	11.58
Restricted shares canceled	(139,973	)	$	15.16
Restricted shares vested	(308,825	)	$	34.27
Restricted shares outstanding, end of period	1,561,462		$	14.85

16

Performance-Based Restricted Stock Units

For the nine months ended September 30, 2014 and 2013, the Company granted 185,250 and 189,700 units, respectively, of performance-based restricted stock units containing predetermined market and performance conditions with a cliff vesting period of 3.1 years. These units were granted at 100% of target payout while the conditions of the grants allow for a payout ranging between no payout and 200% of target.

The compensation expense for the market condition is based on the per unit grant date valuation using a Monte-Carlo simulation. The performance condition is remeasured quarterly and compensation expense is recorded based on the closing market price of our stock per unit on the grant date multiplied by the expected payout level. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group.

As of September 30, 2014, we had unrecognized compensation expense of $2.8 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.0 years. No shares vested during the nine months ended September 30, 2014 and 2013. The weighted average grant date fair value for the restricted stock units granted during the nine months ended September 30, 2014 and 2013 was $11.68 and $15.01 per unit, respectively.

The following table represents restricted stock unit activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Grant Price
Restricted stock units outstanding, beginning of period	189,700	$	15.01
Restricted stock units granted	185,250	$	11.68
Restricted stock units canceled	—	$	—
Restricted stock units vested	—	$	—
Restricted stock units outstanding, end of period	374,950	$	13.36

(4)           Earnings Per Share

The Company computes earnings per share in accordance with FASB ASC 260-10. Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2014 and 2013, 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 nine months ended September 30, 2014 and 2013 (in thousands, except per share amounts):

	Three Months Ended September 30, 2014					Three Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	2,474	43,850	$	0.06	$	7,359	43,389	$	0.17
Dilutive Securities:
Restricted Stock Awards			564					288
Restricted Stock Units			59					27
Diluted EPS:
Net Income and Assumed Share Conversions	$	2,474	44,473	$	0.06	$	7,359	43,704	$	0.17

17

	Nine Months Ended September 30, 2014					Nine Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	14,743	43,768	$	0.34	$	22,946	43,308	$	0.53
Dilutive Securities:
Restricted Stock Awards			469					249
Restricted Stock Units			62					67
Diluted EPS:
Net Income and Assumed Share Conversions	$	14,743	44,299	$	0.33	$	22,946	43,624	$	0.53

Approximately 1.4 million and 1.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2014 and 2013, respectively, and approximately 1.4 million and 1.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2014 and 2013 because these stock options were antidilutive. Approximately 0.2 million restricted stock awards were not included in the computation of Diluted EPS for the three months ended September 30, 2014 and 2013, and approximately 0.3 million restricted stock awards were not included in the computation of Diluted EPS for the nine months ended September 30, 2014 and 2013 because they were antidilutive. Approximately 0.7 million and 0.4 million shares for three and nine months ended September 30, 2014 and 2013, respectively, related to performance-based restricted stock units that could be converted to common shares based on predetermined performance and market goals were not included in the computation of Diluted EPS because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the performance period.

18

(5)           Long-Term Debt

Our long-term debt as of September 30, 2014 and December 31, 2013, was as follows (in thousands):

	September 30, 2014		December 31, 2013
7.125% senior notes due in 2017	$	250,000	$	250,000
8.875% senior notes due in 2020 (1)	222,691		222,446
7.875% senior notes due in 2022 (1)	404,578		404,922
Bank Borrowings due in 2017	202,000		265,000
Long-Term Debt (1)	$	1,079,269	$	1,142,368
(1) Amounts are shown net of any debt discount or premium

As of September 30, 2014, we had $202.0 million of outstanding bank borrowings on our credit facility which has a maturity date of November 1, 2017. The maturities on our senior notes are $250.0 million in 2017, $225.0 million in 2020 and $400.0 million in 2022.

We have capitalized interest on our unproved properties in the amount of $1.2 million and $1.8 million for the three months ended September 30, 2014 and 2013, respectively, and we have capitalized interest on our unproved properties in the amount of $3.7 million and $5.6 million for the nine months ended September 30, 2014 and 2013, respectively.

Bank Borrowings. Effective October 17, 2014, our syndicate of 11 banks reaffirmed the borrowing base and commitment amount of $417.6 million on our $500.0 million credit facility. The maturity date of November 1, 2017 remained unchanged.

We had $202.0 million and $265.0 million in outstanding borrowings under our credit facility at September 30, 2014 and December 31, 2013, respectively. The interest rate on our credit facility is either (a) the lead bank’s prime rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. However with respect to (a), if the lead bank’s prime rate is not higher than each of the federal funds rate plus 0.5%, and the adjusted London Interbank Offered Rate (“LIBOR”) plus 1%, the greatest of these three rates will then apply. The applicable margins vary depending on the level of outstanding debt with escalating rates of 50 to 150 basis points above the Alternative Base Rate and escalating rates of 150 to 250 basis points for Eurodollar rate loans. At September 30, 2014, the lead bank’s prime rate was 3.25%. The commitment fee associated with the credit facility fluctuated between 0.38% and 0.50% for the three months ended September 30, 2014.

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 as defined in the terms of our credit facility) and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. As of September 30, 2014, we were in compliance with the provisions of this agreement. The credit facility is secured by our oil and natural gas properties. Under the terms of the credit facility, the commitment amount can be less than or equal to the total amount of the borrowing base with unanimous consent of the bank group as it might change from time to time.

Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.7 million and $1.6 million for the three months ended September 30, 2014 and 2013, respectively. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $5.9 million and $4.0 million for the nine months ended September 30, 2014 and 2013, respectively. The amount of commitment fees included in interest expense, net was $0.2 million for the three months ended September 30, 2014 and 2013, and was $0.6 million and $0.9 million for the nine months ended September 30, 2014 and 2013.

Senior Notes Due In 2022. These notes consist of $400.0 million of 7.875% senior notes that will mature on March 1, 2022. On November 30, 2011, we issued $250.0 million of these senior notes at a discount of $2.1 million or 99.156% of par, which equates to an effective yield to maturity of 8%. The original discount of $2.1 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. On October 3, 2012, we issued an additional $150.0 million of these senior notes at 105% of par, which equates to a yield to worst of 6.993%. The premium of $7.5 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. 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

19

credit facility, and will rank senior to any future subordinated indebtedness of Swift Energy. Interest on these notes is payable semi-annually on March 1 and September 1 and commenced on March 1, 2012. On or after March 1, 2017, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.938% of principal, declining  in twelve-month intervals to 100% in 2020 and thereafter. In addition, prior to March 1, 2015, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 107.875% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $7.5 million of debt issuance costs related to these notes, which is included in “Other Long–Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

Interest expense on the senior notes due in 2022, including amortization of debt issuance costs and debt premium, totaled $7.9 million for the three months ended September 30, 2014 and 2013 and $23.7 million for the nine months ended September 30, 2014 and 2013.

Senior Notes Due In 2020. These notes consist of $225.0 million of 8.875% senior notes issued at 98.389% of par, which equates to an effective yield to maturity of 9.125%. The notes were issued on November 25, 2009 with an original discount of $3.6 million and will mature on January 15, 2020. The original discount of $3.6 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. 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 January 15, 2010. 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. We incurred approximately $5.0 million of debt issuance costs related to these notes, which is included in “Other Long–Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

Interest expense on the senior notes due in 2020, including amortization of debt issuance costs and debt discount, totaled $5.2 million for the three months ended September 30, 2014 and 2013 and $15.6 million and $15.5 million for the nine months ended September 30, 2014 and 2013, respectively.

Senior Notes Due In 2017. These notes consist of $250.0 million of 7.125% senior notes due in 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. We may redeem some or all of these notes, with certain restrictions, starting at a redemption price of 102.375% of the principal, plus accrued and unpaid interest, declining in twelve-month intervals to 100% on June 1, 2015 and thereafter. We incurred approximately $4.2 million of debt issuance costs related to these notes, which is included in “Other Long-Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

20

Interest expense on the senior notes due in 2017, including amortization of debt issuance costs, totaled $4.6 million for the three months ended September 30, 2014 and 2013 and $13.7 million for the nine months ended September 30, 2014 and 2013.

(6)           Acquisitions and Dispositions

On July 15, 2014, we closed our transaction with Saka Energi to fully develop 8,300 acres of Fasken area Eagle Ford shale properties owned by Swift Energy in Webb County, Texas, with an effective date of January 1, 2014. Swift Energy sold a 36% full participating interest in the Fasken properties to Saka Energi for $175 million in total cash consideration, with $125 million paid at closing (subject to adjustments for the interim period between the effective date and the closing date) and $50 million in cash to be paid by Saka Energi over time to carry a portion of Swift Energy's field development costs incurred after the effective date. As of September 30, 2014, approximately $35 million remained of Saka Energi's original $50 million carry obligation. At closing, the company received approximately $147 million in proceeds, including a $12.5 million deposit received during the prior quarter which was held in an escrow account until the closing date, as well as adjustments for the interim period between the effective date and the closing date. The proceeds initially were used to reduce our outstanding borrowings on our credit facility which were partially offset by additional borrowings against the credit facility during the quarter to fund development expenditures. No gain or loss was recognized for the transaction as the proceeds were applied to the full cost pool.

(7)           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.

Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Based upon quoted market prices as of September 30, 2014 and December 31, 2013, the fair value and carrying value of our senior notes was as follows (in millions):

	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
7.125% senior notes due in 2017	$	251.9	$	250.0	$	256.7	$	250.0
8.875% senior notes due in 2020	$	225.0	$	222.7	$	239.1	$	222.4
7.875% senior notes due in 2022	$	411.0	$	404.6	$	409.0	$	404.9

Our senior notes due in 2017, 2020 and 2022 are stated as liabilities at carrying value on our accompanying condensed consolidated balance sheets, net of any discount or premium. If we recorded these notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments.

21

The following table presents our assets and liabilities that are measured at fair value as of September 30, 2014 and December 31, 2013, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 2 of these condensed consolidated financial statements. 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
	Total Assets / Liabilities		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs  (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2014
Assets:
Natural Gas Derivatives	$	0.7	$	—	$	0.7	$	—
Liabilities:
Natural Gas Basis Derivatives	0.6		—		0.6		—
December 31, 2013
Assets:
Natural Gas Derivatives	0.5		—		0.5		—
Oil Derivatives	0.3		—		0.3		—
Liabilities:
Natural Gas Derivatives	0.7		—		0.7		—
Oil Derivatives	0.2		—		0.2		—

Our unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Other current assets” and "Accounts payable and accrued liabilities", respectively.

Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.

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 are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that 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.

(8)           Condensed Consolidating Financial Information

Swift Energy Company (the parent) is the issuer and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of Swift Energy Company) is the sole guarantor of our senior notes due in 2017, 2020 and 2022. Swift Energy Company does not have any independent assets or operations. The guarantees on our senior notes due in 2017, 2020 and 2022 are full and unconditional. All subsidiaries of Swift Energy Company, other than Swift Energy Operating, LLC, are minor.

(9)           Commitments and Contingencies

During 2014, the Company entered into additional gas transportation agreements. As of September 30, 2014, the minimum commitments under these agreements total approximately $36.3 million covering transportation from 2015 through 2020.

We had no other material changes from amounts referenced under Note 5 in our Notes to Consolidated Financial Statements from our Annual Report on Form 10-K/A for the year ending December 31, 2013.

22

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

You should read the following discussion and analysis in conjunction with our financial information and our consolidated financial statements and accompanying notes included in this report and our annual report on Form 10-K/A for the year ended December 31, 2013. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 29 of this report.

Restatement

As discussed in the Preliminary Note and in Note 1A of the Notes to Consolidated Financial Statements included in this Form 10-Q, we are restating our unaudited condensed consolidated financial statements and related disclosures for the three and nine months ended September 30, 2013. The following discussion and analysis of our financial condition and results of operations incorporates the restated amounts. For this reason, the data set forth in this Item 2 may not be comparable to the discussion and data in our previously filed quarterly report on Form 10-Q for the quarter ended September 30, 2013.

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 our Texas properties as well as onshore and inland waters of Louisiana. We hold a large acreage position in Texas prospective for Eagle Ford shale and Olmos tight sands development and are one of the largest producers of crude oil in the state of Louisiana. Oil production accounted for 29% of our third quarter 2014 production and 62% of our oil and gas sales, and combined production of both oil and natural gas liquids (“NGLs”) constituted 45% of our third quarter 2014 production and 74% of our oil and gas sales.

Recent Events and 2015 Capital Spending Plans and Expectations

• Recent crude oil price decline: Both natural gas and crude oil prices are volatile and significant price movement can impact our profitability and cash flows. Oil prices started to decline in the third quarter of 2014 and this decline accelerated during the month of October 2014. Between June 30, 2014 and October 31, 2014, WTI crude oil prices decreased 24% with the most rapid decline occurring in October 2014. Although the effect of this price decrease was somewhat muted on our third quarter results, we expect fourth quarter 2014 results will be affected in a more significant way as 60% of the Company’s oil and gas sales for the first nine months of 2014 were derived from crude oil sales.

• Update of 2014 planned capital expenditures: For 2014, the Company is targeting annual production levels of 12.2 to 12.3 MMBoe with an average daily production rate of 33.4 to 33.7 MBoe/d, which is an increase from our previous expectation of 11.9 to 12.1 MMBoe. This increase is based on planned full-year capital expenditures of $390 to $400 million, which is an increase from our most recent estimate of $375 to $400 million. We will continue to fund our 2014 capital expenditures with our operating cash flow and a portion of the proceeds received from the recently closed Saka Energi transaction.

• 2015 capital spending and expectations: We expect the current significantly lower oil and natural gas prices to reduce operating cash flows and we therefore have meaningfully reduced our capital spending plans for 2015. We currently plan to spend between $240 to $260 million next year, with a focus on drilling activity in our Fasken area as well as in our South Texas oil and condensate properties. Based on this level of capital expenditures, we currently expect 2015 production to remain level with our current year average production, which is expected to average 33.4 to 33.7 MBoe/d for 2014. A portion of our capital expenditure program is discretionary and may be deferred if necessary. We forecast our capital expenditures will exceed our operating cash flows by approximately $60 to $70 million using commodity prices as of November 1, 2014. We expect to cover this level of spending through a combination of asset dispositions, joint ventures or other partnerships and will use excess proceeds to reduce borrowings on our credit facility and/or retire a portion of our long-term debt. Between June 30, 2014 and September 30, 2014, the outstanding balance under our credit facility had been reduced by approximately $100 million using a portion of the proceeds from the July 2014 closing of the Saka Energi transaction. We will continue to work with a prospective buyer for all of our Central Louisiana properties, although we remain uncertain when or if this transaction will occur. At this point, if no sale of these assets were to occur, we anticipate investing a limited amount of capital in this area during 2015 in low risk projects to maintain the value of these assets, and we will continue to consider offering portions of these properties for sale in separate parcels.

23

Third Quarter 2014 Activities

• Saka Energi transaction: On July 15, 2014, we closed a transaction with Saka Energi to fully develop 8,300 acres of natural gas Eagle Ford shale properties in our Fasken area. Saka Energi purchased a 36% full participating interest in the properties for $175 million in total cash consideration, with $125 million paid at closing and $50 million in cash to be paid by Saka Energi over time to carry a portion of Swift Energy's field development costs incurred after the effective date, January 1, 2014. As of September 30, 2014, approximately $35 million remained of Saka Energi's original $50 million carry obligation, which is expected to be fulfilled by the end of calendar year 2016 but is dependent on the pace of drilling in the Fasken area. At closing, Swift received proceeds of approximately $147 million, composed of the initial $125 million in cash consideration plus Saka Energi's share of capital costs, net of revenue between the January 1, 2014 effective date and the closing date. The consideration included a $12.5 million deposit received during the prior quarter that was held in an escrow account until the closing date. The proceeds from this transaction initially were used to pay down our credit facility which were partially offset by additional borrowings against the credit facility during the quarter to fund development expenditures. We expect this transaction to allow accelerated drilling and development of our Fasken properties.

• Fasken production: In Fasken, we have grown our Eagle Ford dry gas gross production from 28.3 million cubic feet of gas per day (“MMcf/d”) during the second quarter of 2013 to over 100 MMcf/d during the third quarter of 2014. We have contracted firm transportation capacity of 75 MMcf/d and have also been able to access interruptible capacity in excess of that amount during the third quarter of 2014. We also contracted for an increase in this firm transportation capacity to 160 MMcf/d, which is now in place and ready for service. We currently expect to reach our fully committed capacity production levels before the end of the first quarter of 2015.

• Production: Our production volumes decreased by 2% in the third quarter of 2014 when compared to volumes in the same period in 2013, as oil volumes decreased by 13% and NGL volumes decreased by 20%, while natural gas production volumes increased by 13%. Sequentially, production volumes decreased by 13% in the third quarter of 2014 compared to second quarter of 2014 levels as natural gas production volumes decreased by 23% (primarily due to the sale of a 36% interest in our Fasken properties to Saka Energi in July 2014), oil volumes decreased by 2% and NGL volumes increased by 11%.

• Pricing: Our weighted average sales price in the third quarter of 2014decreased by 11% when compared to average price levels in the third quarter of 2013 and sequentially decreased2% when compared to second quarter of 2014 average prices. When compared to pricing in the third quarter of 2013, oil prices in the third quarter of 2014decreased11%, NGL prices increased5% and natural gas prices increased13%. Sequentially over the past quarter, oil prices decreased5%, NGL prices decreased2% and natural gas prices decreased15%.

• Revenues and net income: Our 2014 third quarter revenues of $138.8 million decreased 8% compared to $150.9 million for the third quarter of 2013 and sequentially decreased 11% compared to the $156.0 million of total revenues in the second quarter of 2014. Net income of $2.5 million for the third quarter of 2014 decreased from net income of $7.4 million for the third quarter of 2013 and $6.8 million in the second quarter of 2014.

• Expenses and tightening of service and supply costs: Our expenses in the third quarter of 2014decreased$4.6 million, or 3%, compared to those in the third quarter of 2013 and sequentially decreased $10.9 million, or 8%, compared to expenses in the second quarter of 2014. We have seen some tightening in the availability of services and supplies including some upward pressure on service costs, but we believe that these costs could potentially decrease from current levels if the recent decline in oil prices continues.

Liquidity and Capital Resources

• Outstanding bank borrowings: At September 30, 2014, we had $202.0 million in outstanding borrowings under our credit facility. As of October 17, 2014, our borrowing base and commitment amount were reaffirmed at $417.6 million after being automatically reduced from $450.0 million effective July 15, 2014, due to the Saka Energi transaction. The proceeds of approximately $147 million received at closing were immediately used to pay down our outstanding borrowing under the credit facility, with additional borrowings against the credit facility during the quarter to fund development activities.

24

• 2014 capital expenditures:Our capital expenditures on a cash flow basis were $317.0 million in the first nine months of 2014, compared to $435.7 million in the first nine months of 2013. The expenditures were devoted to drilling and completion activity in our South Texas core region as we drilled 16 wells in our AWP Eagle Ford field and 12 wells in our Fasken field during the year. These expenditures were funded by $252.2 million of cash provided by operating activities along with borrowings under our credit facility and proceeds from the Saka Energi transaction.

• Net cash provided by operating activities: For the first nine months of 2014, our net cash provided by operating activities was $252.2 million, representing a $26.6 million or 12%increase, compared to $225.6 million generated during the same period of 2013, primarily due to working capital changes.

• Working capital and debt to capitalization ratio: Our working capital increased from a deficit of $83.5 million at December 31, 2013, to a deficit of $50.9 million at September 30, 2014. Working capital, which is calculated as current assets less current liabilities, can be used to measure both a company's operational efficiency and short-term financial health. The Company uses this measure to track its short-term financial position. Our working capital ratio does not include available liquidity through our credit facility. Our debt to capitalization ratio was 50% at September 30, 2014 and 52% at December 31, 2013.

Competitive Advantages

• Enhancing Eagle Ford asset value through operating improvements and completion technology: Our South Texas drilling activities continue to benefit from optimized well design as we are drilling longer laterals in our horizontal wells and performing more frac stages per well. We are using proprietary 3D seismic techniques to identify a narrow high quality interval of the lower Eagle Ford within which to steer our laterals, resulting in marked improvement in our well results. Before completion operations commence, we conduct GEOFRAC logging of the horizontal well bore, which has led to more effective placement of frac stages and has also assisted in identifying sections of rock that are ideal for stimulation. These techniques have been effectively deployed in wells drilled in our Fasken and North AWP areas as well as the joint venture area in the central portion of AWP, proving the transferability of this technology. We have observed that longer laterals with additional frac stages and more intense treatment of each stage have resulted in improved rates of return of our Eagle Ford horizontal wells when comparing results using normalized oil and gas prices. Our current process allowed us to drill a well in our Fasken area during the third quarter with a lateral of approximately 7,500 feet and over 20 frac stages. We believe the successful extension of lateral lengths, increased number of frac stages and engineered spacing of these stages will result in further improvements in our economic returns across our acreage.

• Improved value of Eagle Ford shale assets through reductions in per well costs:We have seen improved performance this year in our initial production (IP) rates for Eagle Ford wells and have also seen our per well drilling costs come down from those experienced in the prior year. For the nine months ended September 2014, our average drilling cost per well decreased to $3.1 million from $4.0 million during the prior year, even though our drilling cost per well included an average of approximately 650 more feet of lateral per well in the current year. We have also experienced efficiency gains in our hydraulic fracturing activities, lowering the overall frac cost per stage while achieving better overall results as measured by rates of return and net present value. For the nine months ended September 2014, our average per well completion cost decreased to $4.0 million from $4.2 million during the prior year, even though we are performing an average of two more frac stages per well and using approximately 270 more pounds of proppant, per lateral foot, in each stimulated stage. We believe progression along this technology learning curve is important to improving performance and reducing costs and represents a competitive, transferable skill set we can use across all of our South Texas acreage.

• Ability to capitalize on increased commodity prices in the future:Current natural gas prices are lower than historical highs but have improved from the low prices seen in recent periods. With increasing demand, including the volume of LNG export capacity increasing over the next several years, we believe natural gas prices will increase from current levels and that selected natural gas properties can be economically developed in today’s market, although much of the potential for natural gas development will require higher prices. Our Fasken properties in Webb County, which include some of the best Eagle Ford rock in South Texas as defined by porosity, total organic content and other geologic and petrophysical qualities, can be economically developed today, while areas such as our South AWP area in McMullen County may require a higher price environment to provide adequate economic returns. Our strategy includes a balanced approach to oil and natural gas, and we plan to continue development on our prolific natural gas properties, such as Fasken, along with development in economic liquids-rich areas as commodity prices improve.

25

Results of Operations

Revenues — Three Months Ended September 30, 2014 and 2013

Our oil and gas sales in the third quarter of 2014decreased by 12% compared to oil and gas sales in the third quarter of 2013, primarily due to lower oil production and prices, partially offset by higher natural gas production. Average oil prices we received were 11%lower than those received during the third quarter of 2013, while natural gas prices were 13% higher and NGL prices were 5% higher.

Crude oil production was 29% and 33% of our production volumes in the third quarters of 2014 and 2013, respectively. Crude oil sales were 62% and 70% of oil and gas sales in the third quarters of 2014 and 2013, respectively. Natural gas production was 55% and 48% of our production volumes in the third quarters of 2014 and 2013, respectively. Natural gas sales were 26% and 18% of oil and gas sales in the third quarters of 2014 and 2013, respectively. The remaining production and sales in each period came from NGLs.

The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, for the three months ended September 30, 2014 and 2013:

Core Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MBoe)
	2014		2013		2014	2013
Southeast Louisiana	$	30.5	$	43.9	351	438
South Texas	93.0		94.7		2,468	2,358
Central Louisiana	10.0		13.4		166	247
Other	0.4		1.0		9	14
Total	$	133.9	$	153.0	2,994	3,057

In the third quarter of 2014, our $19.1 million, or 12% decrease in oil, NGL, and natural gas sales resulted from:

• Price variances that had an approximate $6.0 million unfavorable impact on sales due to lower oil prices partially offset by increased natural gas and NGL prices; and

• Volume variances resulted in an approximate decrease of $13 million primarily attributable to lower oil production.

The following table provides additional information regarding our quarterly oil and gas sales, excluding any effects of our hedging activities, for the three months ended September 30, 2014 and 2013:

	Production Volume				Average Price (1)
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
Three Months Ended September 30, 2014	870	482	9.9	2,994	$	96.12	$	33.39	$	3.55
Three Months Ended September 30, 2013	1,004	600	8.7	3,057	$	108.17	$	31.67	$	3.15

(1) As described in Note 1A to the consolidated financial statements, adjustments for certain previously identified immaterial accounting errors have been

made in this Form 10-Q. Any effect on the historical unit sales prices were evaluated and deemed to be immaterial to any period presented and therefore

not restated.

For the three months ended September 30, 2014 and 2013, we recorded total net gains (losses) of $5.0 million and ($2.0 million), respectively, related 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 amounts been recognized in the oil and gas sales account, our average oil price would have been $97.81 and $106.32 for the third quarters of 2014 and 2013, respectively, and our average natural gas price would have been $3.91 and $3.14 for the third quarters of 2014 and 2013, respectively.

26

Costs and Expenses — Three Months Ended September 30, 2014 and 2013

Our expenses in the third quarter of 2014decreased$4.6 million, or 3%, compared to those in the third quarter of 2013, for the reasons noted below.

Lease operating cost. These expenses decreased$1.0 million, or 4%, compared to the level of such expenses in the third quarter of 2013. Lease operating costs decreased by $1.2 million, while workover expenses increased by $0.2 million. Our lease operating costs per Boe produced were $7.37 and $7.55 for the three months ended September 30, 2014 and 2013, respectively.

Transportation and gas processing. These expenses decreased$0.7 million, or 12%, compared to the level of such expenses in the third quarter of 2013, as our production mix shifted towards increased natural gas production. Our transportation and gas processing costs per Boe produced were $1.71 and $1.89 for the third quarters of 2014 and 2013, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses decreased$1.9 million, or 3% from those in the third quarter of 2013. The decrease was primarily due to decreased production and a lower per unit rate. Our DD&A rate per Boe of production was $21.82 and $22.01 in the third quarters of 2014 and 2013, respectively.

General and Administrative Expenses, Net. These expenses decreased$0.2 million, or 1%, from the level of such expenses in the third quarter of 2013. The decrease was primarily due to lower salaries and burdens and lower deferred compensation, partially offset by higher legal fees associated with the Saka Energi transaction and lower capitalized amounts. Our net general and administrative expenses per Boe produced increased to $3.67 per Boe in the third quarter of 2014 from $3.65 per Boe in the third quarter of 2013.

Severance and Other Taxes. These expenses decreased$1.5 million, or 13%, from third quarter 2013 levels. Severance and other taxes, as a percentage of oil and gas sales, were approximately 7.6% and 7.6% in the third quarters of 2014 and 2013, respectively.

Interest. Our gross interest cost in the third quarter of 2014 was $19.4 million, of which $1.2 million was capitalized. Our gross interest cost in the third quarter of 2013 was $19.3 million, of which $1.8 million was capitalized. The decrease in the capitalized interest amount is due to a lower unproved properties balance.

Income Taxes. Our effective income tax rate increased to 54.8% from 43.3% for the third quarters of 2014 and 2013, respectively. The permanent tax differences had a larger impact on the income tax rate for the third quarter of 2014 as our income from continuing operations decreased when compared to the prior quarter.

Revenues — Nine Months Ended September 30, 2014 and 2013

Our oil and gas sales for the first nine months of 2014 were consistent with oil and gas sales in the first nine months of 2013, primarily due to higher natural gas pricing and production, offset by lower oil pricing and production. Average oil prices we received were 7%lower than those received during the first nine months of 2013, while natural gas prices were 20%higher and NGL prices were 13%higher.

Crude oil production was 29% and 34% of our production volumes in the nine months ended September 30, 2014 and 2013, respectively. Crude oil sales were 60% and 70% of oil and gas sales in the nine months ended September 30, 2014 and 2013, respectively. Natural gas production was 56% and 47% of our production volumes in the nine months ended September 30, 2014 and 2013, respectively. Natural gas sales were 29% and 18% of oil and gas sales in the nine months ended September 30, 2014 and 2013, respectively. The remaining production and sales in each period came from NGLs.

27

The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, for the nine months ended September 30, 2014 and 2013:

Core Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MBoe)
	2014		2013		2014	2013
Southeast Louisiana	$	101.8	$	131.8	1,119	1,346
South Texas	305.9		266.0		7,733	6,586
Central Louisiana	32.4		42.5		509	689
Other	1.4		1.7		26	33
Total	$	441.5	$	442.0	9,387	8,654

During the first nine months of 2014, our oil and gas sales decreased slightly by $0.5 million. The impact of lower oil prices and lower production was essentially offset by increases in both gas prices and gas production.

The following table provides additional information regarding our quarterly oil and gas sales, excluding any effects of our hedging activities, for the nine months ended September 30, 2014 and 2013:

	Production Volume				Average Price (1)
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
Nine Months Ended September 30, 2014	2,691	1,395	31.8	9,387	$	99.08	$	34.55	$	3.98
Nine Months Ended September 30, 2013	2,903	1,705	24.3	8,654	$	106.69	$	30.48	$	3.32

(1) As described in Note 1A to the consolidated financial statements, adjustments for certain previously identified immaterial accounting errors have been

made in this Form 10-K/A. Any effect on the historical unit sales prices were evaluated and deemed to be immaterial to any period presented and therefore

not restated.

For the nine months ended September 30, 2014 and 2013, we recorded total net gains (losses) of $2.7 million and ($0.8 million), respectively, related to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. Hadtheseamounts been recognized in the oil and gas sales account, our average oil price would have been $98.80 and $105.94 for the nine months ended September 30, 2014 and 2013, respectively, and our average natural gas price would have been $3.92 and $3.38 for the nine months ended September 30, 2014 and 2013, respectively.

Costs and Expenses — Nine Months Ended September 30, 2014 and 2013

Our expenses for the first nine months of 2014increased$6.9 million, or 2%, compared to those in the first nine months of 2013, for the reasons noted below.

Lease operating cost. These expenses decreased$6.3 million, or 8%, compared to the level of such expenses in the first nine months of 2013, as our cost savings initiatives are being realized and due to the one-time costs associated with a well control incident in Lake Washington during the first half of 2013. Our lease operating costs per Boe produced were $7.52 and $8.89 for the nine months ended September 30, 2014 and 2013, respectively.

Transportation and gas processing. These expenses increased$1.0 million, or 7%, compared to the level of such expenses in the first nine months of 2013, as our production mix shifted towards increased natural gas production. Our transportation and gas processing costs per Boe produced were $1.75 and $1.78 for the nine months ended September 30, 2014 and 2013, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses increased$13.6 million, or 7% from those in the first nine months of 2013. The increase was primarily due to higher production. Our DD&A rate per Boe of production improved to $21.42 for the nine months ended September 30, 2014, as compared to $21.67 for the nine months ended September 30, 2013.

General and Administrative Expenses, Net. These expenses decreased$1.5 million, or 4%, from the level of such expenses in the first nine months of 2013. The decrease was primarily due to lower salaries and lower deferred compensation, partially

28

offset by lower capitalized amounts and higher legal and professional fees related to the Saka Energi transaction. Our net general and administrative expenses per Boe produced decreased to $3.58 per Boe in the first nine months of 2014 from $4.05 per Boe in the first nine months of 2013.

Severance and Other Taxes. These expenses decreased$3.4 million, or 11%, from first nine months of 2013 levels. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.5% and 7.3% in the nine months ended September 30, 2014 and 2013, respectively. The decrease in the rate was primarily driven by higher production in South Texas which carries a lower severance tax rate than Louisiana.

Interest. Our gross interest cost in the first nine months of 2014 was $59.0 million, of which $3.7 million was capitalized. Our gross interest cost in the first nine months of 2013 was $56.9 million, of which $5.6 million was capitalized. The increase in gross interest came primarily from additional borrowings on our credit facility while the decrease in capitalized interest was due to a lower unproved properties balance.

Income Taxes. Our effective income tax rate was 49.1% and 39.9% for the nine months ended September 30, 2014 and 2013, respectively. This increase in rate related to a shortfall between the tax deduction received with respect to prior restricted stock grants that vested during the year versus the actual book expense recorded over the life of those grants.

Contractual Commitments and Obligations

Additional Commitments in 2014. During 2014, the Company entered into additional gas transportation agreements. As of September 30, 2014, the minimum commitments under these agreements total approximately $36.3 million as follows: 2015 - $6.5 million, 2016 - $7.0 million, 2017 - $7.0 million, 2018 - $6.5 million and $9.3 million thereafter. We had no other material changes in our contractual commitments and obligations from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis in our Annual Report on Form 10-K/A for the year ending December 31, 2013.

Critical Accounting Policies and New Accounting Pronouncements

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 including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. 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.

The costs of unproved properties not being amortized are 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. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of unproved properties. For both reserves estimates (see discussion below) and the impairment of unproved properties (see discussion above), these processes are subjective, and results may change over time based on current information and industry conditions. 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.

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 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 price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).

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.

29

Given the volatility of oil and natural gas prices, it is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the future and that non-cash write-downs of oil and natural gas properties could occur in the future. For example, if future capital expenditures out pace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, non-cash write-downs of our oil and natural gas properties could occur in the future. We cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09 which provides a single, comprehensive revenue recognition model for all contracts with customers across various industries. The guidance is effective for annual and interim reporting periods beginning after December 15, 2016. We plan to review and assess the effect and implement any necessary requirements as needed.

30

Forward-Looking Statements

This report includes forward-looking statements intended to qualify for the safe harbors from liability established by the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated production levels, reserve increases, capital expenditures, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words "could," "believe," "anticipate," "intend," "estimate," “budgeted”, "expect," "may," continue," "predict," "potential," "project" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Forward-looking statements may include statements about our:

• oil and natural gas pricing expectations;

• the amount, nature and timing of capital expenditures, including future development costs;

• timing and amount of future production of oil and natural gas

• business strategy, financial strategy, budget, projections and operating results;

• estimated oil and natural gas reserves or the present value thereof;

• technology;

• our borrowing capacity, cash flows and liquidity;

• asset disposition efforts, future repayments of our debt, or the timing or outcome thereof;

• prospective joint ventures, their structure and substance, and the likelihood of their finalization or the timing thereof;

• availability of drilling and production equipment or availability of oil field labor;

• availability and terms of capital;

• drilling of wells;

• marketing and transportation of oil and natural gas;

• costs of exploiting and developing our properties and conducting other operations;

• competition in the oil and natural gas industry;

• general economic conditions;

• opportunities to monetize assets;

• effectiveness of our risk management activities;

• environmental liabilities;

• counterparty credit risk;

• governmental regulation and taxation of the oil and natural gas industry;

• developments in world oil markets and in oil and natural gas-producing countries;

• uncertainty regarding our future operating results;

• plans, objectives, expectations and intentions contained in this report that are not historical.

All forward-looking statements speak only as of the date they are made. You should not place undue reliance on these forward-looking statements. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved. We disclose important factors that could cause our actual results to differ materially from our expectations under "Risk factors" in Item 1A of our annual report on Form 10-K/A for the year ended December 31, 2013. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

All subsequent written and oral forward-looking statements attributable to us or to persons acting on our behalf are expressly qualified in their entirety by the foregoing. We undertake no obligation to publicly release the results of any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this report or to reflect the occurrence of unanticipated events.

31

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. This commodity pricing volatility has continued with unpredictable price swings throughout 2013 and into 2014.

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. For additional discussion related to our price-risk management policy, refer to Note 2 of these condensed consolidated financial statements.

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 and 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.

Concentration of Sales Risk. Over the last several years, a large portion of our oil and gas sales have been to Shell Oil Corporation and affiliates and we expect to continue this relationship in the future. We believe that the risk of these unsecured receivables is mitigated by the short-term sales agreements we have in place as well as the size, reputation and nature of their business.

Interest Rate Risk. Our senior notes due in 2017, 2020 and 2022 have fixed interest rates, so consequently we are not exposed to cash flow risk from market interest rate changes on these notes. At September 30, 2014, we had $202.0 million drawn 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 future cash flows.

32

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.

Management has determined that a deficiency in internal control over financial reporting exists related to the review of the full-cost ceiling test write-down calculation. The deficiency specifically relates to the deferred income tax effects attributable to the Company’s asset retirement obligations. Management has also concluded that this deficiency is a material weakness, as defined by Securities and Exchange Commission regulations, and that our disclosure controls and procedures were not effective as of September 30, 2014 as a result of the material weakness in our internal control over financial reporting as discussed in the Preliminary Note.

In light of the material weakness referred to above, we performed additional analyses and procedures in order to conclude that our condensed consolidated financial statements in this Form 10-Q for the quarters ended September 30, 2014 and 2013 are fairly presented, in all material respects, in accordance with US GAAP.

Remediation Plan

We are remediating this material weakness by, among other things, implementing a process of enhanced review of the non-cash ceiling test calculation at September 30, 2014. The actions that we are taking are subject to ongoing senior management review and Audit Committee oversight. Management believes the foregoing efforts will effectively remediate the material weakness in the fourth quarter of 2014. As we continue to evaluate and work to improve our internal control over financial reporting, management may execute additional measures to address potential control deficiencies or modify the remediation plan described above and will continue to review and make necessary changes to the overall design of our internal controls.

Changes in Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the first nine months of 2014 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting, except as noted above related to the full-cost ceiling test write-down calculation.

33

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 2013 Annual Report on Form 10-K/A.

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

The following table summarizes repurchases of our common stock occurring during the third quarter of 2014:

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)
07/01/14 – 07/31/14 (1)	—	$	—	—	$	—
08/01/14 – 08/31/14 (1)	3,598	$	11.94	—	—
09/01/14 – 09/30/14 (1)	1,484	$	10.28	—	—
Total	5,082	$	11.46	—	$	—
(1) These shares were withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

Item 6. Exhibits.

10.1*	Acquisition Agreement by and between Swift Energy Operating, LLC and Saka Energi Fasken, LLC executed May 5, 2014, but effective July 15, 2014.
10.2*	Fourth Amendment and Consent to Second Amended and Restated Credit Agreement effective as of April 30, 2014, among Swift Energy Company, Swift Energy Operating, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto.
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.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith

34

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:	November 17, 2014	By:	/s/ Alton D. Heckaman, Jr.
			Alton D. Heckaman, Jr. Executive Vice President Chief Financial Officer and Principal Accounting Officer

35

Exhibit Index

10.1*	Acquisition Agreement by and between Swift Energy Operating, LLC and Saka Energi Fasken, LLC executed May 5, 2014, but effective July 15, 2014.
10.2*	Fourth Amendment and Consent to Second Amended and Restated Credit Agreement effective as of April 30, 2014, among Swift Energy Company, Swift Energy Operating, LLC, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto.
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.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith

36

EX-10.1

EXHIBIT 10.1

ACQUISITION AGREEMENT BY AND BETWEEN

SWIFT ENERGY OPERATING, LLC

AND

SAKA ENERGI FASKEN LLC

EXECUTED ON MAY 5, 2014

TABLE OF CONTENTS

Page

ARTICLE IDEFINITIONS AND INTERPRETATION ......................................................1

1.1Defined Terms ...................................................................................................1

1.2References and Rules of Construction ...............................................................1

ARTICLE IIASSET ACQUISITION.....................................................................................2

2.1Asset Acquisition ...............................................................................................2

2.2Excluded Assets .................................................................................................3

2.3Revenues and Expenses .....................................................................................3

ARTICLE IIICONSIDERATION ...........................................................................................4

3.1Consideration .....................................................................................................4

3.2Deposit ...............................................................................................................4

3.3Adjustments to Closing Cash Amount...............................................................5

3.4Preliminary Settlement Statement......................................................................6

3.5Final Settlement Statement ................................................................................6

3.6Disputes..............................................................................................................7

3.7Allocated Values ................................................................................................8

ARTICLE IVACCESS / DISCLAIMERS...............................................................................8

4.1Access ................................................................................................................8

4.2Confidentiality .................................................................................................10

4.3Disclaimers ......................................................................................................10

ARTICLE VTITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS ............12

5.1General Disclaimer of Title Warranties and Representations..........................12

5.2Special Warranty..............................................................................................12

5.3Notice of Title Defects; Defect Adjustments ...................................................12

5.4Casualty or Condemnation Loss ......................................................................16

5.5Preferential Purchase Rights and Consents to Assign .....................................17

ARTICLE VIENVIRONMENTAL MATTERS ...................................................................19

6.1Environmental Defects.....................................................................................19

6.2NORM, Wastes and Other Substances ............................................................22

ARTICLE VII REPRESENTATIONS AND WARRANTIES OF SELLER ..........................23

7.1Organization, Existence ...................................................................................23

7.2Authorization ...................................................................................................23

7.3No Conflicts .....................................................................................................23

7.4Consents ...........................................................................................................23

7.5Bankruptcy .......................................................................................................23

7.6Foreign Person .................................................................................................24

7.7Litigation ..........................................................................................................24

7.8Material Contracts............................................................................................24

7.9No Violation of Laws.......................................................................................25

TABLE OF CONTENTS

(continued)

Page

7.10Preferential Rights ...........................................................................................25

7.11Imbalances .......................................................................................................25

7.12Current Commitments......................................................................................25

7.13Asset Taxes ......................................................................................................26

7.14Brokers’ Fees ...................................................................................................26

7.15Advance Payments ...........................................................................................26

7.16Partnerships ......................................................................................................26

7.17Suspense Funds ................................................................................................26

7.18Payout ..............................................................................................................26

7.19Leases...............................................................................................................26

7.20Payment of Royalties and Rentals ...................................................................26

7.21Plugging and Abandonment.............................................................................27

7.22Casualty or Condemnation Loss ......................................................................27

7.23Operations ........................................................................................................27

7.24Reserved Interests ............................................................................................27

7.25Environmental Matters.....................................................................................27

7.26Affiliate Contracts............................................................................................28

7.27Rights of Way ..................................................................................................28

7.28Personal Property .............................................................................................28

7.29Joint Accounts..................................................................................................28

ARTICLE VIII REPRESENTATIONS AND WARRANTIES OF BUYER .........................28

8.1Organization; Existence ...................................................................................29

8.2Authorization ...................................................................................................29

8.3No Conflicts .....................................................................................................29

8.4Consents ...........................................................................................................29

8.5Bankruptcy .......................................................................................................29

8.6Litigation ..........................................................................................................29

8.7Regulatory........................................................................................................29

8.8Financing..........................................................................................................30

8.9Independent Evaluation ...................................................................................30

8.10Brokers’ Fees ...................................................................................................30

8.11Accredited Investor ..........................................................................................30

ARTICLE IXCERTAIN AGREEMENTS ............................................................................30

9.1Conduct of Business ........................................................................................30

9.2Notifications.....................................................................................................32

9.3Amendments to Schedules ...............................................................................32

9.4Non-Solicitation of Employees ........................................................................32

9.5Additional Interests ..........................................................................................33

9.6Governmental Approvals .................................................................................33

ARTICLE XBUYER’S CONDITIONS TO CLOSING ......................................................34

TABLE OF CONTENTS

(continued)

Page

10.1Representations ................................................................................................33

10.2Performance .....................................................................................................34

10.3No Legal Proceedings ......................................................................................34

10.4Title Defects and Environmental Defects ........................................................34

10.5Certificate.........................................................................................................34

10.6Closing Deliverables ........................................................................................34

10.7CFIUS ..............................................................................................................34

ARTICLE XISELLER’S CONDITIONS TO CLOSING .....................................................34

11.1Representations ................................................................................................34

11.2Performance .....................................................................................................35

11.3No Legal Proceedings ......................................................................................35

11.4Title Defects and Environmental Defects ........................................................35

11.5Certificate.........................................................................................................35

11.6Closing Deliverables ........................................................................................35

11.7CFIUS ..............................................................................................................35

ARTICLE XIICLOSING ........................................................................................................35

12.1Date of Closing ................................................................................................35

12.2Place of Closing ...............................................................................................35

12.3Closing Obligations .........................................................................................36

12.4Records ............................................................................................................37

ARTICLE XIIIASSUMPTION; INDEMNIFICATION; SURVIVAL....................................37

13.1Assumption by Buyer ......................................................................................37

13.2Indemnities of Seller ........................................................................................38

13.3Indemnities of Buyer........................................................................................39

13.4Limitation on Liability .....................................................................................39

13.6Exclusive Remedy ...........................................................................................40

13.7Indemnification Procedures .............................................................................40

13.8Survival ............................................................................................................42

13.9Non-Compensatory Damages ..........................................................................42

13.10Waiver of Right to Rescission .........................................................................43

13.11Insurance, Taxes ..............................................................................................43

ARTICLE XIVTERMINATION, DEFAULT AND REMEDIES ...........................................43

14.1Right of Termination........................................................................................43

14.2Effect of Termination.......................................................................................44

14.3Return of Documentation and Confidentiality.................................................45

ARTICLE XVMISCELLANEOUS ........................................................................................45

15.1Appendices, Exhibits and Schedules ...............................................................45

15.2Expenses and Taxes .........................................................................................45

15.3Tax Treatment ..................................................................................................46

TABLE OF CONTENTS

(continued)

Page

15.4Value Allocations for Tax Purposes ................................................................47

15.5Assignment ......................................................................................................47

15.6Preparation of Agreement ................................................................................48

15.7Publicity ...........................................................................................................48

15.8Notices .............................................................................................................48

15.9Further Cooperation .........................................................................................50

15.10Filings ..............................................................................................................50

15.12Entire Agreement; Non-Reliance; Conflicts ....................................................50

15.13Successors and Permitted Assigns ...................................................................51

15.14Parties in Interest..............................................................................................51

15.15Amendment......................................................................................................51

15.16Waiver; Rights Cumulative..............................................................................51

15.17Governing Law; Jurisdiction; Venue; Jury Waiver .........................................52

15.18Severability ......................................................................................................52

15.19Counterparts .....................................................................................................52

15.20Specific Performance .......................................................................................52

15.21Accounting for Conveyed Interests .................................................................52

LIST OF APPENDICES, EXHIBITS AND SCHEDULES

Appendices

Appendix I¯Definitions

Exhibits

Exhibit A	¯	Leases
Exhibit B	¯	Wells and Allocated Values
Exhibit C	¯	Personal Property
Exhibit D	¯	Development Area
Exhibit E	¯	Form of Tax Partnership Agreement
Exhibit F	¯	Form of Assignment and Bill of Sale
Exhibit G	¯	Excluded Assets
Exhibit H	¯	Form of Development Agreement
Exhibit I	¯	Form of Parent Guaranty
Exhibit J	¯	Title Defect Exceptions
Exhibit K	¯	Applicable Contracts
Exhibit L	¯	2014 Work Program and Budget

Schedules
Schedule 2.1	¯	Geophysical/Seismic Data
Schedule 4.1(f)	¯	Insurance
Schedule 7.3	¯	No Conflicts
Schedule 7.4	¯	Seller Consents
Schedule 7.7	¯	Litigation
Schedule 7.8	¯	Material Contracts
Schedule 7.9	¯	Violation of Laws
Schedule 7.10	¯	Preferential Rights
Schedule 7.12	¯	Current Commitments
Schedule 7.13	¯	Asset Taxes
Schedule 7.17	¯	Suspense Funds
Schedule 7.18	¯	Payout Balances
Schedule 7.25	¯	Environmental Matters
Schedule 7.26	¯	Affiliate Contracts
Schedule 8.4	¯	Buyer Consents
Schedule 9.1	¯	Conduct of Business

ACQUISITION AGREEMENT

THIS ACQUISITION AGREEMENT (as the same may be amended, restated, supplemented or otherwise modified from time to time, this “Agreement”) is entered into this 5th day of May, 2014 (the “Execution Date”), between Swift Energy Operating, LLC, a Texas limited liability company (“Seller”), and Saka Energi Fasken LLC, a Texas limited liability company (“Buyer”). Buyer and Seller are sometimes referred to herein together as the “Parties” or individually as a “Party”.

Recitals

Seller and Buyer desire to enter into an arrangement for the exploration, development and operation of certain oil and gas properties located in the State of Texas as hereinafter described, and in connection therewith Seller desires to transfer to Buyer, and Buyer desires to acquire from Seller, a portion of Seller’s right, title and interest in and to such properties and related interests in accordance with this Agreement; and

The transfer of the Conveyed Interests and the Parties’ agreement regarding the exploration, development and operation of the Development Assets will be consummated on the terms and conditions set forth in this Agreement and the Development Agreement, each of which is an integral part of a single transaction.

NOW, THEREFORE, for and in consideration of the mutual agreements herein contained, the benefits to be derived by each Party, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereby agree as follows:

ARTICLE I

DEFINITIONS AND INTERPRETATION

1.1 Defined Terms. Capitalized terms used herein and not otherwise defined have the meanings given such terms in Appendix I.

1.2 References and Rules of Construction. All references in this Agreement to Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions refer to the corresponding Exhibits, Appendices, Schedules, Articles, Sections, subsections and other subdivisions of or to this Agreement unless expressly provided otherwise. Titles appearing at the beginning of any Articles, Sections, subsections and other subdivisions of this Agreement are for convenience only, do not constitute any part of this Agreement, and will be disregarded in construing the language hereof. The words “this Agreement,” “herein,” “hereby,” “hereunder” and “hereof,” and words of similar import, refer to this Agreement as a whole and not to any particular Article, Section, subsection or other subdivision unless expressly so limited. The word “including” (in its various forms) means including without limitation. All references to “$” or “dollars” will be deemed references to United States dollars. Each accounting term not defined herein, and each accounting term partly defined herein to the extent not defined, will have the meaning given to it under GAAP as interpreted as of the Execution Date. Pronouns in masculine, feminine or neuter genders will be construed to state and include any other gender, and words, terms and titles (including terms defined herein) in the singular form will be

construed to include the plural and vice versa, unless the context otherwise requires. References to any Law or agreement will mean such Law or agreement as it may be amended from time to time. References to any date will mean such date in Houston, Texas and for purposes of calculating the time period in which any notice or action is to be given or undertaken hereunder, such period will be deemed to begin at 12:01 A.M. on the applicable date in Houston, Texas.

ARTICLE II

ASSET ACQUISITION

2.1 Asset Acquisition. Subject to the terms and conditions of this Agreement, Seller agrees to sell, assign, transfer, and convey to Buyer, and Buyer agrees to purchase, receive, acquire, and pay for the following interests and properties (less and except the Excluded Assets, such interests and properties described in subsections (a) and (b) of this Section 2.1, collectively, the “Conveyed Interests”):

(a)an undivided 36% of Seller’s right, title and interest in and to the

following assets and properties:

(i) the oil, gas and/or mineral leases described in Exhibit A, subject to any depth limitations described therein (Seller’s interests in such leases and other interests as so limited, the “Leases”), and all rights, titles and interests of Seller in and to any units arising on account of any of the Leases having been pooled or unitized into such units (Seller’s interests in such units, the “Units”);

(ii) all wells (including oil and gas wells, water wells, carbon dioxide wells, salt water disposal wells, injection wells and any other wells and wellbores) located on the Leases or the Units, including the wells set forth on Exhibit B (Seller’s interests in such wells and all other wells located on the Leases or Units being collectively referred to hereinafter as the “Wells”), and all Hydrocarbons produced therefrom or allocated thereto (the Leases, the Units and the Wells being collectively referred to hereinafter as the “Properties” or individually as a “Property”);

(iii) the surface agreements or surface leases, easement agreements and right-of-way agreements (if any) used or held for use primarily in connection with the Properties (collectively such interests, the “Rights of Way”);

(iv) all equipment, machinery, fixtures, improvements and other personal property, operational or nonoperational, known or unknown, that is used or held for use primarily in connection with the Properties or the other Conveyed Interests, including those items listed on Exhibit C, and including well equipment, casing, tubing, pumps, motors, machinery, platforms, rods, tanks, boilers, fixtures, compression equipment, flowlines, pipelines, gathering systems associated with the Wells, manifolds, processing and separation facilities, structures and other similar items used or held for use primarily in connection with the Subject Oil and Gas Assets (Seller’s interest in such properties, the “Personal Property”); and

(v) all of the Contracts set forth on Exhibit K (the “Applicable Contracts”), and all rights and obligations thereunder, but only to the extent that such rights and obligations relate to the Properties, Rights of Way or Personal Property.

(b) an undivided 36% of Seller’s right, title and interest in and to the following assets and properties to the extent, and only to the extent, that such assets and properties relate to the interests described in subsection (a) above:

(i) copies (in digital form, if available) of the following, to the extent they are in Seller’s or its Affiliates’ possession: (A) land and title records (including abstracts of title, title opinions and title curative documents); (B) contract files; (C) correspondence; (D) operations, environmental, production and accounting and Asset Tax records; and (E) production, facility and well files, records and data (including logs and cores), but excluding any of the foregoing items that are Excluded Assets (the “Records”);

(ii) to the extent assignable without payment of fees or other penalties, all geophysical and other seismic and related technical data and information and all interpretative data in connection therewith, including the data and information listed on Schedule 2.1;

(iii) all rights, claims and causes of action (including claims for adjustments or refunds) to the extent attributable to: (A) the Conveyed Interests; and (B) any of the Assumed Obligations; and

(iv) all Hydrocarbons which may be produced from or allocable to the Subject Oil and Gas Assets with respect to periods on or after the Effective Time, together with all proceeds from or of such Hydrocarbons and all Hydrocarbons in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time.

2.2Excluded Assets. Seller reserves and retains all of the Excluded Assets.

2.3Revenues and Expenses.

(a) For purposes of determining the amount of the adjustment to the Closing Cash Amount provided for in Section 3.3, the principles set forth in this Section 2.3 will apply. Except as expressly provided otherwise in this Agreement, Seller will remain entitled to all of the rights of ownership (including the right to all production, proceeds of production and other proceeds) and shall remain responsible for all Operating Expenses and other costs or expenses in connection with the Conveyed Interests, in each case attributable to the Conveyed Interests for the period of time prior to the Effective Time. Except as expressly provided otherwise in this Agreement, and subject to the occurrence of the Closing, (i) Buyer will be entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds), and shall be responsible for all Operating Expenses, in each case solely to the extent attributable to the Conveyed Interests beginning with the Effective Time and thereafter, and (ii) Seller will be entitled to all of the rights of ownership (including the right to all production, proceeds of production, and other proceeds), and shall be responsible for all Operating Expenses, in each case attributable to the interests that are retained by Seller in the properties and assets described in Section 2.1 from which the Conveyed Interests are created. Such amounts which are received or paid prior to Closing will be accounted for in the Preliminary Settlement Statement or Final Settlement Statement, as applicable; provided, however, that the Preliminary Settlement Statement may contain estimated amounts. To the extent attributable to periods prior

to the Closing Date, such amounts which are received or paid after Closing but prior to the date of the Final Settlement Statement will be accounted for in the Final Settlement Statement.

(b) Except for such amounts to be paid in accordance with the accounting procedures of any Applicable Operating Agreement (as defined in the Development Agreement), after the Parties’ agreement upon the Final Settlement Statement: (i) if any Party receives monies belonging to the other, including proceeds of production, then such amount shall be paid over to the proper Party within 30 days after the end of the month in which such amounts were received; (ii) if any Party pays monies for Operating Expenses which are the obligation of the other Party hereto, then such other Party shall, within 30 days after the end of the month in which the applicable invoice and proof of payment of such invoice were received, reimburse the Party which paid such Operating Expenses; (iii) if a Party receives an invoice of an expense or obligation which is owed by the other Party, such Party receiving the invoice shall promptly forward such invoice to the Party obligated to pay the same; and (iv) if an invoice or other evidence of an obligation is received by a Party, which is partially an obligation of both Seller and Buyer, then the Parties shall consult with each other, and each shall promptly pay its portion of such obligation to the obligee.

(c) Each of Seller and Buyer will be permitted to offset any Operating Expenses owed by such Party to the other Party pursuant to this Section 2.3 against revenues owing by the second Party to the first Party pursuant to this Section 2.3, but not otherwise.

ARTICLE III

CONSIDERATION

3.1 Consideration. The consideration for: (x) the transfer of the Conveyed Interests and the transactions contemplated hereby; and (y) the assumption of the Assumed Obligations will be comprised of the following components:

(a)An amount equal to: (i) $125,000,000 (the “Closing Cash Amount”) to

be paid in cash at Closing by Buyer;

(b)plus (ii) the Interim Period Carried Costs Amount;

in each case, as adjusted pursuant to this Agreement as and when provided in Section 3.3, and payable in dollars by wire transfer in same day funds, in each case to an account designated by Seller in the Preliminary Settlement Statement; and

(c) Buyer’s entry into, and assumption of its obligations under, the Development Agreement, including the obligation to pay and satisfy the Carried Costs Obligation pursuant to the terms thereof.

3.2Deposit; Guaranty.

(a) Concurrently with the execution of this Agreement, Buyer shall deposit into the Escrow Account by wire transfer in same day funds the sum of $12,500,000 as of the Execution Date (such amount, together with any interest earned thereon, the “Deposit”). If Closing occurs, the Deposit will be applied toward the Closing Cash Amount at Closing. The Deposit otherwise shall be released to Seller or Buyer, as applicable, pursuant to Section 14.2. All fees charged by the Escrow Agent in connection with the Deposit shall be borne fifty percent (50%) by Buyer and fifty percent (50%) by Seller.

(b)Simultaneously with the Parties’ execution of this Agreement, Buyer

Parent delivered the Parent Guaranty to Seller.

3.3 Adjustments to Closing Cash Amount. The Closing Cash Amount will be adjusted as follows (without duplication of any other adjustments or payments hereunder or under the Development Agreement, including any costs and expenses accounted for in the calculation of the Interim Period Carried Costs Amount), and the resulting amount will be herein called the “Adjusted Closing Cash Amount”:

(a)The Closing Cash Amount will be adjusted upward by the following amounts:

(i) an amount equal to the value of all Hydrocarbons attributable to the Conveyed Interests in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time, if any, the value to be based on the price paid to Seller in connection with the sale of such Hydrocarbons during the Interim Period, net of: (A) amounts payable as Burdens on such production and severance taxes deducted by the purchaser of such production; and (B) expenses (other than Operating Expenses) directly incurred in earning or receiving such proceeds and any sale, excise or similar taxes or fees payable or incurred in connection therewith not reimbursed to Seller;

(ii) an amount equal to all Operating Expenses and other costs and expenses directly attributable to the Conveyed Interests (but excluding any Overhead Costs) incurred by Seller during the Interim Period, whether paid before or after the Effective Time, including: (A) Burdens; (B) rentals and other lease maintenance payments; and (C) Asset Taxes prorated to Buyer in accordance with Section 15.2(c) that are paid or payable by Seller and excluding all: (x) Liabilities for which Buyer would be entitled to receive indemnification therefor from Seller pursuant to the terms of this Agreement; and (y) the Interim Period Carried Costs Amount;

(iii)to the extent attributable to the Conveyed Interests, the Overhead Costs; and

(iv)any other amount provided for elsewhere in this Agreement or otherwise agreed upon in writing by Seller and Buyer.

(b)The Closing Cash Amount will be adjusted downward by the following amounts:

(i)if Seller makes the election under Section 5.3(c)(i) with respect to any Title Defect, the Title Defect Amount with respect to each such Title Defect;

(ii)if Seller makes the election under Section 6.1(b)(i) with respect to an Environmental Defect, the Remediation Amount with respect to such Environmental Defect;

(iii) an amount equal to the Allocated Values for any Conveyed Interests excluded from the transaction contemplated hereby pursuant to Section 5.3(c)(ii), Section 6.1(b)(iii) or any other provisions of this Agreement;

(iv) an amount equal to 36% of all proceeds received by Seller attributable to the sale of Hydrocarbons: (A) produced from or allocable to the Conveyed Interests during the Interim Period; or (B) contained in storage or existing in stock tanks, pipelines and/or plants (including inventory) as of the Effective Time for which an upward Closing Cash Amount adjustment was made pursuant to Section 3.3(a)(i), (in each case) net of expenses (other than Operating Expenses) paid by Seller and directly incurred in earning or receiving such proceeds, and any sales, excise or similar taxes or fees payable or incurred in connection therewith not reimbursed to Seller by a Third Party purchaser (collectively, the “Interim Period Revenue Share”);

(v)the amount of all Asset Taxes prorated to Seller in accordance with

Section 15.2(c) that are paid or payable by Buyer; and

(vi)any other amount expressly provided for elsewhere in this

Agreement or otherwise agreed upon in writing by Seller and Buyer.

3.4 Preliminary Settlement Statement. Not less than ten Business Days prior to the Closing, Seller shall prepare and submit to Buyer for review a draft settlement statement (the “Preliminary Settlement Statement”) that sets forth the Interim Period Carried Costs Amount, the Interim Period Revenue Share and the Adjusted Closing Cash Amount reflecting each estimate or adjustment made in accordance with this Agreement as of the date of preparation of such Preliminary Settlement Statement and the calculation of the adjustments used to determine such amount, together with the designation of the account for the wire transfers of funds as set forth in Section 12.3(c). Within five Business Days of receipt of the Preliminary Settlement Statement, Buyer will deliver to Seller a written report containing all changes with the explanation therefor that Buyer proposes to be made to the Preliminary Settlement Statement, if any. The Preliminary Settlement Statement, as agreed upon by the Parties, will be used to adjust the Interim Period Carried Costs Amount, the Interim Period Revenue Share and the Closing Cash Amount, as applicable, at Closing; provided that if the Parties cannot agree on the Preliminary Settlement Statement prior to the Closing, the Preliminary Settlement Statement as presented by Seller will be used to adjust the Interim Period Carried Costs Amount, the Interim Period Revenue Share and the Closing Cash Amount, as applicable, at Closing.

3.5Final Settlement Statement.

(a) On or before 90 days after the Closing, Seller shall deliver to Buyer a final settlement statement (the “Final Settlement Statement”) prepared based on actual revenues and expenses during the Interim Period and which takes into account all final adjustments made to the Interim Period Carried Costs Amount and the Closing Cash Amount, as applicable, and shows the Interim Period Revenue Share, the resulting final Interim Period Carried Costs Amount and the final Adjusted Closing Cash Amount.

(b) Within 30 days after receipt of the Final Settlement Statement, Buyer shall deliver to Seller a written report containing any proposed changes to the Final Settlement Statement and an explanation of any such changes and the reasons therefor (the “Dispute Notice”). Any changes not so specified in the Dispute Notice will be deemed waived and Seller’s determinations with respect to all such elements of the Final Settlement Statement that are not addressed specifically in the Dispute Notice will prevail. If Buyer fails to timely deliver a Dispute Notice to Seller containing changes Buyer proposes to be made to the Final Settlement Statement, the Final Settlement Statement as delivered by Seller will be deemed to be mutually agreed upon by the Parties and will be final and binding on the Parties. If the final Interim Period Carried Costs Amount and the final Adjusted Closing Cash Amount set forth in the Final Settlement Statement is mutually agreed upon by Seller and Buyer, the Final Settlement Statement, the final Interim Period Carried Costs Amount and the final Adjusted Closing Cash Amount will be final and binding on the Parties, subject to the provisions of Section 2.3(b).

(c) If the final Adjusted Closing Cash Amount is: (a) more than the amount of the Adjusted Closing Cash Amount set forth in the Preliminary Settlement Statement used for purposes of the Closing, Buyer shall pay Seller the amount of such excess; or (b) less than the amount of the Adjusted Closing Cash Amount set forth in the Preliminary Settlement Statement used for purposes of the Closing, Seller shall pay Buyer the amount of such difference, in either case, by wire transfers in immediately available funds no later than five Business Days after the date such final Adjusted Closing Cash Amount is agreed (or deemed agreed) pursuant to this Section 3.5.

(d) If the final Interim Period Carried Costs Amount is: (a) more than the Interim Period Carried Costs Amount set forth in the Preliminary Settlement Statement that the Parties used for purposes of Closing, Buyer shall pay Seller the amount of such excess; or (b) less than the Interim Period Carried Costs Amount set forth in the Preliminary Settlement Statement that the Parties used for purposes of Closing, Seller shall pay Buyer the amount of such difference, in either case, by wire transfers in immediately available funds no later than five Business Days after the date such final Interim Period Carried Costs Amount is deemed agreed, pursuant to this Section 3.5.

3.6 Disputes. If Seller and Buyer are unable to resolve the matters addressed in the Dispute Notice (if any), each of Buyer and Seller shall within 14 Business Days after the delivery of such Dispute Notice, summarize its position with regard to such dispute in a written document of 20 pages or less and submit such summaries to the Houston, Texas office of a mutually agreed accounting arbitrator (the “Accounting Arbitrator”), together with the Dispute Notice, the Final Settlement Statement and any other documentation such Party may desire to submit. Within 20 Business Days after receiving the Parties’ respective submissions, the Accounting Arbitrator shall render a decision choosing either Seller’s position or Buyer’s position with respect to each matter addressed in any Dispute Notice, based on the materials described above. Any decision rendered by the Accounting Arbitrator pursuant hereto will be final, conclusive and binding on Seller and Buyer and will be enforceable against any of the Parties in any court of competent jurisdiction. Each Party shall bear one-half of the costs of the Accounting Arbitrator. The Final Settlement Statement, the final Adjusted Closing Cash Amount, final Interim Period Revenue

Share and the final Interim Period Carried Costs Amount determined by the Accounting Arbitrator pursuant to this Section 3.6 will be final and binding on

the Parties (other than with respect to amounts not accounted for therein or settled thereby, which amounts will be subject to the provisions of Section 2.3(b)).

3.7 Allocated Values. The “Allocated Value” for each Lease included in the Conveyed Interests equals the product of the Net Acre Allocation and the number of Net Acres attributable to the Conveyed Interest in such Lease (other than any portion of such Lease included in a proration unit for a Well), and the “Allocated Value” for each Well included in the Conveyed Interests is as set forth for such Well on Exhibit B and includes Seller’s interest in the Leases included in the proration unit for such Well as authorized by applicable Law and the terms of the applicable Leases.

ARTICLE IV

ACCESS / DISCLAIMERS

4.1Access.

(a) From and after the Execution Date and up to and including the Closing Date (or earlier termination of this Agreement pursuant to the terms herein) but subject to the other provisions of this Section 4.1 and obtaining any required consents of Third Parties, including Third Party operators of the Properties (with respect to which consents Seller shall use commercially reasonable efforts to obtain but will not be obligated to expend any monies), Seller shall afford to Buyer and its Affiliates and their respective officers, employees, agents, accountants, attorneys, consultants and other authorized representatives (“Buyer’s Representatives”) reasonable access, during normal business hours, to the Properties and all Records and other documents in Seller’s or its Affiliates’ possession relating primarily to the Conveyed Interests. From and after the Execution Date until the Title Defect Claim Date, Seller shall also make available to Buyer and Buyer’s Representatives, upon reasonable notice and during normal business hours: (i) all lease files, title opinions, abstracts, run-sheets and other records relating to the Leases in Seller’s or its Affiliate’s possession which have not been previously delivered to Buyer; and (ii) Seller’s personnel knowledgeable with respect to the Conveyed Interests, in each case in order that Buyer may make such diligence investigation as Buyer considers necessary or appropriate. All investigations and due diligence conducted by Buyer or any Buyer’s Representative shall be conducted at Buyer’s sole cost, risk and expense and any conclusions made from any examination done by Buyer or any Buyer’s Representative shall result from Buyer’s own independent review and judgment. Buyer shall coordinate its access rights and physical inspections of the Conveyed Interests with Seller to minimize any inconvenience to or interruption of the conduct of business by Seller. Buyer shall, and shall cause all Buyer’s Representatives to, abide by Seller’s, and any Third Party operator’s safety rules, regulations, and operating policies while conducting its due diligence evaluation of the Conveyed Interests, including any environmental or other inspection or assessment of the Conveyed Interests, and to the extent reasonably required by any Third Party operator, execute and deliver any required bonding agreement of such Third Party operator or maintain insurance as may be required by any Third Party operator, in each case before conducting Buyer’s assessment on such Conveyed Interest.

(b)From the Execution Date until the Environmental Defect Claim Date,

Buyer’s inspection right with respect to the environmental condition of the Conveyed Interests

will be limited to conducting a Phase I Environmental Site Assessment and may include only visual inspections and record reviews relating to the Conveyed Interests, including their condition and compliance with Environmental Laws. In conducting such Phase I Environmental Site Assessment, Buyer shall not operate any equipment or conduct any testing or sampling of soil, groundwater or other materials (including any testing or sampling for Hazardous Substances, Hydrocarbons or NORM) or conduct any other invasive activities. In the event that Buyer’s Phase I Environmental Site Assessment identifies actual or potential “recognized environmental conditions” with respect to any Asset, then Buyer may request (any such request, a “Phase II Request”) in writing Seller’s permission to conduct Phase II environmental property assessments to further assess such conditions. Each Phase II Request will state with reasonable specificity (i) the actual or potential “recognized environmental conditions” identified and (ii) the proposed scope of the Phase II assessment, including a description of the activities to be conducted, and a description of the approximate location and expected timing of such activities. Seller may, in its sole discretion, approve said Phase II environmental property assessment plan, in whole or in part, and Buyer shall not have the right to conduct any activities set forth in such plan until such time that Seller has approved such plan in writing. Any such approved Phase II environmental property assessment plan shall be conducted by a reputable environmental consulting or engineering firm. Seller shall have the right to (A) condition any approval of said Phase II environmental property assessment plan on the provision of proof of satisfactory insurance and (B) if said plan is approved by Seller, have its representatives witness all on-site activities set forth in said Phase II environmental property assessment plan and split any samples collected in connection therewith. If Seller does not provide its consent to any Phase II Request delivered in accordance with the above terms within two Business Days of Buyer’s delivery of such request, Buyer may submit the “recognized environmental conditions” identified in the Phase I Environmental Site Assessment as the basis of an Environmental Defect pursuant to Article VI.

(c) Buyer hereby indemnifies, defends, and holds harmless each of the operators of the Conveyed Interests and each Seller Indemnified Party from and against any and all Liabilities caused, directly or indirectly, by any field visit, environmental property assessment or other due diligence activity conducted by Buyer or any Buyer’s Representative with respect to the Conveyed Interests, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ARISING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF ANY SUCH OPERATOR OF THE CONVEYED INTERESTS OR A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(d) Buyer acknowledges that any entry into Seller’s offices or onto the Conveyed Interests will be at Buyer’s sole risk and, subject to the terms hereof, that none of the Seller Indemnified Parties will be liable in any way for any injury, loss or damage arising out of such entry that may occur to Buyer or any of Buyer’s Representatives pursuant to this Agreement. Buyer hereby fully waives and releases any and all Liabilities against all of the Seller Indemnified Parties for any injury, death, loss or damage to any of Buyer’s Representatives or their property in connection with Buyer’s due diligence activities, EVEN IF SUCH LIABILITIES ARISE OUT OF OR RESULT FROM, IN WHOLE OR IN PART, THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES, EXCEPTING ONLY LIABILITIES ARISING FROM THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF A MEMBER OF THE SELLER INDEMNIFIED PARTIES.

(e) Upon request by Seller, Buyer agrees to promptly provide Seller copies of all final reports and test results prepared by Buyer and/or any of Buyer’s Representatives, which contain data collected or generated from Buyer’s due diligence with respect to the Conveyed Interests, including all environmental and title reports. Seller will not be deemed by its receipt of said documents or otherwise to have made any representation or warranty, expressed, implied or statutory, as to the condition of the Conveyed Interests or to the accuracy of said documents or the information contained therein.

(f) During all periods between the Effective Date and the Closing that Buyer and/or any of Buyer’s Representatives are physically present on the Conveyed Interests, Buyer shall maintain, at its sole expense, policies of insurance of the types and in the amounts set forth on Schedule 4.1(f) or as otherwise mutually agreed between Buyer and Seller. Upon request by Seller, Buyer shall provide evidence of such insurance to Seller prior to entering the premises constituting the Conveyed Interests.

4.2 Confidentiality. Buyer acknowledges that, pursuant to its right of access to the Records or the Conveyed Interests, Buyer will become privy to confidential and other information of Seller and that such confidential information shall not be used for any purpose other than assessing the transactions contemplated by this Agreement and shall be held confidential by Buyer and Buyer’s Representatives in accordance with the terms of the Confidentiality Agreement. If the Closing should occur, the foregoing confidentiality restriction on Buyer, including the Confidentiality Agreement, will terminate 12 months following the Closing Date (except as to the following items (for which such restriction will continue in full force and effect): (a) any Conveyed Interests that are excluded from the transactions contemplated hereby pursuant to the provisions of this Agreement; (b) the Excluded Assets; and (c) information related to any assets other than the Conveyed Interests).

4.3Disclaimers.

(a) EXCEPT AS AND TO THE EXTENT SET FORTH IN THIS AGREEMENT AND ANY TRANSACTION DOCUMENTS: (I) SELLER MAKES NO REPRESENTATIONS OR WARRANTIES, EXPRESS, STATUTORY OR IMPLIED; AND (II) SELLER EXPRESSLY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, STATEMENT OR INFORMATION MADE OR COMMUNICATED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES, EMPLOYEES, AGENTS, CONSULTANTS OR REPRESENTATIVES (INCLUDING ANY OPINION, INFORMATION, PROJECTION OR ADVICE THAT MAY HAVE BEEN PROVIDED TO BUYER BY A MEMBER OF THE SELLER INDEMNIFIED PARTIES).

(b) EXCEPT AS AND TO THE EXTENT SET FORTH IN THIS AGREEMENT AND ANY TRANSACTION DOCUMENTS, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED BY ANY MEMBER OF THE SELLER INDEMNIFIED PARTIES, AS TO: (I) TITLE TO ANY OF THE CONVEYED INTERESTS; (II) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT, OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE CONVEYED INTERESTS; (III) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE CONVEYED INTERESTS, (IV) ANY ESTIMATES OF THE VALUE OF THE CONVEYED INTERESTS OR FUTURE REVENUES GENERATED BY THE CONVEYED INTERESTS; (V) THE PRODUCTION OF HYDROCARBONS FROM THE CONVEYED INTERESTS; (VI) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE CONVEYED INTERESTS, (VII) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLER OR THIRD PARTIES WITH RESPECT TO THE CONVEYED INTERESTS; (VIII) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES, OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO; AND (IX) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE EXTENT SET FORTH IN THIS AGREEMENT AND ANY TRANSACTION DOCUMENT, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY CONVEYED INTERESTS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE OR CONSIDERATION, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES HERETO THAT BUYER WILL BE DEEMED TO BE OBTAINING THE CONVEYED INTERESTS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(c) EXCEPT AS AND TO THE EXTENT SET FORTH IN THIS AGREEMENT AND ANY TRANSACTION DOCUMENT, (i) SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF MATERIALS INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE CONVEYED INTERESTS; AND (ii) SUBJECT TO BUYER’S RIGHTS UNDER SECTION 6.1, BUYER WILL BE DEEMED TO BE TAKING THE CONVEYED INTERESTS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT

BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS AS BUYER DEEMS APPROPRIATE.

(d) Seller and Buyer agree that, to the extent required by applicable Law to be effective, the disclaimers of certain representations and warranties contained in this Section 4.3 are “conspicuous” disclaimers for the purpose of any applicable Law.

ARTICLE V

TITLE MATTERS; CASUALTIES; TRANSFER RESTRICTIONS

5.1 General Disclaimer of Title Warranties and Representations. Except for the special warranty of title described in Section 5.2 below and without limiting Buyer’s remedies for Title Defects set forth in this Article V, Seller makes no warranty or representation, express, implied, statutory or otherwise, with respect to Seller’s title to any of the Conveyed Interests, and Buyer hereby acknowledges and agrees that Buyer’s sole remedy for any defect of title, including any Title Defect, with respect to any of the Conveyed Interests: (a) before the Title Defect Claim Date, will be as set forth in Section 5.3; and (b) from and after the Title Defect Claim Date, will be pursuant to the special warranty of title described in Section 5.2 below.

5.2 Special Warranty. The Assignment will include a special warranty of title pursuant to which Seller will warrant title to the Leases and Wells against every Person whomsoever claiming the same or any part thereof by, through or under Seller, but not otherwise, subject, however, to the Permitted Encumbrances (the “Special Warranty”). No other warranty of title will be contained in the Assignment or any other assignments of the Conveyed Interests, and except for the Special Warranty, all such warranties will be expressly disclaimed; provided, however, that the Assignment will contain subrogation language in favor of Buyer such that, to the extent transferable, Buyer will be and is subrogated to all covenants and warranties of title by Third Parties previously given or made to Seller or its predecessors in title in respect of any of the Conveyed Interests. The Special Warranty will be subject to the further limitations and provisions of this Section 5.2.

5.3Notice of Title Defects; Defect Adjustments.

(a) Title Defect Notices. On or before the Title Defect Claim Date, Buyer must deliver claim notices to Seller meeting the requirements of this Section 5.3(a) (collectively the “Title Defect Notices” and individually a “Title Defect Notice”) setting forth any matters which Buyer intends to assert as a Title Defect pursuant to this Article V. For all purposes of this Agreement and notwithstanding anything herein to the contrary, Buyer will be deemed to have waived, and Seller will have no liability for, any Title Defect which Buyer fails to assert as a Title Defect in a Title Defect Notice received by Seller on or before the Title Defect Claim Date. Each Title Defect Notice must be in writing, and must include: (i) a description of the alleged Title Defect(s); (ii) the Leases or Wells affected by the Title Defect (each a “Title Defect Property”); (iii) the Allocated Value of each Title Defect Property; (iv) supporting documents available to Buyer and reasonably necessary for Seller to verify the existence of the alleged Title Defect(s); and (v) the amount by which Buyer reasonably believes the Allocated Value of each Title Defect Property is reduced by the alleged Title Defect(s) and the computations (in reasonable detail) upon which Buyer’s belief is based. Buyer may provide a single Title Defect

Notice that covers multiple Title Defects and multiple Title Defect Properties so long as the Title Defect Notice includes the information listed in parts (i) through (v) of the preceding sentence with respect to each Title Defect and otherwise complies with this Section 5.3(a). To give Seller an opportunity to commence reviewing and curing Title Defects, Buyer agrees to use commercially reasonable efforts to give Seller, on or before May 9, 2014 and May 23, 2014, as applicable, written notice of all Title Defects discovered by Buyer prior to such date (unless previously submitted to Seller in a Title Defect Notice), which each such notice may be preliminary in nature and supplemented prior to the expiration of the Title Defect Claim Date.

(b) S ell er’s R ight to C ure . Seller has the right, but not the obligation, to attempt, at its sole cost, to cure any Title Defects of which it has been advised by Buyer at any time prior to the date that is two Business Days prior to the Closing Date (the “Cure Period”).

(c) Remedies for Title Defects. Subject to Seller’s continuing right to dispute the existence of a Title Defect and/or the Title Defect Amount asserted with respect thereto, in the event that any Title Defect timely asserted by Buyer in accordance with Section 5.3(a) is not waived in writing by Buyer or cured during the Cure Period, Seller shall, at its sole option, elect to, subject to Section 5.3(f):

(i) reduce the Closing Cash Amount by an amount (the “Title Defect Amount”) determined pursuant to Section 5.3(e) as being the value of such Title Defect to the extent affecting the applicable Lease and/or Well;

(ii) retain the entirety of the Title Defect Property that is subject to such Title Defect, together with all associated Conveyed Interests (and such Title Defect Property and Conveyed Interests shall be deemed to be Excluded Assets for the purposes of this Agreement), and, concurrently therewith, reduce the Closing Cash Amount by an amount equal to the Allocated Value of the Title Defect Property; or

(iii) elect to cure the Title Defect following Closing (in which case, the Closing Cash Amount will be adjusted downwards by the Allocated Value of the Title Defect Property affected by such Title Defect and such Title Defect Property (together with all associated Conveyed Interests) will not be conveyed to Buyer at the Closing); provided that (A) in the event that such Title Defect is cured within 45 days following the Closing, Buyer will pay to Seller the Allocated Value for such Title Defect Property and Seller will promptly convey to Buyer such Title Defect Property (together with all associated Conveyed Interests) (plus the sum of all amounts Buyer would have been required to pay to Seller with respect to the development of such Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation) had such Conveyed Interest been conveyed to Buyer at Closing) or (B) in the event that such Title Defect is not cured within 45 days following the Closing, Seller shall be required to remedy the Title Defect pursuant to subsections (i) or (ii) above (provided that if the remedy in subsection (i) is selected, Buyer shall pay to Seller the Allocated Value for such Title Defect Property minus the Title Defect Amount therefor (plus the sum of all amounts Buyer would have been required to pay to Seller with respect to the development of such Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any

Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation) had such Conveyed Interest been conveyed to Buyer at Closing) and Seller shall promptly convey to Buyer such Title Defect Property (together with all associated Conveyed Interests previously excluded at Closing in connection therewith), or (x) if the remedy in subsection (ii) is selected, Seller shall promptly reimburse to Buyer all amounts previously paid by Buyer with respect to the development of such Title Defect Property and associated Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation).

(d) Exclusive Remedy. Except for the Special Warranty, Section 5.3(c) will be the exclusive right and remedy of Buyer with respect to any Title Defects or Seller’s failure to have Defensible Title with respect to any Lease and/or Well or any other title matter with respect to any Conveyed Interest, and Buyer hereby waives any and all other rights or remedies with respect thereto.

(e) Title Defect Amount. The Title Defect Amount resulting from a Title Defect will be the amount by which the Allocated Value of the Title Defect Property is reduced as a result of the existence of such Title Defect and will be determined in accordance with the following terms and conditions:

(i) if Buyer and Seller agree on the Title Defect Amount, then that amount will be the Title Defect Amount;

(ii) if the Title Defect is an Encumbrance that is undisputed and liquidated in amount, then the Title Defect Amount will be the amount necessary to be paid to remove the Title Defect from that portion of the Title Defect Property included in the Covered Interests;

(iii) if the Title Defect represents a discrepancy such that the actual Net Revenue Interest for any Title Defect Property is less than the Net Revenue Interest identified for such Title Defect Property in Exhibit A or Exhibit B, as applicable (proportionately reduced), then the Title Defect Amount will be the product of the Allocated Value of the Title Defect Property multiplied by a fraction, the numerator of which is the Net Revenue Interest decrease and the denominator of which is the Net Revenue Interest for such Title Defect Property (proportionately reduced) identified on Exhibit A or Exhibit B, as applicable; provided, that the Title Defect Amount for such Title Defect will be determined by considering both the proportion of reduction in the Net Revenue Interest (through the formula set forth above) and the effect of the disproportionate change, if any, in the Working Interest (through the provisions of Section

5.3(e)(v));

(iv) if the Title Defect represents a discrepancy such that the actual Net Acres for any Title Defect Property is less than the Net Acres set forth in Exhibit A, then the Title Defect Amount will be the product obtained by multiplying the difference between such Net Acre amounts for that portion of the applicable Title Defect Property included in the Conveyed Interests by the Net Acre Allocation;

(v) if the Title Defect represents an Encumbrance upon or other defect in title affecting the Title Defect Property of a type not described above, the Title Defect Amount will be determined by taking into account the Allocated Value of the Title Defect Property, the portion of the Title Defect Property affected by the Title Defect, the legal effect of the Title Defect, the potential economic effect of the Title Defect over the life of the Title Defect Property and such other reasonable factors as are necessary to make a proper evaluation; provided, however, that if Seller elects to cure such Title Defect, the Title Defect Amount will not be greater than the lesser of: (A) the reasonable cost and expense of curing such Title Defect; and (B) the Allocated Value of the Title Defect Property;

(vi) if a Title Defect affects both a Lease or Leases and a Well, then the Title Defect Amount for such Title Defect will equal the sum of: (A) the Title Defect Amount with respect to such Title Defect for such Lease(s); plus (B) the Title Defect Amount with respect to such Title Defect for such Well;

(vii) the Title Defect Amount with respect to a Title Defect Property will be determined without duplication of any costs or losses included in another Title Defect Amount hereunder; and

(viii) notwithstanding anything to the contrary in this Article V, the aggregate Title Defect Amounts attributable to the effects of all Title Defects upon any Title Defect Property shall not exceed the Allocated Value of the Title Defect Property.

(f) Title Deductibles. Notwithstanding anything to the contrary: (i) in no event will there be any adjustments to the Closing Cash Amount or other remedies provided by Seller hereunder for any individual Title Defect for which the Title Defect Amount does not exceed $100,000 (“Individual Title Defect Threshold”); and (ii) in no event will there be any adjustments to the Closing Cash Amount or other remedies provided by Seller hereunder for any Title Defect for which the Title Defect Amount exceeds the Individual Title Defect Threshold unless the aggregate Title Defect Amounts of all such Title Defects that exceed the Individual Title Defect Threshold, but excluding any Title Defect Amounts attributable to Title Defects cured by Seller or Title Defect Properties retained by Seller, as applicable, pursuant to Section 5.3(c)(ii) exceeds $1,000,000 (the “Title Defect Deductible”), after which point Buyer will be entitled to remedies for such Title Defects only to the extent that the Title Defect Amounts with respect thereto are in excess of such Title Defect Deductible. For the avoidance of doubt, if Seller elects to retain any Title Defect Property, the Closing Cash Amount will be reduced in accordance with Section 5.3(c)(ii) and the Title Defect Amount relating to the Conveyed Interest attributable to such Title Defect Property will not be counted towards the Title Defect Deductible.

(g)Title Dispute Resolution.

(i) Seller and Buyer shall attempt in good faith to agree on all Title Defects and Title Defect Amounts (collectively “Title Disputes”) prior to the Closing. If Seller and Buyer are unable to agree by the Closing, (i) the Title Disputes will be exclusively and finally resolved pursuant to Section 5.3(g)(ii), (ii) the Closing Cash Amount shall be adjusted downwards by the Allocated Value of each Title Defect Property affected by such Title Disputes

and such Title Defect Properties (together with all associated Conveyed Interests) shall not be conveyed to Buyer at the Closing, and (iii) promptly after such Title Disputes are finally resolved, Seller shall, at its sole option with respect to each such Title Defect Property, elect to, subject to Section 5.3(f): (x) cause Buyer to pay to Seller (1) the Allocated Value for such Title Defect Property minus the Title Defect Amount, if any, plus (2) the sum of all amounts Buyer would have been required to pay to Seller with respect to the development of such Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation) had such Conveyed Interest been conveyed to Buyer at Closing and promptly convey to Buyer such Title Defect Property (together with all associated Conveyed Interests); (y) retain the Title Defect Property (together with all associated Conveyed Interests), in which case such Title Defect Property (together with all associated Conveyed Interests) will be deemed permanently to be an Excluded Asset; or (z) elect to cure the Title Defect, provided that if Seller is not successful in curing the Title Defect within the 45 day period following the resolution of such Title Disputes, Seller will remedy the Title Defect pursuant to subsections (x) or (y) above (provided that if the remedy in subsection (y) is selected, Seller shall promptly reimburse to Buyer all amounts previously paid by Buyer with respect to the development of such Title Defect Property and associated Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation)).

(ii) There will be a single arbitrator, who must be a title attorney with at least ten years’ experience in oil and gas titles involving properties in any of the regional areas in which the Title Defect Properties are located, in each case as selected by mutual agreement of Buyer and Seller within 15 days after the Closing Date (the “Title Arbitrator”). If the Parties are unable to mutually agree upon the Title Arbitrator, the Houston, Texas office of the AAA shall appoint the Title Arbitrator under such conditions as the AAA in its sole discretion deems necessary or advisable. The place of arbitration will be Houston, Texas, and the arbitration will be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 5.3(g). The Title Arbitrator’s determination will be made within 30 days after submission of Title Disputes and will be final and binding upon both Parties, without right of appeal. In making his determination with respect to any Title Dispute, the Title Arbitrator shall be bound by the rules set forth in Section 5.3(g) and, subject to the foregoing, may consider such other matters as in the opinion of the Title Arbitrator are necessary to make a proper determination. The Title Arbitrator, however, may not award Buyer a greater Title Defect Amount than the Title Defect Amount claimed by Buyer in its applicable Title Defect Notice. The Title Arbitrator will act for the limited purpose of determining the specific Title Disputes submitted by either Party, and the Title Arbitrator may not award damages, interest or penalties to either Party with respect to any Title Dispute. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Title Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Title Arbitrator. Subject to Sections 10.4 and 11.4, nothing herein will operate to cause the Closing to be delayed on account of any arbitration that may be conducted pursuant to this Section 5.3(g).

5.4Casualty or Condemnation Loss.

(a) Notwithstanding anything herein to the contrary, from and after the Effective Time if Closing occurs, with respect to the Conveyed Interests, without limiting Buyer’s rights to indemnity hereunder, Buyer shall assume all risk of loss with respect to: (i) production of Hydrocarbons through normal depletion (including watering out of any well, collapsed casing or sand infiltration of any well); and (ii) the depreciation of Personal Property due to ordinary wear and tear, in each case, to the extent attributable to the Conveyed Interests, and Buyer shall not assert such matters as any casualty losses or Title Defects hereunder, to the extent of its percentage interest share.

(b) If, after the Effective Time but prior to the Closing Date, any portion of the Conveyed Interests is damaged or destroyed by fire or other casualty or is taken in condemnation or under right of eminent domain (a “Casualty Event”), then, subject to Buyer’s rights arising under Section 10.4, Buyer will not be excused from its obligation to close solely as a result thereof and Seller shall elect by written notice to Buyer prior to Closing either: (i) to cause the Conveyed Interests affected by such casualty or taking to be repaired or restored to at least its condition prior to such casualty or taking, at Seller’s sole cost and expense, prior to the Closing, in which case, Seller is entitled to retain all rights to insurance, condemnation awards and other claims against Third Parties with respect to the casualty or taking except to the extent the Parties otherwise agree in writing; or (ii) at Closing, to pay to Buyer all sums paid to Seller by Third Parties by reason of such casualty or taking to the extent (and only to the extent) attributable to the Conveyed Interests and shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s right, title and interest (if any) in insurance claims, unpaid awards, and other rights against Third Parties (excluding any Liabilities, other than insurance claims, of or against any Seller Indemnified Parties) arising out of such casualty or taking to the extent (and only to the extent) attributable to the Conveyed Interests; provided, however, that Seller shall reserve and retain (and Buyer shall assign to Seller) all rights, titles, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing in pursuing or asserting any such insurance claims or other rights against Third Parties or in defending or asserting rights in such condemnation or eminent domain action with respect to the Conveyed Interests.

(c) Subject to Buyer’s rights arising under Section 10.4, if any action for condemnation or taking under right of eminent domain is pending or threatened with respect to any Conveyed Interest or portion thereof after the Effective Time, but no taking of such Conveyed Interest or portion thereof occurs prior to the Closing Date, Buyer shall nevertheless be required to close and Seller, at Closing, shall assign, transfer and set over to Buyer or subrogate Buyer to all of Seller’s right, title and interest (if any) in such condemnation or eminent domain action, including any future awards therein, to the extent (and only to the extent) attributable to the Conveyed Interests threatened to be taken, except that Seller shall reserve and retain (and Buyer shall assign to Seller) all rights, titles, interests and claims against Third Parties for the recovery of Seller’s costs and expenses incurred prior to the Closing in defending or asserting rights in such action with respect to the Conveyed Interests, to the extent that no such costs will be charged to Buyer.

5.5Preferential Purchase Rights and Consents to Assign.

(a) With respect to each Preferential Purchase Right set forth in Schedule 7.10, not later than ten days after the Execution Date (and, with respect to each Preferential Purchase Right that is not set forth in Schedule 7.10 but is discovered by either Party after the Execution Date and before the Closing Date, not later than five days after the discovery thereof), Seller shall send to the holder of each such Preferential Purchase Right a notice in compliance with the contractual provisions applicable to such Preferential Purchase Right.

(i) If, prior to Closing, any holder of a Preferential Purchase Right notifies Seller that it intends to consummate the purchase of the Conveyed Interest to which its Preferential Purchase Right applies or if the time for exercising such Preferential Purchase Right has not expired, then the Conveyed Interest (together with all associated Conveyed Interests) subject to such Preferential Purchase Right will be excluded from the Conveyed Interests to be assigned to Buyer at Closing (but only to the extent of the portion of such Conveyed Interest affected by the Preferential Purchase Right), such Conveyed Interest shall be deemed to be an Excluded Asset, and the Closing Cash Amount will be reduced by the sum of the Allocated Value of such Conveyed Interest (or portion thereof) so excluded. Seller will be entitled to all proceeds paid by any Person exercising a Preferential Purchase Right prior to Closing. If such holder of such Preferential Purchase Right thereafter fails to consummate the purchase of the Conveyed Interest (or portion thereof) covered by such Preferential Purchase Right on or before the end of the time period for closing such sale or the time for exercising such Preferential Purchase Right expires without exercise by the holder thereof: (1) Seller shall so notify Buyer; and (2) Seller shall assign, on the tenth Business Day following the end of such time period or termination of such right without exercise, such Conveyed Interest (or portion thereof) that was so excluded to Buyer pursuant to an instrument in substantially the same form as the Assignment, such Conveyed Interest will no longer be deemed to be an Excluded Asset and shall be treated as a Conveyed Interest and Buyer will pay Seller (by wire transfer of immediately available funds) the amount by which the Closing Cash Amount was reduced at Closing with respect to such asset that was excluded (or portion thereof).

(ii) All Conveyed Interests for which any applicable Preferential Purchase Right has been waived, or as to which the period to exercise the applicable Preferential Purchase Right has expired, in each case, prior to Closing, will be transferred to Buyer at Closing pursuant to the provisions of this Agreement.

(b) With respect to each Consent set forth in Schedule 7.4, Seller, not later than ten days after the Execution Date (and, with respect to each Consent that is not set forth in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date, not later than five days after the discovery thereof), shall send to the holder of each such Consent a notice in compliance with the contractual provisions applicable to such Consent seeking such holder’s consent to assign to Buyer the Applicable Contract or Lease subject to such Consent in connection with the transactions contemplated hereby.

(i) If: (A) Seller fails to obtain a Consent set forth in Schedule 7.4 (or any Consent that is not set forth in Schedule 7.4 but is discovered by either Party after the Execution Date and before the Closing Date) prior to Closing and the failure to obtain such Consent would: (1) cause the assignment of the Conveyed Interests affected thereby to Buyer to

be void; or (2) terminate the affected Lease(s) and/or Applicable Contract(s) or give the holder of such Consent the right to terminate the affected Lease(s) or Applicable Contract(s) under the express terms thereof; or (B) a Consent requested by Seller is denied in writing, then, in each case, the Conveyed Interest (or portion thereof) affected by such un-obtained Consent (together with all associated Conveyed Interests) will be excluded from the Conveyed Interests to be assigned to Buyer at Closing and such Conveyed Interests shall be deemed to be Excluded Assets, and the Closing Cash Amount will be reduced by the sum of the Allocated Value of such Conveyed Interest (or portion thereof) so excluded. In the event that any such Consent (with respect to a Conveyed Interest excluded pursuant to this Section 5.5(b)(i)) that was not obtained prior to Closing is obtained within 60 days following the Closing Date, then, on the tenth Business Day after such Consent is obtained Seller shall assign the Conveyed Interest (or portion thereof) that was so excluded as a result of such previously un-obtained Consent to Buyer pursuant to an instrument in substantially the same form as the Assignment, such Conveyed Interest will no longer be deemed to be an Excluded Asset and shall be treated as a Conveyed Interest, and Buyer will pay Seller (by wire transfer of immediately available funds) the amount by which the Closing Cash Amount was reduced at Closing with respect to the Conveyed Interest (or portion thereof) so excluded. From the Closing Date until 60 days thereafter, Seller shall use its best reasonable efforts to obtain consent to assignment from each holder of a consent affecting a Conveyed Interest that was retained by Seller pursuant to the terms of this Section

5.5(b).

(ii) If Seller fails to obtain a Consent set forth in Schedule 7.4 prior to Closing and: (A) the failure to obtain such Consent would not: (1) cause the assignment of the Conveyed Interest (or portion thereof) affected thereby to Buyer to be void; or (2) terminate the affected Lease(s) and/or Applicable Contract(s) or give the holder of such Consent the right to terminate the affected Lease(s) or Applicable Contract(s) under the express terms thereof; and (B) such Consent requested by Seller is not denied in writing by the holder thereof, then the Conveyed Interest (or portion thereof) subject to such un-obtained Consent will nevertheless be assigned by Seller to Buyer at Closing as part of the Conveyed Interests and Buyer will have no claim against, and Seller will have no Liability for, the failure to obtain any such Consent set forth in Schedule 7.4.

ARTICLE VI

ENVIRONMENTAL MATTERS

6.1Environmental Defects.

(a) Assertions of Environmental Defects. Buyer must deliver claim notices to Seller meeting the requirements of this Section 6.1(a) (collectively the “Environmental Defect Notices” and individually an “Environmental Defect Notice”) not later than the Environmental Defect Claim Date setting forth any matters which, in Buyer’s reasonable opinion, constitute Environmental Defects and which Buyer intends to assert as Environmental Defects pursuant to this Section 6.1. For all purposes of this Agreement, and notwithstanding anything to the contrary, Buyer will be deemed to have waived, and Seller will have no liability for, any Environmental Defect which Buyer fails to assert as an Environmental

Defect by an Environmental Defect Notice properly delivered by Buyer and received by Seller on or before the Environmental Defect Claim Date. Each Environmental Defect Notice must be in writing and must include: (i) a description of the matter constituting the alleged Environmental Defect; (ii) a description of each Conveyed Interest (or portion thereof) that is affected by the alleged Environmental Defect; (iii) supporting documents available to Buyer and reasonably necessary for Seller to verify the existence of the alleged Environmental Defect; and (iv) a calculation of the Remediation Amount (itemized in reasonable detail) that Buyer asserts is attributable to such alleged Environmental Defect. Buyer’s calculation of the Remediation Amount included in the Environmental Defect Notice must describe in reasonable detail the Remediation proposed for the Environmental Condition that gives rise to the asserted Environmental Defect and identify all assumptions used by Buyer in calculating the Remediation Amount, including the standards that Buyer asserts must be met to comply with Environmental Laws. Seller, at its sole discretion, has the right, but not the obligation, to cure any claimed Environmental Defect on or before the expiration of the Cure Period. Seller will be deemed to have adequately completed the Remediation required in the immediately preceding sentence: (A) upon receipt of a certificate or approval from the applicable Governmental Authority that the Remediation has been implemented to the extent necessary to comply with existing Laws; or (B) to the extent that the applicable Governmental Authority approval is not required with respect to the Remediation, upon receipt of a certificate from a licensed professional engineer that the Remediation has been implemented to the extent necessary to comply with existing Laws; provided that such engineer shall be selected by Seller and the costs and expenses in connection with such engineer shall be paid by Seller.

(b) Remedies for Environmental Defects. Subject to Seller’s continuing right to dispute the existence of an Environmental Defect and/or the Remediation Amount asserted with respect thereto, in the event that any Environmental Defect timely asserted by Buyer in accordance with Section 6.1(a) is not waived in writing by Buyer or cured prior to the expiration of the Cure Period (an “Uncured Environmental Defect”), Seller shall, at its sole option, elect to, subject to Section 6.1(d):

(i)reduce the Closing Cash Amount by the Remediation Amount;

(ii)assume responsibility for the Remediation of such Environmental

Defect; or

(iii) retain the entirety of the Conveyed Interest that is subject to such Uncured Environmental Defect, together with all associated Conveyed Interests, in which event (a) the Closing Cash Amount will be reduced by an amount equal to the sum of the Allocated Values of such retained Conveyed Interests and (b) such retained Conveyed Interests shall be deemed to be Excluded Assets.

If Seller elects the option set forth in clauses (i) or (iii) above, Buyer shall have no further remedy for any costs and expenses attributable to the Remediation of the applicable Environmental Defect and all Liabilities (net to the Conveyed Interest) with respect thereto and Buyer’s obligations with respect to the foregoing will be deemed to constitute Assumed Obligations. If Seller elects the option set forth in clause (ii) above, Seller shall take steps to promptly complete such Remediation prior to the date that is thirty (30) days after the Environmental Defect Claim Date in a manner which is consistent with the requirements of Environmental Laws, and such remediation shall be completed in accordance with diligent and customary oilfield practice within a reasonable period of time.

(c) Exclusive Remedy. Section 6.1(b) will be the exclusive right and remedy of Buyer with respect to any Environmental Defect or other environmental matter.

(d) Environmental Deductibles. Notwithstanding anything to the contrary: (i) in no event will there be any adjustments to the Closing Cash Amount or other remedies provided by Seller for any individual Environmental Defect for which the Remediation Amount does not exceed $100,000 (“Individual Environmental Threshold”); and (ii) in no event will there be any adjustments to the Closing Cash Amount or other remedies provided by Seller for any Environmental Defect for which the Remediation Amount exceeds the Individual Environmental Threshold unless the aggregate Remediation Amounts of all such Environmental Defects that exceed the Individual Environmental Threshold, but excluding any Remediation Amounts attributable to any Environmental Defects cured by Seller prior to the expiration of the Cure Period exceeds $1,000,000 (the “Environmental Defect Deductible”), after which point Buyer will be entitled to remedies for such Environmental Defect only to the extent that the Remediation Amounts with respect thereto are in excess of the Environmental Defect Deductible.

(e)Environmental Dispute Resolution.

(i) Seller and Buyer shall attempt in good faith to agree on all Environmental Defects and Remediation Amounts (collectively, the “Environmental Disputes”) prior to Closing. If Seller and Buyer are unable to agree by Closing, (i) the Environmental Disputes will be exclusively and finally resolved by arbitration pursuant to this Section 6.1(e), (ii) the Closing Cash Amount shall be adjusted downwards by the Allocated Value of each Conveyed Interest affected by such Environmental Disputes (together with all associated Conveyed Interests) and such Conveyed Interests shall be deemed to be Excluded Assets until such disputes are finally resolved (including, for the avoidance of doubt, for the purposes of calculating the Adjusted Closing Cash Amount and the Interim Period Carried Costs Amount) and (iii) promptly after such Environmental Disputes are finally resolved, Seller shall, at its sole option with respect to each such Conveyed Interest, elect to either: (a) convey such Conveyed Interest to Buyer in a form substantially similar to the Assignment and cause Buyer to pay to Seller an amount equal to (x) the Allocated Value minus the Environmental Defect Amount, if any (provided that Seller has not elected to assume responsibility for the Remediation of the underlying Environmental Defect, in which case, such deduction will not be made and Seller shall implement and promptly complete such Remediation in a manner which is consistent with the requirements of Environmental Laws), with respect to such Conveyed Interest, subject to Section 6.1(d), plus (y) the sum of all amounts Buyer would have been required to pay to Seller with respect to the development of such Conveyed Interests pursuant to the Development Agreement and any related operating agreements (including any Carried Costs that exceed the portion of the Allocated Value for such Title Defect Property that is attributable to the Carried Costs Obligation) had such Conveyed Interest been conveyed to Buyer at Closing; or (b) retain such Conveyed Interest, in which case such Conveyed Interest will be deemed permanently to be an Excluded Asset.

(ii) There will be a single arbitrator, who must be an environmental attorney with at least ten years’ experience in environmental matters involving oil and gas producing properties in any of the regional areas in which the affected Conveyed Interests are located, as selected by mutual agreement of Buyer and Seller within 15 days after the Closing Date (the “Environmental Arbitrator”). If the Parties are unable to mutually agree upon the Environmental Arbitrator, the Houston, Texas office of the AAA shall appoint such Environmental Arbitrator under such conditions as the AAA in its sole discretion deems necessary or advisable. The place of arbitration will be Houston, Texas, and the arbitration shall be conducted in accordance with the AAA Rules, to the extent such rules do not conflict with the terms of this Section 6.1(e). The Environmental Arbitrator’s determination shall be made within 30 days after submission of the Environmental Disputes and will be final and binding upon both Parties, without right of appeal. In making his determination, the Environmental Arbitrator shall be bound by the rules set forth in this Section 6.1 and, subject to the foregoing, may consider such other matters as in the opinion of the Environmental Arbitrator are necessary to make a proper determination. The Environmental Arbitrator, however, may not award Buyer a greater Remediation Amount than the Remediation Amount claimed by Buyer in its applicable Environmental Defect Notice or a lower Remediation Amount than the Remediation Amount claimed by Seller in response to Buyer’s Environmental Defect Notice unless it is determined there was no Environmental Defect. The Environmental Arbitrator shall act for the limited purpose of determining the specific Environmental Disputes submitted by either Party and may not award damages, interest or penalties to either Party with respect to any Environmental Dispute. Seller and Buyer shall each bear its own legal fees and other costs of presenting its case to the Environmental Arbitrator. Each of Seller and Buyer shall bear one-half of the costs and expenses of the Environmental Arbitrator. Subject to Sections 10.4 and 11.4, nothing herein will operate to cause the Closing to be delayed on account of any arbitration conducted pursuant to this Section 6.1(e).

6.2 NORM, Wastes and Other Substances. Buyer acknowledges that the Conveyed Interests have been used for exploration, development, and production of oil and gas and that there may be petroleum, produced water, wastes, or other substances or materials located in, on or under the Conveyed Interests or associated with the Conveyed Interests. Equipment and sites included in the Conveyed Interests may contain asbestos, NORM or other Hazardous Substances. NORM may affix or attach itself to the inside of wells, materials, and equipment as scale, or in other forms. The wells, materials, and equipment located on the Conveyed Interests or included in the Conveyed Interests may contain NORM and other wastes or Hazardous Substances. NORM containing material and/or other wastes or Hazardous Substances may have come in contact with various environmental media, including water, soils or sediment. Special procedures may be required for the assessment, remediation, removal, transportation, or disposal of environmental media, wastes, asbestos, NORM and other Hazardous Substances from the Conveyed Interests. Notwithstanding anything herein to the contrary, Buyer shall not be permitted to claim any Environmental Defect on the account of the presence of NORM on the properties underlying the Conveyed Interests, unless such presence of NORM constitutes an Environmental Condition resulting in a violation of Environmental Law.

ARTICLE VII

REPRESENTATIONS AND WARRANTIES OF SELLER

Seller represents and warrants to Buyer as follows:

7.1 Organization, Existence. Seller is a limited liability company duly formed and validly existing under the Laws of the State of Texas. Seller has all requisite power and authority to own and operate its property (including the Conveyed Interests) and to carry on its business as now conducted. Seller is duly licensed or qualified to do business as a foreign limited liability company in all jurisdictions in which such qualification is required by Law.

7.2 Authorization. Seller has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Seller of this Agreement and the Transaction Documents has been duly and validly authorized and approved by all necessary limited liability company action on the part of Seller. This Agreement is, and the Transaction Documents to which Seller is a party when executed and delivered by Seller will be, the valid and binding obligation of Seller and enforceable against Seller in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

7.3 No Conflicts. Except as disclosed in Schedule 7.3 and assuming the receipt of all consents and the waiver of all Preferential Purchase Rights applicable to the transactions contemplated hereby, the execution, delivery, and performance by Seller of this Agreement, the Transaction Documents and the consummation of the transactions contemplated herein and therein does not and will not: (a) conflict with or result in a breach of any provisions of the organizational documents or other governing documents of Seller; or (b) except for Permitted Encumbrances, result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation, or acceleration under any of the terms, conditions, or provisions of the Credit Agreement (or any other agreements in connection with the Credit Facility) or any Lease, Applicable Contract, note, bond, mortgage, or indenture to which Seller is a party or by which Seller or the Conveyed Interests may be bound; or (c) violate any Law applicable to Seller or any of the Conveyed Interests.

7.4 Consents. Except: (a) as set forth in Schedule 7.4; (b) for Customary Post- Closing Consents; and (c) for any Preferential Purchase Rights applicable to the transactions contemplated by this Agreement that are set forth on Schedule 7.10, there are no consents to assignment or other similar restrictions on assignment, in each case that would be applicable in connection with the transfer of the Conveyed Interests to Buyer or the consummation of the transactions contemplated by this Agreement by Seller (each, a “Consent”).

7.5 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened against Seller or any Affiliate entity of Seller.

7.6Foreign Person.Seller is not a “foreign person” within the meaning of

Section 1445 of the Code.

7.7 Litigation. Except as set forth in Schedule 7.7, as of the Execution Date, there is no: (a) lawsuit or litigation, or to Seller’s Knowledge, investigation by or before any Governmental Authority, pending, or to Seller’s Knowledge, threatened, against Seller (or, with respect to subsection (ii) below, any of Seller’s Affiliates); or (b) administrative or arbitration proceeding, pending, or to Seller’s Knowledge, threatened, against Seller (or, with respect to subsection (ii) below, any of Seller’s Affiliates), (in each case): (i) with respect to Seller’s ownership or operation of the Conveyed Interests; or (ii) that would affect the ability of Seller to consummate the transactions contemplated by this Agreement. Seller has received no written notice of any breach of Contract, tort or violation of Law by Seller or any of its Affiliates in any material respect with respect to Seller’s ownership or operation of the Conveyed Interests that has not been resolved.

7.8Material Contracts.

(a)Schedule 7.8(a) sets forth as of the Execution Date all Applicable

Contracts of the type described below (collectively, the “Material Contracts”):

(i) any Applicable Contract that can reasonably be expected to result in aggregate payments by Seller of more than $1,000,000 during the remainder of the current or any subsequent fiscal year or $5,000,000 in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(ii) any Applicable Contract that can reasonably be expected to result in aggregate revenues to Seller of more than $1,000,000 during the remainder of the current or any subsequent fiscal year or $5,000,000 in the aggregate over the term of such Applicable Contract (in each case, based solely on the terms thereof and without regard to any expected increase in volumes or revenues);

(iii) any Hydrocarbon purchase and sale, transportation, gathering, treating, processing or similar Contract that is not terminable without penalty on 90 days or less notice;

(iv) any Applicable Contract that is an indenture, mortgage, loan, credit or sale-leaseback, guaranty of any obligation, bonds, letters of credit or similar financial Contract;

(v) any Applicable Contract that constitutes a lease under which Seller is the lessor or the lessee of real or personal property which lease: (A) cannot be terminated by Seller without penalty upon 90 days or less notice; and (B) involves an annual base rental of more than $1,000,000;

(vi) any Applicable Contract with any Affiliate of Seller which will be binding on Buyer after the Closing Date other than the Development Agreement;

(vii) any Applicable Contract that constitutes a non-competition agreement or any agreement that purports to restrict, limit or prohibit the manner in which, or the locations in which, Seller conducts business, including area of mutual interest Contracts;

(viii)any Applicable Contract that contains a call on production;

(ix) any Applicable Contract that constitutes a partnership agreement, joint venture agreement or similar contract (in each case, excluding any tax partnership);

(x) any executory Applicable Contract that constitutes a pending farmout agreement, exploration agreement, participation agreement or other similar Contract where the primary obligation thereunder has not fully been performed; and

(xi)any Applicable Contract thatconstitutes a joint operating agreement.

(b) Except as set forth on Schedule 7.8(b), there exist no material defaults under any Applicable Contract by Seller or, to Seller’s Knowledge, by any other Person that is a party to such Applicable Contract. Each of the Applicable Contracts is in full force and effect as to Seller and, to Seller’s Knowledge, each counterparty thereto. Seller has made available to Buyer true and complete copies of each Applicable Contract (together with all amendments thereto). As of the Execution Date, Seller has not received or delivered any unresolved written notice of any price redetermination or termination with respect to any Applicable Contract. Other than the Material Contracts, there are no other Material Contracts, whether written or oral, that will be binding on Buyer or will encumber or affect the Conveyed Interests or the production therefrom after the Closing Date.

7.9 No Violation of Laws. Except as set forth on Schedule 7.9, neither Seller nor, to Seller’s Knowledge, any Third Party operator is in violation of any applicable Laws in any material respect with respect to the ownership by Seller or operation by such Third Party of the Subject Oil and Gas Assets. Seller possesses all material Permits required to be obtained from any Governmental Authority for conducting its business with respect to the Subject Oil and Gas Assets as presently conducted. With respect to each such Permit, Seller has not received written notice from any Governmental Authority of any violations of such Permits that remain uncured. Notwithstanding the foregoing, this Section 7.9 does not apply (and will not be deemed to apply) to any matters with respect to Environmental Laws or any of the environmental matters addressed in Section 7.25.

7.10 Preferential Rights. Except as set forth in Schedule 7.10, there are no preferential purchase rights, rights of first refusal or other similar rights that are applicable to the transfer of the Conveyed Interests in connection with the transactions contemplated hereby (each a “Preferential Purchase Right”).

7.11Imbalances. There are no Imbalances associated with the Properties as of the

Effective Time.

7.12Current Commitments. Schedule 7.12 sets forth, as of the Execution Date, all

approved authorities for expenditures and other approved capital commitments (“AFEs”)

relating to the Properties to drill or rework any Wells or conduct other operations, including those for which Seller had the right to consent or non-consent, in each case for which all of the activities anticipated in such AFEs were not completed by the Execution Date. There are no operations (including drilling operations) associated with the Properties with respect to which Seller is currently or will become a non-consenting or non-participating party.

7.13 Asset Taxes. Except as disclosed in Schedule 7.13, all Asset Taxes that have become due and payable by Seller on or prior to the Execution Date have been properly paid other than any Asset Taxes that are being contested in good faith that are disclosed on a schedule to this Agreement, and there is no audit or examination pending with respect to any such Asset Taxes. There are no encumbrances or liens (other than the Permitted Encumbrances) on any of the Conveyed Interests that arose in connection with any failure of Seller or any Affiliate to pay any Taxes, whether or not related to the Conveyed Interests.

7.14 Brokers’ Fees. Seller has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which Buyer or any Affiliate of Buyer will have any responsibility.

7.15 Advance Payments. Seller is not obligated by virtue of any take or pay payment, advance payment or other similar payment (other than gas balancing arrangements), to deliver Hydrocarbons, or proceeds from the sale thereof, attributable to the Conveyed Interests at some future time without receiving payment therefor at or after the time of delivery.

7.16Partnerships. None of Seller’s interest in the Conveyed Interests is subject to tax

partnership reporting for federal income tax purposes.

7.17 Suspense Funds. Schedule 7.17 contains a listing showing all proceeds from production attributable to the Conveyed Interests that are held in suspense as of the Execution Date (the “Suspense Funds”) and sets forth the reason (as reflected in Seller's records) that such proceeds are being held in suspense.

7.18Payout. Schedule 7.18 contains a complete and accurate list of the status of any

“payout” balance as of the respective dates set forth therein for the Wells listed on Exhibit B.

7.19 Leases. Seller has provided to Buyer complete, true and correct copies of the Leases. To Seller’s knowledge, all bonuses and rentals and other material payments or obligations due under the Leases have been properly and timely paid. To Seller’s knowledge, there is no default by Seller under any of the Leases. Neither Seller nor its Affiliates have received written notice from a lessor of any requirements or demands to drill additional wells on any of the Leases, which requirements or demands have not been resolved in writing. No party to any Lease or any successor to the interest of such party has filed or, to Seller’s Knowledge, threatened to file any action to terminate, cancel, rescind or procure judicial reformation of any Lease that has not been resolved.

7.20 Payment of Royalties and Rentals. Neither Seller nor its Affiliates have received notice of claims for failure to pay or mispayment of royalties, overriding royalties and other burdens on production, or any amounts owing to co-owners of the Subject Oil and Gas Assets, in each case, due by it with respect to the Subject Oil and Gas Assets that have not been

resolved. With respect to Leases and other agreements associated with the Leases and Wells, neither Seller nor its Affiliates have received notice of claims for failure to pay or mispayment of delay rentals and royalties that perpetuate Leases and similar payments under surface use agreements that have not been resolved.

7.21 Plugging and Abandonment. There are no Wells that constitute a part of the Subject Oil and Gas Assets in respect of which Seller or any Affiliate thereof has received an order from any Governmental Authority requiring that such Wells be plugged and abandoned.

7.22 Casualty or Condemnation Loss. There has been no casualty or condemnation loss as of the Execution Date with respect to the Conveyed Interests.

7.23 Operations. The Subject Oil and Gas Assets operated by Seller have been operated in the ordinary course of business consistent with past practices.

7.24 Reserved Interests. Seller and its Affiliates have not reserved any royalties, overriding royalties, production payments, net profits interests, carried interests or reversionary interests in connection with the transactions contemplated by this Agreement.

7.25Environmental Matters. Except as set forth in Schedule 7.25:

(a) With respect to the Properties, Seller has not entered into, and is not otherwise subject to, any agreements, consents, orders, decrees, judgments, license or permit conditions, or other binding consensual arrangements or commitments pursuant to and based on Environmental Laws that impose conditions that (i) prevent or limit or impair in any material respect the development of the Properties, (ii) impose restrictions or conditions that materially impair the future use of any of the Properties or (iii) require any remediation or other similar change in the present conditions of any of the Properties.

(b) Neither Seller nor any of its Affiliates have received notice from any Person of any (i) Release or threatened Release of Hazardous Substances at or from any of the Properties, or (ii) event, condition, circumstance, activity, practice or incident concerning any land, facility, asset or property included in the Properties or the management or disposal of Hazardous Substances associated with the ownership of the Properties, in each case that (A) prevents, restricts, delays or otherwise materially interferes with (1) compliance by Seller or any of Seller’s Affiliates or the Properties with any Environmental Law or the terms of any Environmental Permit, or (2) the development of the Properties, or (B) alleges or gives rise to or results in any Liability of Seller to any Person.

(c) Seller has made available to Buyer complete and accurate copies of all environmental, reports, studies, investigations and all similar documentation and correspondence in the possession of or control of Seller or any of Seller’s Affiliates.

(d) To Seller’s Knowledge, without investigation, (a) there are no uncured violations of any Environmental Law or Environmental Permit with respect to the Properties and no obligations to remediate conditions upon the Properties under any applicable Environmental Law (and no such obligation would arise as a result of notice or lapse of time or both), that in any such case relate to any actions of it, and (b) there are no uncured violations of any Environmental Law or Environmental Permit issued thereunder with respect to the Properties and no obligations to remediate conditions upon the Properties under any applicable Environmental Law (and no such obligation would arise as a result of notice or lapse of time or both), that in any such case relate to the actions of any Third Party.

(e) To Seller’s Knowledge, without investigation, (a) there is no outstanding investigation, inquiry or information request made by or claim or other actions initiated by a Governmental Authority related to Environmental Laws with respect to the Properties and any actions by Seller, and (b) there is no outstanding investigation, inquiry or information request made by or claims or other actions initiated by a Governmental Authority related to Environmental Laws with respect to the Properties and the actions of any Third Party.

(f) Seller possesses and maintains in full force and effect all material Environmental Permits for conducting its business with respect to the Conveyed Interests as presently conducted.

7.26 Affiliate Contracts. Schedule 7.26 sets forth all Applicable Contracts to which both Seller and an Affiliate of Seller are parties. The terms and provisions of such Affiliate Contracts reflect terms and conditions that would have been negotiated in an arms-length negotiation between Seller and a Third Party.

7.27 Rights of Way. Except as may be set forth in the Leases, there are no surface use agreements to which Seller is a party that materially interfere with the development or operation of any Development Assets.

7.28 Personal Property. Seller has good and marketable title or a valid leasehold interest in all of the Personal Property. All of the Personal Property is, in all material respects, in reasonable operating condition and repair (ordinary wear and tear excepted) and is adequate for the uses to which it is currently being put. All interests in the Personal Property that are attributable to the Conveyed Interests will be conveyed to Buyer at Closing free and clear of all Encumbrances, other than Permitted Encumbrances.

7.29 Sufficiency. The Property, Personal Property and Rights of Way are sufficient in all material respects for the conduct of the business in connection with the Subject Oil and Gas Assets in substantially the same manner as they are currently conducted.

7.30 Joint Accounts. There are no audits currently being conducted by Seller of the joint account under any operating agreements relating to the Properties nor are there any audits of Seller currently underway or, to Seller’s Knowledge, imminent relating to the Properties (except for customary audits by the Texas General Land Office in respect of royalty payments under the Leases).

ARTICLE VIII

REPRESENTATIONS AND WARRANTIES OF BUYER

Buyer represents and warrants to Seller the following:

8.1 Organization; Existence. Buyer is a limited liability company, duly formed, validly existing and in good standing under the Laws of the State of Texas and has all requisite power and authority to own and operate its property and to carry on its business as now conducted.

8.2 Authorization. Buyer has full power and authority to enter into and perform this Agreement and the Transaction Documents to which it is a party and the transactions contemplated herein and therein. The execution, delivery, and performance by Buyer of this Agreement and the Transaction Documents has been duly and validly authorized and approved by all necessary action on the part of Buyer. This Agreement is, and the Transaction Documents to which Buyer is a party when executed and delivered by Buyer will be, the valid and binding obligation of Buyer and enforceable against Buyer in accordance with their respective terms, subject to the effects of bankruptcy, insolvency, reorganization, moratorium, and similar Laws, as well as to principles of equity (regardless of whether such enforceability is considered in a proceeding in equity or at law).

8.3 No Conflicts. The execution, delivery, and performance by Buyer of this Agreement, the Transaction Documents to which it is a party and the consummation of the transactions contemplated herein will not: (a) conflict with or result in a breach of any provisions of the organizational or other governing documents of Buyer; or (b) result in a default or the creation of any Encumbrance or give rise to any right of termination, cancellation or acceleration under any of the terms, conditions or provisions of any note, bond, mortgage or indenture to which Buyer is a party or by which Buyer or any of its property may be bound; or (c) violate any Law applicable to Buyer or any of its property, except in the case of clauses (b) and (c) where such default, Encumbrance, termination, cancellation, acceleration or violation would not, individually or in the aggregate, have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated by this Agreement or perform its obligations hereunder.

8.4 Consents. Except as set forth on Schedule 8.4, there are no consents or other restrictions on assignment, including requirements for consents from Third Parties to any assignment (in each case) that would be applicable in connection with the consummation of the transactions contemplated by this Agreement by Buyer and are also not required of Seller.

8.5 Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer or any Affiliate of Buyer.

8.6 Litigation. As of the Execution Date, there is no investigation, lawsuit, action, or litigation by or before any Governmental Authority to which Buyer or any of its Affiliates is a party, and no legal, administrative, or arbitration proceedings pending, or to Buyer’s Knowledge, threatened against Buyer or any of its Affiliates, that in each case would have a material adverse effect upon the ability of Buyer to consummate the transactions contemplated in this Agreement.

8.7Regulatory. At Closing, Buyer will be qualified pursuant to all regulations of

Governmental Authorities and other applicable Laws to own the Conveyed Interests, and the

consummation of the transactions contemplated in this Agreement will not cause Buyer to be disqualified as such an owner.

8.8 Financing. Buyer will have as of the Closing Date, sufficient cash with which to pay the Closing Cash Amount and the Interim Period Carried Costs Amount and consummate the transactions contemplated by this Agreement.

8.9 Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer (a) has relied or shall rely solely on its own independent investigation and evaluation of the Conveyed Interests and the advice of its own legal, tax, economic, environmental, engineering, geological and geophysical advisors and the express provisions of this Agreement and the Transaction Documents and not on any comments, statements, projections or other materials made or given by any representatives or consultants or advisors engaged by Seller, and (b) has satisfied or shall satisfy itself through its own due diligence as to the environmental and physical condition of and contractual arrangements and other matters affecting the Conveyed Interests.

8.10 Brokers’ Fees. Buyer has incurred no liability, contingent or otherwise, for brokers’ or finders’ fees relating to the transactions contemplated by this Agreement or the Transaction Documents for which Seller or Seller’s Affiliates will have any responsibility.

8.11 Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Conveyed Interests for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

ARTICLE IX

CERTAIN AGREEMENTS

9.1 Operations During Interim Period. Except: (w) as expressly set forth in Schedule 9.1; (x) for the operations covered by the AFEs and other capital commitments described in Schedule 7.12; (y) as expressly set forth in the 2014 Work Program and Budget; and (z) as expressly contemplated by this Agreement or expressly consented to in writing by Buyer (which consent shall not be unreasonably delayed, withheld or conditioned):

(a)Seller agrees that from and after the Execution Date until Closing, Seller will:

(i) maintain and operate, or cause its Affiliates to maintain and operate, the Subject Oil and Gas Assets in a good and workmanlike manner, in the ordinary course of business and in accordance with all Applicable Contracts and Laws in all material respects and, except as set forth on Schedule 9.1, consistent with past practices;

(ii) maintain or cause its Affiliates to maintain the books of account and records relating to the Subject Oil and Gas Assets in the usual, regular and ordinary manner, in accordance with the usual accounting practices of each such Person and GAAP;

            (iii)use commercially reasonable efforts to maintain in full force and effect all Leases;

(iv) maintain insurance coverage on the Subject Oil and Gas Assets in amounts and types substantially similar to those currently in force;

(v)maintain all material Permits (including Environmental Permits)

and other approvals affecting the Subject Oil and Gas Assets; and

(vi) give prompt written notice to Buyer of any written notice: (A) received from any Third Party regarding spills, other environmental contamination or remediation obligations relating to the Conveyed Interests; and (B) of any material claim asserting any breach of Contract, tort or violation of Law or any investigation, suit, action or litigation by or before any Governmental Authority, that in each case has been received by Seller and relates to the Conveyed Interests.

(b)Seller agrees that from and after the Execution Date until the Closing

Date, Seller will not:

(i) commit to any operation or series of operations relating to the Subject Oil and Gas Assets in a manner that is inconsistent with the 2014 Work Program and Budget or any AFE set forth in Schedule 7.12 or that could reasonably be anticipated to require expenditures by Seller in excess of the amounts set forth in the 2014 Work Program and Budget or any AFE set forth in Schedule 7.12;

(ii) except upon prior written notice to Buyer, and except for the Gathering and Purchase Contracts, enter into an Applicable Contract that, if entered into on or prior to the Execution Date, would be required to be listed on Schedule 7.8(a) amend any Applicable Contract that, if so amended before the Execution Date, would have been required to be listed on Schedule 7.8(a);

(iii) terminate (unless such Applicable Contract terminates pursuant to its stated terms) or materially amend the terms of any Applicable Contract;

(iv) unless expressly contemplated in the 2014 Work Program and Budget, (A) transfer, sell, Encumber or dispose of (or permit any Affiliate to do any of the foregoing) any portion of the Conveyed Interests other than the sale and/or disposal of Hydrocarbons in the ordinary course of business and sales of equipment that is no longer necessary in the operation of the Conveyed Interests or for which replacement equipment of equal or greater value has been obtained;

(v) except as set forth on Schedule 9.1, settle any suit or litigation or waive any

material claims or rights of material value, in each case, attributable to the Conveyed Interests and affecting the period after the Effective Time;

(vi)relinquish any operating rights or other rights with respect to the

Subject Oil and Gas Assets; and

(vii)commit to do any of the foregoing.

Requests for consent/approval of any action restricted by this Section 9.1 shall be delivered to the following individual, who shall have full authority to grant or deny such requests for consent/approval on behalf of Buyer:

Firman A. Yaman

PT Saka Energi Indonesia

The Energy, 11th - 12th Floor, SBCD Lot 11A Jl. Jenderal Sudirman Kav. 52-53

Jakarta 12190, Indonesia

Fax: +6221.2995.1001

Email: firman.yaman@sakaenergi.com

Buyer’s consent to or approval of any action restricted by this Section 9.1 shall be deemed to be granted on the day that is ten days (unless a shorter time is mutually agreed by the Parties) requesting such consent/approval (which shall set forth with reasonable specificity the scope of such action) unless Buyer notifies Seller to the contrary during that period; provided that Buyer still may retract such deemed consent or approval at any time after expiration of such ten day period if Seller has not yet commenced steps to implement the actions set forth in such notice. Notwithstanding anything to the contrary in this Section 9.1, and solely with respect to the actions set forth in Sections 9.1(a)(i), 9.1(b)(i) and 9.1(b)(ii), in the event of an emergency, Seller may take such action as a prudent operator would take and shall notify Buyer of such action promptly thereafter.

9.2 Notifications. If, prior to Closing, Buyer or Seller has Knowledge that the other Party may have breached a representation, warranty, covenant or other agreement under this Agreement in any material respect, then Buyer or Seller, as the case may be, shall promptly inform the other Party of such breach so that it may attempt to remedy or cure such breach prior to Closing.

9.3 Amendments to Schedules. Buyer agrees that, with respect to the representations and warranties of Seller contained in this Agreement, Seller has the continuing right until Closing to add, supplement or amend the Schedules to its representations and warranties with respect to any matter hereafter arising (excluding, for the avoidance of doubt, any matters discovered after the Execution Date that are attributable to events occurring prior to such date) which, if existing or known at the date hereof or thereafter, would have been required to be set forth or described in such Schedules. For all purposes of this Agreement, including for purposes of determining whether the conditions set forth in Article X have been fulfilled, the Schedules to Seller’s representations and warranties contained in this Agreement will be deemed to include only that information contained therein on the Execution Date and will be deemed to exclude all information contained in any addition, supplement or amendment thereto.

9.4 Non-Solicitation of Employees. From and after the Execution Date until the one year anniversary of the day this Agreement is terminated pursuant to Section 14.1 or the date of Closing, whichever occurs first, Buyer and its Affiliates shall not solicit or hire any officer or employee of Seller or its Affiliates without first obtaining the prior written consent of Seller;

provided that this prohibition will not apply to offers of employment made by Buyer or its

Affiliates pursuant to a general solicitation of employment to the public or the industry.

9.5 Additional Interests. If Seller or its Affiliates acquire any additional oil and gas leases in the Development Area after the Execution Date (such leases, the “Additional Interests”), such Additional Interests will be excluded from the transactions contemplated by this Agreement and the Parties agree that, upon Closing, Seller or any such Affiliate shall offer to Buyer its 36% undivided share of any such Additional Interest pursuant to Article V of the Development Agreement.

9.6Governmental Approvals.

(a) In a timely manner, the Parties shall (a) make all required filings, prepare all required applications and conduct negotiations with each Governmental Body as to which such filings, applications or negotiations are necessary or appropriate in the consummation of the transactions contemplated hereby and (b) provide such information as each may reasonably request to make such filings, prepare such applications and conduct such negotiations. Each Party shall reasonably cooperate with and use all reasonable efforts to assist the other with respect to such filings, applications, and negotiations.

(b) In addition to the foregoing, the parties shall cooperate and use their respective best reasonable efforts to, as promptly as practicable, prepare and submit a joint voluntary notice to CFIUS, pursuant to the Foreign Investment and National Security Act of 2007 (“FINSA”), which amended Section 721 of the Defense Production Act of 1950, 31 C.F.R. Part 800. Each Party agrees to take any and all reasonable actions and to execute any and all documents advisable, necessary or desirable to secure CFIUS Approval as promptly as practicable after the date of such filing. Such efforts shall include complying with any reasonable request from CFIUS or its member agencies, including for additional or supplemental information during the CFIUS review process. Neither Party shall be required to enter into any agreement that: (i) interferes with its ability to participate in the management of the Company pursuant to the terms of this Agreement, unless agreed upon in writing; (ii) requires the Party to dispose of any portion of its businesses, operations, assets or product lines (or any combination thereof) other than the disposition that is contemplated in this Agreement; (iii) requires that one or more current owners be excluded from the transaction; or (iv) would impair or restrict the Parties’ ability to expand the scope of their mutual cooperation or Buyer’s ability to make additional investments in United States oil and gas assets (an “Exempted CFIUS Mitigation Agreement”).

ARTICLE X

BUYER’S CONDITIONS TO CLOSING

The obligations of Buyer to consummate the acquisition of the Conveyed Interests provided for herein is subject, at the option of Buyer, to the fulfillment by Seller or written waiver by Buyer, on or prior to the Closing of each of the following conditions:

10.1Representations. The representations and warranties of Seller set forth in Article

VII are true and correct in all material respects (other than any representations and warranties

qualified by “material” or “material adverse effect”, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date (other than representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date).

10.2 Performance. Seller has performed or complied in all material respects with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Seller is required prior to or at the Closing Date.

10.3 No Legal Proceedings. No suit, action, or other proceeding is pending before any Governmental Authority or threatened by a non-Affiliated Third Party, which in each case is seeking to restrain, prohibit, enjoin, declare illegal, or otherwise prevent, or is seeking material damages or other material relief in connection with, the transactions contemplated by this Agreement. No Law is enacted or issued that on a temporary or permanent basis restrains, enjoins, invalidates or otherwise prohibits the transactions contemplated by this Agreement.

10.4Title Defects and Environmental Defects. The sum of the following is less than

$25,000,000: (a) all Title Defect Amounts determined under Section 5.3 prior to the Closing or if disputed at Closing, as determined by Seller in its reasonable opinion; plus (b) all Remediation Amounts for Environmental Defects determined under Section 6.1 prior to the Closing or if disputed at Closing, as determined by Seller in its reasonable opinion; plus (c) the amount of losses attributable to all Casualty Events occurring during the Interim Period; plus (d) all adjustments to the Closing Cash Amount as a result of the exclusion of any Conveyed Interest on account of Preferential Purchase Rights pursuant to Section 5.5(a) or the failure to obtain a Consent pursuant to Section 5.5(b).

10.5 Certificate. An authorized officer of Seller has duly executed and delivered a certificate dated as of the Closing Date certifying on behalf of Seller that the conditions set forth in Section 10.1 and Section 10.2 have been fulfilled by Seller and, if applicable, any exceptions to such conditions that have been waived by Buyer.

10.6 Closing Deliverables. Seller has delivered (or be ready, willing and able to deliver at Closing) to Buyer the documents and other items required to be delivered by Seller under Section 12.3.

10.7CFIUS. The Parties have received the CFIUS Approval.

ARTICLE XI

SELLER’S CONDITIONS TO CLOSING

The obligations of Seller to consummate the transfer of the Conveyed Interests provided for herein is subject, at the option of Seller, to the fulfillment by Buyer or written waiver by Seller, on or prior to the Closing of each of the following conditions precedent:

11.1 Representations. The representations and warranties of Buyer set forth in Article VIII are true and correct in all material respects (other than any representations and warranties qualified by “material” or “material adverse effect”, which shall be true and correct in all respects) as of the Closing Date as though made on and as of the Closing Date (other than

representations and warranties that refer to a specified date, which need only be true and correct on and as of such specified date).

11.2 Performance. Buyer has performed or complied in all material respects with all obligations, agreements, and covenants contained in this Agreement as to which performance or compliance by Buyer is required prior to or at the Closing Date.

11.3 No Legal Proceedings. No suit, action, or other proceeding is pending before any Governmental Authority or threatened by a non-Affiliated Third Party, which in each case is seeking to restrain, prohibit, enjoin, declare illegal or otherwise prevent, or is seeking material damages or other material relief in connection with, the transactions contemplated by this Agreement. No Law is enacted or issued that on a temporary or permanent basis restrains, enjoins, invalidates or otherwise prohibits the transactions contemplated by this Agreement.

11.4Title Defects and Environmental Defects. The sum of the following is less than

$25,000,000: (a) all Title Defect Amounts determined under Section 5.3 prior to the Closing or if disputed at Closing, as determined by Seller in its reasonable opinion; plus (b) all Remediation Amounts for Environmental Defects determined under Section 6.1 prior to the Closing or if disputed at Closing, as determined by Seller in its reasonable opinion; plus (c) the amount of losses attributable to all Casualty Events occurring during the Interim Period; plus (d) all adjustments to the Closing Cash Amount as a result of the exclusion of any Conveyed Interest on account of Preferential Purchase Rights pursuant to Section 5.5(a) or the failure to obtain a Consent pursuant to Section 5.5(b).

11.5 Certificate. An authorized officer of Buyer has executed and delivered a certificate dated as of the Closing Date certifying on behalf of Buyer that the conditions set forth in Section 11.1 and Section 11.2 have been fulfilled by Buyer and, if applicable, any exceptions to such conditions that have been waived by Seller.

11.6 Closing Deliverables. Buyer has delivered (or be ready, willing and able to deliver at Closing) to Seller the documents and other items required to be delivered by Buyer under Section 12.3.

11.7CFIUS. The Parties have received the CFIUS Approval.

ARTICLE XII

CLOSING

12.1 Date of Closing. Subject to the conditions stated in this Agreement, the transfer by Seller of the Conveyed Interests to Buyer pursuant to this Agreement (the “Closing”) will occur on or before June 30, 2014, or if all conditions to Closing in Article X and Article XI have not yet been satisfied or waived by that date, then five Business Days after such conditions have been satisfied or waived, or such other date as Buyer and Seller may agree upon in writing. The date of the Closing will be the “Closing Date.”

12.2 Place of Closing. The Closing will be held at the offices of Latham & Watkins LLP, Suite 3700, 811 Main Street, Houston, Texas 77002, or such other location as Buyer and Seller may agree upon in writing.

12.3 Closing Obligations. At the Closing, the following documents will be delivered and the following events will occur, the execution of each document and the occurrence of each event being a condition precedent to the others and each being deemed to have occurred simultaneously with the others:

(a) Seller and Buyer shall execute and deliver the Assignment, in sufficient counterparts to facilitate recording in the applicable counties where the Conveyed Interests are located, covering the Conveyed Interests;

(b) Seller and Buyer shall execute and deliver assignments, on appropriate forms, of state and of federal Leases comprising portions of the Conveyed Interests, if any, in sufficient counterparts to facilitate filing with the applicable Governmental Authority;

(c) Buyer shall deliver to Seller, by direct bank or wire transfer in same day funds, an amount equal to (i) the sum of the Adjusted Closing Cash Amount and the Interim Period Carried Cost Amount minus (ii) the amount of the Deposit;

(d) Buyer and Seller shall duly execute and deliver joint written instructions to the Escrow Agent directing the Escrow Agent to release the Deposit to Seller;

(e) Seller shall deliver an executed statement, in form reasonably satisfactory to Buyer, described in Treasury Regulation § 1.1445-2(b)(2) certifying that Seller is not a foreign person within the meaning of the Code and the Treasury Regulations promulgated thereunder;

(f)Seller and Buyer shall execute and deliver the Development Agreement; (g)Seller and Buyer shall execute and deliver the Tax Partnership Agreement;

(h) Seller shall deliver letters in lieu of division and transfer orders executed by Seller relating to the Conveyed Interests in form reasonably acceptable to Buyer to reflect the conveyance contemplated hereby;

(i) Seller shall deliver to Buyer a certificate dated as of the Closing Date and signed by an authorized officer of Seller, certifying as complete and accurate as of the Closing Date attached copies of all requisite actions or resolutions of the applicable governing bodies of Seller and its Affiliates approving the execution, delivery and performance of this Agreement, the Development Agreement, the Tax Partnership Agreement, the Assignment, and all other transactions contemplated herein and therein;

(j) Buyer shall deliver to Seller a certificate dated as of the Closing Date and signed by an authorized officer of Buyer, certifying as complete and accurate as of the Closing Date attached copies of all requisite actions or resolutions of the applicable governing bodies and equity holders of Buyer and its Affiliates approving the execution, delivery and performance of this Agreement, the Development Agreement, the Tax Partnership Agreement, the Assignment and all other transactions contemplated herein and therein; and

(k)Seller shall deliver to Buyer evidence reasonably satisfactory to Buyer of

(i) the release of all Encumbrances in connection with the Credit Facility that affect the

Conveyed Interests and (ii) all consents and/or waivers required in connection with the Credit Agreement in order to consummate the transactions contemplated hereby and the transactions contemplated by the Transaction Documents without default or violation of, or giving rise to any right of termination, cancellation, or acceleration under, any of the terms, conditions, or provisions of the Credit Agreement or any other agreements in connection with the Credit Facility (including, for the avoidance of doubt, all consents and/or waivers required in connection with the disclosures set forth on Schedule 7.3).

(l) Seller and Buyer shall execute and deliver (i) any other Transaction Documents that are required by other terms of this Agreement to be executed and/or delivered at the Closing and (ii) any documents to be executed and delivered at the Closing pursuant to the terms of the other Transaction Documents.

12.4 Records. In addition to the obligations set forth under Section 12.3 above, no later than 15 days following the Closing Date, Seller shall deliver to Buyer copies of the Records.

ARTICLE XIII

ASSUMPTION; INDEMNIFICATION; SURVIVAL

13.1 Assumption by Buyer. Without limiting Buyer’s rights to indemnity under this Article XIII, from and after the Closing, Buyer assumes and hereby agrees to fulfill, perform, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all of the following (but solely to the extent attributable to the Conveyed Interests): (i) obligations and Liabilities, known or unknown, arising from, based upon or associated with the Conveyed Interests arising from and after the Effective Time, relating in any manner to the use, ownership or operation of the Conveyed Interests; and (ii) obligations and liabilities, known or unknown, arising from, based upon or associated with the Conveyed Interests, regardless of whether such obligations or Liabilities arose prior to, on or after the Effective Time, relating in any manner to obligations: (a) to furnish makeup gas attributable to the Conveyed Interests according to the terms of applicable gas sales, processing, gathering or transportation Contracts; (b) to pay royalties, overriding royalties and other interest owners’ revenues or proceeds attributable to sales of Hydrocarbons produced from the Conveyed Interests, including those held in suspense; (c) to pay the proportionate share attributable to the Conveyed Interests to properly plug and abandon any and all wells, including inactive wells or temporarily abandoned wells, located on the Properties; (d) to pay the proportionate share attributable to the Conveyed Interests to replug any well, wellbore, or previously plugged well on the Properties to the extent required by Law or otherwise necessary; (e) to pay the proportionate share attributable to the Conveyed Interests to dismantle or decommission and remove any Personal Property and other property of whatever kind related to or associated with operations and activities conducted by whomever on the Properties or otherwise pursuant to the Conveyed Interests; (f) except to the extent Seller is required to do so pursuant to Section 6.1(b), to pay the proportionate share attributable to the Conveyed Interests to clean up, restore and/or remediate the premises covered by or related to the Conveyed Interests in accordance

with applicable Contracts and Laws; and (g) to pay the proportionate share attributable to the Conveyed Interests to perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases and the Applicable Contracts, or as required by any Law (all of said obligations and Liabilities, subject to the exclusion below, herein being referred to as the “Assumed Obligations”); provided, Buyer does not assume any obligations or Liabilities, known or unknown, arising from, based upon or associated with the Conveyed Interests arising prior to the Effective Time, relating in any manner to the use, ownership or operation of the Conveyed Interests, other than those specifically addressed above (collectively, the “Seller’s Retained Obligations”). Notwithstanding anything to the contrary herein, the Seller’s Retained Obligations shall include:

(a) all Liabilities attributable to the interests that are retained by Seller in the properties and assets described in Section 2.1 from which the Conveyed Interests are created;

(b) all Liabilities attributable to, resulting from or arising out of the Excluded Assets or any asset excluded from the Conveyed Interests pursuant to the terms of this Agreement or the Development Agreement;

(c)Operating Expenses and other costs and expenses in connection with the

Conveyed Interests for which Seller is responsible pursuant to Section 2.3;

(d) all Liabilities attributable to or arising out of the payment of royalties, overriding royalties and other Burdens attributable to the period of time prior to the Effective Time or measured by production occurring prior to the Effective Time;

(e) all Liabilities attributable to or arising out of any breach or default in performance under any Applicable Contract prior to the Effective Time;

(f) all Liabilities attributable to or arising out of any personal injury or death prior to the Effective Time; and

(g)Asset Taxes and other Taxes for which Seller is responsible pursuant to Section 15.2.

13.2 Indemnities of Seller. Effective as of the Closing, subject to the limitations set forth in Section 13.4 and Section 13.8, Seller shall be responsible for, shall pay on a current basis, and hereby defends, indemnifies and holds harmless Buyer and its Affiliates, and all of its and their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, the “Buyer Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder, arising from, based upon, related to or associated with:

(a)any breach by Seller of its representations or warranties contained in Article VII;

(b)any breach by Seller of its covenants and agreements under this Agreement; or

(c)the Seller’s Retained Obligations.

13.3 Indemnities of Buyer. Effective as of the Closing, except as provided in Section 13.2 and subject to the limitations set forth in Section 13.8, Buyer and its successors and assigns shall assume, be responsible for, shall pay on a current basis, and hereby defends, indemnifies, holds harmless and forever releases Seller and its Affiliates, and all of their respective stockholders, partners, members, directors, officers, managers, employees, attorneys, agents and representatives (collectively, the “Seller Indemnified Parties”) from and against any and all Liabilities, whether or not relating to Third Party claims or incurred in the investigation or defense of any of the same or in asserting, presenting or enforcing any of their respective rights hereunder arising from, based upon, related to or associated with:

(a)any breach by Buyer of its representations or warranties contained in Article VIII;

(b)any breach by Buyer of its covenants and agreements under this Agreement; or

(c)the Assumed Obligations.

Notwithstanding anything contained herein to the contrary, the obligations of Buyer set forth in this Section 13.3 do not extend in any way to any Liability arising from, based upon, related to or associated with the failure of Seller to comply with the terms of the Transaction Documents or applicable Law or the gross negligence or willful misconduct of Seller in connection with any operations or activities conducted by Seller pursuant to the Transaction Documents.

13.4Limitation on Liability.

(a) Seller will have no liability for any indemnification under Section 13.2(a) of this Agreement unless the aggregate amount of all Liabilities for which Seller is liable under Section 13.2(a) of this Agreement exceeds $2,000,000, and then only to the extent such damages or costs exceed $2,000,000; provided that any breach of Section 7.1 (Organization, Existence), 7.2 (Authorization), 7.3 (No Conflicts), 7.6 (Foreign Person), 7.13 (Asset Taxes), 7.14 (Brokers’ Fees) or 7.16 (Partnerships), and any payments in respect thereof will not be limited by this Section 13.4(a).

(b) Notwithstanding anything to the contrary contained in this Agreement, Seller will not be required to indemnify Buyer pursuant to Section 13.2(a) for aggregate Liabilities in excess of $22,500,000 (other than Liabilities pursuant to Section 13.2(a) for any breach of Section 7.1 (Organization, Existence), 7.2 (Authorization), 7.3 (No Conflicts), 7.6 (Foreign Person), 7.13 (Asset Taxes), 7.14 (Brokers’ Fees) or 7.16 (Partnerships)).

13.5Express Negligence.EXCEPT AS OTHERWISE PROVIDED IN SECTION

4.1(c), SECTION 4.1(d) AND SECTION 4.3, THE INDEMNIFICATION, RELEASE, ASSUMED OBLIGATIONS, WAIVER AND LIMITATION OF LIABILITY PROVISIONS PROVIDED FOR IN THIS AGREEMENT WILL BE APPLICABLE WHETHER OR NOT THE LIABILITIES, LOSSES, COSTS, EXPENSES AND DAMAGES IN QUESTION AROSE OR RESULTED SOLELY OR IN PART FROM THE SOLE, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, STRICT LIABILITY OR OTHER FAULT OF OR BY ANY INDEMNIFIED PARTY, BUT NOT THE GROSS NEGLIGENCE OR WILLFUL MISCONDUCT OF SUCH INDEMNIFIED PARTY. BUYER AND SELLER ACKNOWLEDGE THAT THIS STATEMENT COMPLIES WITH THE EXPRESS NEGLIGENCE RULE AND IS CONSPICUOUS.

13.6Exclusive Remedy. Notwithstanding anything to the contrary contained in this

Agreement, and except for fraud or willful misconduct, from and after Closing, Sections 4.1(c), 13.2 and 13.3 contain the Parties’ exclusive remedy against each other with respect to breaches of the representations, warranties, covenants and agreements of the Parties contained in this Agreement and the affirmations of such representations, warranties, covenants and agreements contained in the certificate delivered by each Party at Closing pursuant to Section 10.5 or Section 11.5, as applicable. Except for: (a) the remedies contained in Sections 4.1(c), 13.2 and 13.3; (b) subject to the terms hereof, any other remedies available to the Parties at law or in equity for breaches of provisions of this Agreement other than Article VII, Article VIII, Article IX and Article XIII; and (c) the remedies available at law or in equity in connection with any other document delivered by a Party in connection with the consummation of the transactions contemplated hereby (other than the Assignment delivered by the Parties pursuant to Section 12.3(a) and the certificates delivered by the Parties pursuant to Section 10.5 or Section 11.5, as applicable), from and after Closing, Seller and Buyer each releases, remises, and forever discharges the other and its Affiliates and all such Persons’ stockholders, members, partners, officers, directors, employees, agents, advisors, and representatives from any and all Liabilities at law or in equity, known or unknown, which such Persons might now or subsequently may have, based on, relating to or arising out of this Agreement, the consummation of the transactions contemplated hereby, the ownership, use or operation of the Conveyed Interests prior to the Closing, or the condition, quality, status or nature of the Conveyed Interests prior to the Closing, including rights to contribution under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, breaches of statutory or implied warranties, nuisance or other tort actions, rights to punitive damages, common law rights of contribution, and rights under insurance maintained by Seller or any of its Affiliates (except as provided in Section 5.4.

13.7Indemnification Procedures. All claims for indemnification under Section 4.1(c), Section 13.2 and Section 13.3 must be asserted and resolved as follows:

(a) For purposes of Section 4.1(c) and this Article XIII, the term “Indemnifying Party” when used in connection with particular Liabilities means the Party having an obligation to indemnify another Party or Person(s) with respect to such Liabilities pursuant to Section 4.1(c) and this Article XIII, and the term “Indemnified Party” when used in connection with particular Liabilities means the Party or Person(s) having the right to be indemnified with respect to such Liabilities by another Party pursuant to Section 4.1(c) and this Article XIII.

(b) To make claim for indemnification under Sections 4.1(c), 13.2 or 13.3, an Indemnified Party shall notify the Indemnifying Party in writing of its claim under this Section 13.7, including the details of and basis under this Agreement for its claim (the “Claim Notice”), each with reasonable particularity. In the event that the claim for indemnification is based upon a claim by a Third Party against the Indemnified Party (a “Third Party Claim”), the Indemnified Party shall provide its Claim Notice promptly after the Indemnified Party has actual

knowledge of the Third Party Claim and shall enclose a copy of all papers (if any) served with respect to the Third Party Claim; provided that the failure of any Indemnified Party to give notice of a Third Party Claim as provided in this Section 13.7 will not relieve the Indemnifying Party of its obligations under Sections 4.1(c), 13.2 or 13.3 (as applicable) except to the extent such failure results in insufficient time being available to permit the Indemnifying Party to effectively defend against the Third Party Claim or otherwise materially prejudices the Indemnifying Party’s ability to defend against the Third Party Claim. In the event that the claim for indemnification is based upon a breach of a representation, warranty, covenant or agreement, the Claim Notice must specify the representation, warranty, covenant or agreement that was inaccurate or breached.

(c) In the case of a claim for indemnification based upon a Third Party Claim, the Indemnifying Party will have 30 days from its receipt of the Claim Notice to notify the Indemnified Party whether it admits or denies its liability to defend the Indemnified Party against such Third Party Claim at the sole cost and expense of the Indemnifying Party. The Indemnified Party is authorized, prior to and during such 30 day period, at the expense of the Indemnifying Party, to file any motion, answer or other pleading that it deems necessary or appropriate to protect its interests or those of the Indemnifying Party and that is not prejudicial to the Indemnifying Party.

(d) If the Indemnifying Party admits its liability to defend the Indemnified Party against a Third Party Claim, it will have the right and obligation to diligently defend, at its sole cost and expense, such Third Party Claim. The Indemnifying Party will have full control of such defense and proceedings, including any compromise or settlement thereof. If requested by the Indemnifying Party, the Indemnified Party agrees to reasonably cooperate, at the Indemnifying Party’s sole cost and expense, in contesting any Third Party Claim which the Indemnifying Party elects to contest. The Indemnified Party may participate in, but not control, at its own expense, any defense or settlement of any Third Party Claim controlled by the Indemnifying Party pursuant to this Section 13.7(d) and employ separate counsel reasonably acceptable to Indemnifying Party with respect to such Third Party Claim; provided, however, that such Indemnified Party shall be entitled to participate in any such defense with separate counsel reasonably acceptable to Indemnifying Party if (i) so requested by the Indemnifying Party to participate or (ii) in the reasonable opinion of both counsel to the Indemnified Party and counsel to the Indemnifying Party a conflict or potential conflict exists between the Indemnified Party and the Indemnifying Party that would make such separate representation necessary. An Indemnifying Party shall not, without the written consent of the Indemnified Party: (i) settle any Third Party Claim or consent to the entry of any judgment with respect thereto which does not include an unconditional written release of the Indemnified Party from all Liability in respect of such Third Party Claim; or (ii) settle any Third Party Claim or consent to the entry of any judgment with respect thereto in any manner that may adversely affect the Indemnified Party (other than as a result of

money damages covered by the indemnity).

(e) If the Indemnifying Party does not admit its liability or admits its liability to defend the Indemnified Party against the Third Party Claim, but fails to diligently prosecute or settle such Third Party Claim, then the Indemnified Party will have the right to defend against the Third Party Claim at the sole cost and expense of the Indemnifying Party, with counsel of the Indemnified Party’s choosing, subject to the right of the Indemnifying Party to admit its liability and assume the defense of the Third Party Claim at any time prior to settlement or final determination thereof. If the Indemnifying Party has not yet admitted its liability to defend the Indemnified Party against the Third Party Claim, the Indemnified Party shall send written notice to the Indemnifying Party of any proposed settlement and the Indemnifying Party shall have the option for ten days following receipt of such notice to: (i) admit in writing its liability to indemnify the Indemnified Party from and against the liability and consent to such settlement; (ii) if liability is so admitted, reject, in its reasonable judgment, the proposed settlement; or (iii) deny liability. Any failure to respond to such notice by the Indemnified Party will be deemed to be an election under subsection (iii) above.

(f) In the case of a claim for indemnification not based upon a Third Party Claim, the Indemnifying Party will have 30 days from its receipt of the Claim Notice to: (i) cure the Liabilities complained of; (ii) admit its liability for such Liability; or (iii) dispute the claim for such Liabilities. If the Indemnifying Party does not notify the Indemnified Party within such

30 day period that it has cured the Liabilities or that it disputes the claim for such Liabilities, the amount of such Liabilities will conclusively be deemed a liability of the Indemnifying Party hereunder.

13.8Survival.

(a) The representations and warranties of Seller in Article VII (other than the representations and warranties in Sections 7.1, 7.2, 7.3, 7.6, 7.13, 7.14 and 7.16) and Buyer in Article VIII (other than the representations and warranties in Sections 8.1, 8.2, 8.3, 8.8, 8.9 and

8.10), will in each case terminate on the date that is the 12 month anniversary of the Closing Date. The representations and warranties of Seller in Sections 7.13 and 7.16 will survive the Closing for the applicable statute of limitations plus 60 days. Subject to the foregoing, all other representations and warranties, agreements and covenants set forth in this Agreement (including Sections 7.1, 7.2, 7.3, 7.6, 7.14, 8.1, 8.2, 8.3, 8.8, 8.9 and 8.10) will survive the Closing without time limit except to the extent that the survival thereof is expressly limited herein. Representations, warranties, covenants and agreements will be of no further force and effect after the date of their expiration, provided that there will be no termination of any bona fide claim asserted pursuant to this Agreement with respect to such a representation, warranty, covenant or agreement prior to its expiration date.

(b) The indemnities in Sections 13.2(a), 13.2(b), 13.3(a) and 13.3(b) will terminate as of the termination date of each respective representation, warranty, covenant or agreement that is subject to indemnification. Buyer’s indemnities set forth in Section 4.1(c) and Section 13.3(c) will survive the Closing without time limit. Seller’s indemnity set forth in Section 13.2(c) will survive the Closing without time limit. Notwithstanding the foregoing, there will be no termination of any bona fide claim asserted pursuant to the indemnities in Sections

13.2(a), 13.2(b), or 13.2(c) or Sections 13.3(a) or 13.3(b) prior to the date of termination for such indemnity.

13.9 Non-Compensatory Damages. None of the Buyer Indemnified Parties nor the Seller Indemnified Parties will be entitled to recover from Seller or Buyer, or their respective Affiliates, any indirect, consequential, punitive, exemplary, remote or speculative damages or damages for lost profits of any kind (other than lost profits proven to be direct damages) arising under or in connection with this Agreement or the transactions contemplated hereby, except to the extent any such Party suffers such damages to a Third Party, which damages (including costs of defense and reasonable attorneys’ fees incurred in connection with defending against such damages) will not be excluded by this provision as to recovery hereunder. Subject to the preceding sentence, Buyer, on behalf of each of the Buyer Indemnified Parties, and Seller, on behalf of each of the Seller Indemnified Parties, waive any right to recover punitive, special, indirect, exemplary, consequential damages, remote or speculative, including damages for lost profits of any kind (other than lost profits proven to be direct damages), arising in connection with or with respect to this Agreement or the transactions contemplated hereby.

13.10 Waiver of Right to Rescission. Seller and Buyer acknowledge that, following Closing, the payment of money, as limited by the terms of this Agreement, will be adequate compensation for breach of any representation, warranty, covenant or agreement contained herein or for any other claim arising in connection with or with respect to the transactions contemplated by this Agreement. As the payment of money will be adequate compensation, following Closing, Buyer and Seller waive any right to rescind this Agreement or any of the transactions contemplated hereby.

13.11 Insurance, Taxes. The amount of any Liabilities for which any Party is entitled to indemnification under this Agreement will be reduced by any corresponding: (a) tax benefit actually recognized by such Party, computed on a with and without basis, as certified by such Party’s external accountants (it being understood that such Party will not be required to share information on its other sources of income and loss with the other Party); or (b) insurance proceeds received by such Party with respect to such Liabilities. Each Party agrees to use commercially reasonable efforts to pursue any proceeds available under any insurance policies maintained by such Party covering such Liabilities.

ARTICLE XIV

TERMINATION, DEFAULT AND REMEDIES

14.1 Right of Termination. This Agreement and the transactions contemplated herein may be terminated at any time prior to Closing:

(a)by the mutual prior written consent of Seller and Buyer;

(b) by either Seller or Buyer if Closing has not occurred on or before September 30, 2014 (the “Outside Date”) or such later date as agreed to in writing by Seller and Buyer;

(c) by Buyer, upon delivery of written notice to Seller at any time prior to Closing in the event that Seller has breached in any material respect any representation, warranty or covenant contained in this Agreement such that a closing condition set forth in Article X would not be satisfied, Buyer has notified Seller of the breach in writing, and the breach has continued without cure until the earlier of (i) the Outside Date and (ii) the date that is 30 days after the written notice of breach;

(d) by Seller, upon delivery of written notice to Buyer at any time prior to Closing in the event that Buyer has breached in any material respect any representation, warranty or covenant contained in this Agreement such that a closing condition set forth in Article XI

would not be satisfied, Seller has notified Buyer of the breach in writing, and the breach has continued without cure until the earlier of (i) the Outside Date and (ii) the date that is 30 days after the written notice of breach; and

(e) by either Buyer or Seller, upon written notice to the other, if any court of competent jurisdiction or other competent Governmental Authority shall have issued any Law or taken any other action permanently restraining, enjoining or otherwise prohibiting the transactions contemplated by this Agreement and such Law or other action shall have become final and non-appealable;

provided, however, that no Party will be entitled to terminate this Agreement under this Section

14.1 if such Party is in material breach of its covenants or agreements hereunder.

14.2Effect of Termination.

(a) If the obligation to close the transactions contemplated by this Agreement is terminated pursuant to any provision of Section 14.1 hereof, then, (i) except for the provisions of Article I, Sections 4.1(c) through 4.1(e), 4.2, 4.3, 9.4, 13.9, this Section 14.2, Article XV (other than Sections 15.2(b), 15.3, 15.4, 15.10 and 15.11) and such of the defined terms in Appendix I to give context to the surviving provisions, this Agreement will forthwith become void and the Parties will have no liability or obligation hereunder, except as provided in such surviving provisions or to the extent such termination results from fraud or willful breach by any Party hereto of any of its representations and warranties or any of its covenants or agreements contained in this Agreement and (ii) Seller shall be free immediately to enjoy all rights of

ownership of the Conveyed Interests and to sell, transfer, encumber or otherwise dispose of the Conveyed Interests to any Person without any restriction under this Agreement.

(b) If the transactions contemplated by this Agreement are terminated by Seller pursuant to Section 14.1(d), then, in such event, Buyer and Seller shall promptly deliver duly executed joint written instructions to the Escrow Agent directing the Escrow Agent to release the Deposit to Seller (which shall be free of any claims by Buyer thereto); provided that if the Deposit is released to Seller pursuant to this Section 14.2(b), the Deposit shall be Seller’s sole and exclusive remedy as liquidated damages and Seller shall not have the right to seek out any other remedy from Buyer, including specific performance. It is expressly stipulated by the Parties that the actual amount of damages resulting from such a termination would be difficult if not impossible to determine accurately because of the unique nature of this Agreement, the unique nature of the Assets, the uncertainties of applicable commodity markets and differences of opinion with respect to such matters, and that the liquidated damages provided for in this Agreement are a reasonable estimate by the parties of such damages.

(c) If this Agreement is terminated by the mutual written agreement of the Parties, or if the Closing does not occur for any reason other than a termination by Seller pursuant to Section 14.1(d), then Buyer and Seller shall promptly deliver duly executed joint written instructions to the Escrow Agent directing the Escrow Agent to release the Deposit to Buyer (which shall be free of any claims by Seller with respect thereto).

14.3 Return of Documentation and Confidentiality. Promptly after the termination of this Agreement, Buyer shall destroy or return to Seller all title, engineering, geological and geophysical data, environmental assessments and/or reports, maps and other information furnished by Seller to Buyer or, if not prepared by Buyer, prepared by or on behalf of Buyer in connection with Buyer’s due diligence investigation of the Conveyed Interests and, if Buyer elects to destroy any such information, an officer of Buyer shall certify the destruction of such information to Seller in writing.

ARTICLE XV

MISCELLANEOUS

15.1 Appendices, Exhibits and Schedules. All of the Appendices, Exhibits and Schedules referred to in this Agreement are hereby incorporated into this Agreement by reference and constitute a part of this Agreement. Each Party to this Agreement and its counsel has received a complete set of Appendices, Exhibits and Schedules prior to and as of the execution of this Agreement.

15.2Expenses and Taxes.

(a) Except as otherwise specifically provided, all fees, costs and expenses incurred by the Parties in negotiating this Agreement or in consummating the transactions contemplated by this Agreement will be paid by the Party incurring the same, including legal and accounting fees, costs and expenses.

(b) Seller shall retain responsibility for, and shall bear and pay, all federal income taxes, state income taxes, and similar taxes (including any applicable interest or penalties) incurred or imposed on Seller with respect to the transactions described in this Agreement. Buyer shall bear all required documentary, filing and recording fees and expenses in connection with the filing and recording of the assignments, conveyances or other instruments required to convey title to the Conveyed Interests to Buyer. Buyer shall bear and pay any sales, use, transfer and similar taxes, including any applicable interest or penalties, incurred or imposed with respect to the transactions described in this Agreement (collectively, “Transfer Taxes”), provided that Seller shall pay or cause to be paid to the applicable Governmental Authorities any Transfer Taxes that it is required by Law to collect and remit, and Buyer shall indemnify and hold Seller harmless from and against such Transfer Taxes within 30 days of Seller’s written demand therefor. Seller and Buyer shall reasonably cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

(c) Seller will be allocated and shall bear all Asset Taxes assessed with respect to the ownership and operation of the Conveyed Interests (i) for any period ending prior to the Effective Time (ii) in the case of any such Asset Tax pertaining to a Straddle Period that is based upon income, sales, revenue, production, or similar items or other such Asset Tax not described in clause (iii), the amount of such Asset Tax that is attributable to the pre-Effective Time portion of such Straddle Period, determined on the basis of an interim closing of the books as of the Effective Time, and (iii) in the case of any such ad valorem, property, or similar Asset Tax pertaining to a Straddle Period, the portion of such Asset Tax determined by multiplying the total amount of such Asset Tax for such Straddle Period by a fraction, the numerator of which is the number of days in the Straddle Period ending on the day immediately prior to the day on which the Effective Time occurs and the denominator of which is the number of days in the entire Straddle Period. All Asset Taxes not described in the preceding sentence with respect to the ownership or operation of the Conveyed Interests will be allocated to and shall be borne by Buyer. To the extent the actual amount of an Asset Tax attributable to a Straddle Period is not determinable at Closing, Buyer and Seller shall utilize the most recent information available in estimating the amount of such Asset Tax for purposes of Section 3.3. Upon determination of the actual amount of such Asset Tax, to the extent not taken into account in the Final Settlement Statement, Seller shall pay to Buyer, or Buyer shall pay to Seller, as appropriate, any amount necessary to cause each of Seller and Buyer to bear its appropriate share of such the Asset Tax as determined pursuant to this Section 15.2(c). For the avoidance of doubt, Buyer shall bear and pay all ad valorem, property, and similar Asset Taxes imposed on or with respect to the Conveyed Interests for Taxable periods or assessments beginning on or after the day on which the Effective Time occurs.

(d) Seller and Buyer agree to furnish or cause to be furnished to the other, upon request, as promptly as practicable, such information and assistance relating to the Conveyed Interests, including access to books and records, as is reasonably necessary for the filing of all tax returns by Seller or Buyer, the making of any election relating to taxes, the preparation for any audit by any taxing authority and the prosecution or defense of any claim, suit or proceeding, relating to any tax. Each of Seller and Buyer shall retain all books and records with respect to taxes pertaining to the Conveyed Interests for a period of at

least seven years from the Closing Date. Seller and Buyer shall cooperate fully with each other in the conduct of any audit, litigation or other proceeding relating to taxes involving the Conveyed Interests.

15.3Tax Treatment.

(a) The Parties intend and expect that the transactions contemplated by this Agreement, the Development Agreement and the other Transaction Documents, taken together, will be treated, for purposes of federal income taxation and for purposes of certain state income tax laws that incorporate or follow federal income tax principles (“Tax Purposes”), as resulting in the creation of a partnership (the “Tax Partnership”) in which Buyer and Seller are treated as partners. Accordingly, for Tax Purposes: (i) the Tax Partnership will be treated from and after Closing as: (x) holding: (A) 100% of the Parties’ interests in the Subject Oil and Gas Assets; (B) any other upstream oil and gas assets acquired by the Parties jointly pursuant to the Development Agreement; and (C) any cash held in any Tax Partnership Account and: (y) engaging in all activities of the Parties with respect to the aforementioned assets; (ii) Swift will be treated as contributing to the Tax Partnership at Closing all of its interests in the Contributed Properties and as providing its undertaking to fund, when due, the costs and expenses allocable to it under the Development Agreement, all in exchange for an interest in the Tax Partnership (except as provided in clause (iv) of this sentence); (iii) Saka will be treated as contributing to the Tax Partnership at Closing (by deposit into the Tax Partnership Account) the Closing Cash Amount (as adjusted) and the Interim Period Carried Costs Amount and as undertaking to fund, when due, the costs and expenses allocable to it under the Development Agreement (including the Carried Costs Obligation), all in exchange for an interest in the Tax Partnership, (iv) the Development Agreement permits Swift to withdraw from the Tax Partnership Account the

Closing Cash Amount and the Interim Period Carried Costs Amount, and the amounts so withdrawn shall be treated as amounts received by Swift as a payment for the a portion of the property it transferred to the Tax Partnership in accordance with Treasury Regulations Section 1.707-3, it being understood that no portion of such amounts will be treated as described in Treasury Regulations Section 1.707-4(d); (v) from and after its commencement the Tax Partnership will be treated as realizing all items of income or gain and incurring all items of costs or expense attributable to the acquisition, ownership, operation or disposition of the Joint Interests and Tax Partnership Accounts that are subject to the Tax Partnership, notwithstanding that such items are realized, paid or incurred by the Parties individually, with any reimbursement or direct payment between the Parties treated as having been contributed to the Tax Partnership and used by the Tax Partnership to make the related expenditure or to reimburse the receiving Party as appropriate. The governing terms and conditions of the Tax Partnership (the “Tax Partnership Agreement”) are set forth in the form thereof to be executed at Closing, attached as

Exhibit E.

(b) Any payments made pursuant to Article XIII shall constitute an adjustment of the Allocable Amount for Tax Purposes and shall be treated as such by Buyer and Seller on their tax returns to the extent permitted by law.

15.4 Value Allocations for Tax Purposes. Seller and Buyer agree that the portion, if any, of the Closing Cash Amount, the Interim Period Carried Costs Amount and the Assumed Obligations including, for the avoidance of doubt, any deposit under Section 3.2, in each case that are treated as consideration for a sale transaction (collectively, the “Allocable Amount”) will be allocated among the Subject Oil and Gas Assets for federal and state income tax purposes. The initial draft of such allocations will be prepared by Seller in a manner consistent with the Allocated Values and Section 15.3 and will be provided to Buyer concurrently with the delivery of the Final Settlement Statement. Seller and Buyer shall then cooperate to prepare a final Schedule of any Allocable Amount among such Subject Oil and Gas Assets, which will also be materially consistent with the Allocated Values (as adjusted, the “Allocation Schedule”). The Allocation Schedule must be updated to reflect any adjustments to the Allocable Amount. If agreed by the Parties, the allocation of the Allocable Amount will be reflected on a completed Internal Revenue Service Form 8594 (Asset Acquisition Statement under Section 1060), which Form will be timely filed separately by Seller and the Buyer with the Internal Revenue Service pursuant to the requirements of Section 1060(b) of the Code. The procedures of Section 3.6 will be applied in the event of a dispute in the preparation of the Allocation Schedule. Each Party agrees not to take any position inconsistent with Section 15.3, this Section 15.4 or the allocations set forth in the Allocation Schedule unless required by applicable Law or with the consent of the other Party.

15.5 Assignment. This Agreement may not be assigned by either Party without prior written consent of the other Party; provided, however, that Buyer may assign this Agreement to any of its Affiliates without the prior written consent of Seller. No assignment of any rights hereunder by a Party will relieve the other Party of any obligations (including indemnity obligations) and responsibilities hereunder.

15.6 Preparation of Agreement. Both Seller and Buyer and their respective counsel participated in the preparation of this Agreement. In the event of any ambiguity in this Agreement, no presumption will arise based on the identity of the draftsman of this Agreement.

15.7 Publicity. Seller and Buyer shall consult with each other with regard to all press releases or other public announcements issued or made at or prior to the Closing concerning this Agreement or the transactions contemplated herein, and, except as may be required by applicable Laws or the applicable rules and regulations of any Governmental Authority or stock exchange, neither Buyer nor Seller shall issue any such press release or other publicity without the prior written consent of the other Party, which must not be unreasonably withheld. The Parties shall be obligated to hold all specific terms and provisions of this Agreement strictly confidential until the expiration of two years after the Closing under this Agreement; provided, however, that the foregoing will not: (a) restrict disclosures by Buyer or Seller that are required by applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the disclosing Party or its Affiliates; provided, such disclosures will be made only to the extent required thereunder; (b) prevent Buyer or Seller from recording the Assignment and any federal or state assignments delivered at Closing or from complying with any disclosure requirements of Governmental Authorities that are applicable to the transfer of the Conveyed Interests from Seller to Buyer; (c) prevent Buyer or Seller from making any disclosure of information relating to this Agreement if made in a manner, under conditions and to Persons that would be permitted under the Confidentiality Agreement so long as such Person continues to hold such information confidential on the same terms as set forth in this Section 15.7; and (d) prevent Seller from making disclosures in connection with complying with Preferential Purchase Rights and other transfer restrictions applicable to the transactions contemplated hereby.

15.8 Notices. All notices and communications required or permitted to be given hereunder, will be sufficient in all respects if given in writing and delivered personally, or sent by bonded overnight courier, or mailed by Federal Express or United Parcel Service Express Delivery, or sent by facsimile transmission (provided any such facsimile transmission is confirmed either orally or by written confirmation), addressed to the appropriate Person at the address for such Person shown below:

If to Seller:

Swift Energy Operating, LLC

16825 Northchase Dr., Suite 400

Houston, Texas 77060

Attention: Michael S. Coffield

Fax: (281) 874-2808

Email: Mike.Coffield@swiftenergy.com

With a copy to (which shall not constitute notice):

Swift Energy Operating, LLC

16825 Northchase Dr., Suite 400

Houston, Texas 77060

Attention: Larry A. Baillargeon

Fax: (281) 874-2701

Email: Larry.Baillargeon@swiftenergy.com

With a copy to (which shall not constitute notice): Latham & Watkins LLP

811 Main Street, Suite 3700

Houston, Texas 77002

Attention: Michael P. Darden

Fax: (713) 546-5401

Email: Michael.Darden@lw.com

If to Buyer:

Saka Energi Fasken LLC

The Energy, 11th - 12th Floor, SCBD Lot 11A Jl. Jenderal Sudirman Kav. 52-53

Jakarta 12190, Indonesia Attention: Tumbur Parlindungan Fax: +6221.2995.1001

Email: tumbur.parlindungan@sakaenergi.com

With a copy to:

Saka Energi Fasken LLC

The Energy, 11th - 12th Floor, SCBD Lot 11A Jl. Jenderal Sudirman Kav. 52-53

Jakarta 12190, Indonesia Attention: Firman A. Yaman Fax: +6221.2995.1001

Email: firman.yaman@sakaenergi.com

Any notice given in accordance herewith will be deemed to have been given when delivered to the addressee in person, or by courier, or transmitted by facsimile transmission during normal business hours, or upon actual receipt by the addressee after such notice has either been delivered to an overnight courier or deposited in with Federal Express or United Parcel Service, as the case may be. Any Person may change their contact information for notice by giving written notice to the other Persons set forth in this Section 15.8 in the manner provided in this Section 15.8. If the date specified in this Agreement for giving any notice or taking any action is not a Business Day (or if the period during which any notice is required to be given or

any action taken expires on a date which is not a Business Day), then the date for giving such notice or taking such action (and the expiration date of such period during which notice is required to be given or action taken) will be the next day which is a Business Day.

15.9 Further Cooperation. After the Closing, Buyer and Seller shall execute and deliver, or shall cause to be executed and delivered from time to time, such further instruments of conveyance and transfer, and shall take such other actions as any Party may reasonably request, to convey and deliver the Conveyed Interests to Buyer, to perfect Buyer’s title thereto, and to accomplish the orderly transfer of the Conveyed Interests to Buyer in the manner contemplated by this Agreement.

15.10 Filings. Promptly after Closing, Buyer shall record the Assignments of the Conveyed Interests and all state/federal assignments executed at the Closing in all applicable real property records and/or, if applicable, all state or federal agencies.

15.11 Consents and Approvals. Promptly after Closing, Seller shall:

(a) take all commercially reasonable steps necessary or desirable to promptly obtain Customary Post-Closing Consents, including making all filings with and giving all notices to Governmental Authorities or any other Person required of Seller to consummate the transactions contemplated by this Agreement;

(b) provide such other information and communications to Governmental Authorities or other Persons as Buyer may reasonably request in connection with such transactions;

(c) cooperate with Buyer as promptly as practicable in obtaining all Customary Post-Closing Consents, including making all filings with, and giving all notices to, Governmental Authorities and other Persons required of Buyer to consummate such transactions; and

(d) provide prompt notice to Buyer when any Customary Post-Closing Consent is obtained, taken, made or given, as applicable, and advise Buyer of any communications (and, unless precluded by Law, provide copies of any such written communications) with any Governmental Authority or other Person relating to such transactions.

15.12 Entire Agreement; Non-Reliance; Conflicts. THIS AGREEMENT, THE APPENDICES, EXHIBITS AND SCHEDULES HERETO, THE TRANSACTION DOCUMENTS AND THE CONFIDENTIALITY AGREEMENT COLLECTIVELY CONSTITUTE THE ENTIRE AGREEMENT AMONG THE PARTIES PERTAINING TO THE SUBJECT MATTER HEREOF AND SUPERSEDE ALL PRIOR AGREEMENTS, UNDERSTANDINGS, NEGOTIATIONS, AND DISCUSSIONS, WHETHER ORAL OR WRITTEN, OF THE PARTIES PERTAINING TO THE SUBJECT MATTER OF THIS AGREEMENT. THERE ARE NO WARRANTIES, REPRESENTATIONS, OR OTHER AGREEMENTS BETWEEN THE PARTIES RELATING TO THE SUBJECT MATTER OF THIS AGREEMENT EXCEPT AS SPECIFICALLY SET FORTH IN THIS AGREEMENT OR THE TRANSACTION DOCUMENTS, AND NO PARTY WILL BE BOUND BY OR LIABLE FOR ANY ALLEGED REPRESENTATION, PROMISE, INDUCEMENT, OR STATEMENTS OF INTENTION NOT SO SET FORTH. EACH PARTY ACKNOWLEDGES THAT, IN ENTERING INTO THIS AGREEMENT, IT HAS RELIED SOLELY ON THE PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE EXPRESSLY SET FORTH IN THIS AGREEMENT AND THE TRANSACTION DOCUMENTS AND THAT NO PARTY HAD ANY DUTY TO MAKE ANY PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE NOT EXPRESSLY SET FORTH IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS. EACH PARTY ALSO ACKNOWLEDGES THAT, IN ENTERING THIS AGREEMENT, IT HAS NOT RELIED ON ANY PROMISES, AGREEMENTS, STATEMENTS OR REPRESENTATIONS THAT ARE NOT EXPRESSLY SET FORTH IN THIS AGREEMENT OR IN THE TRANSACTION DOCUMENTS. IN THE EVENT OF A CONFLICT BETWEEN: (A) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY APPENDIX, SCHEDULE OR EXHIBIT HERETO; OR (B) THE TERMS AND PROVISIONS OF THIS AGREEMENT AND THE TERMS AND PROVISIONS OF ANY TRANSACTION DOCUMENT, THE TERMS AND PROVISIONS OF THIS AGREEMENT WILL GOVERN AND CONTROL, PROVIDED, HOWEVER, THAT THE INCLUSION IN ANY OF THE APPENDICES, SCHEDULES OR EXHIBITS HERETO OR ANY TRANSACTION DOCUMENT OF TERMS AND PROVISIONS NOT ADDRESSED IN THIS AGREEMENT WILL NOT BE DEEMED A CONFLICT, AND ALL SUCH ADDITIONAL PROVISIONS WILL BE GIVEN FULL FORCE AND EFFECT, SUBJECT TO THE PROVISIONS OF THIS SECTION 15.12.

15.13 Successors and Permitted Assigns. This Agreement will be binding upon and inure to the benefit of the Parties and their successors and permitted assigns.

15.14 Parties in Interest. Nothing in this Agreement will entitle any Person other than the Parties, or the Parties’ respective related Indemnified Parties hereunder any claim, cause of action, remedy or right of any kind; provided, that only a Party will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of its related Indemnified Parties (but will not be obligated to do so).

15.15 Amendment. This Agreement may be amended, restated, supplemented or otherwise modified only by an instrument in writing executed by all of the Parties and expressly identified as an amendment, restatement, supplement or modification.

15.16 Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties, or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of any Party, or their respective officers, employees, agents or representatives and no failure by a Party to exercise any of its rights under this Agreement will operate as a waiver thereof or affect in any way the right of such Party at a later time to enforce the performance of such provision. No waiver by any Party of any condition, or any breach of any term, covenant, representation, or warranty contained in this Agreement, in any one or more instances, will be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation, or warranty. The rights of the Parties under this Agreement will be cumulative, and the exercise or partial exercise of any such right will not preclude the exercise of any other right.

15.17 Governing Law; Jurisdiction; Venue; Jury Waiver. THIS AGREEMENT AND THE LEGAL RELATIONS AMONG THE PARTIES WILL BE GOVERNED AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS, EXCLUDING ANY CONFLICTS OF LAW RULE OR PRINCIPLE THAT MIGHT REFER CONSTRUCTION OF SUCH PROVISIONS TO THE LAWS OF ANOTHER JURISDICTION. THE PARTIES CONSENT TO THE EXERCISE OF JURISDICTION IN PERSONAM BY THE FEDERAL COURTS OF THE UNITED STATES OF AMERICA LOCATED IN HOUSTON, TEXAS OR, IF SUCH FEDERAL COURTS DO NOT HAVE JURISDICTION, THE STATE COURTS LOCATED IN HOUSTON, TEXAS FOR ANY ACTION ARISING OUT OF THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS, OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY. ALL ACTIONS OR PROCEEDINGS WITH RESPECT TO, ARISING DIRECTLY OR INDIRECTLY IN CONNECTION WITH, OUT OF, RELATED TO, OR FROM THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY WILL BE EXCLUSIVELY LITIGATED IN COURTS HAVING SITES IN HOUSTON, TEXAS. EACH PARTY HERETO WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY ACTION, SUIT OR PROCEEDING ARISING OUT OF OR RELATING TO THIS AGREEMENT, THE OTHER TRANSACTION DOCUMENTS OR ANY TRANSACTION CONTEMPLATED HEREBY OR THEREBY.

15.18 Severability. If any term or other provision of this Agreement is invalid, illegal, or incapable of being enforced by any rule of Law or public policy, all other conditions and provisions of this Agreement will nevertheless remain in full force and effect so long as the economic or legal substance of the transactions contemplated hereby is not affected in any adverse manner to any Party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the Parties shall negotiate in good faith to modify this Agreement so as to effect the original intent of the Parties as closely as possible in an acceptable manner to the end that the transactions contemplated hereby are fulfilled to the extent possible.

15.19 Counterparts. This Agreement may be executed in any number of counterparts, and each such counterpart hereof will be deemed to be an original instrument, but all of such counterparts will constitute for all purposes one agreement. Any signature hereto delivered by a Party by facsimile transmission or other electronic transmission will be deemed an original signature hereto.

15.20 Specific Performance. Except as set forth in Section 14.2(b), the Parties agree that if any of the provisions of this Agreement were not performed in accordance with their specific terms, irreparable damage may occur, no adequate remedy at law may exist and damages may be difficult to determine, and the Parties will be entitled to seek specific performance of the terms hereof and immediate injunctive relief, in addition to any other remedy available at law or in equity.

15.21 Accounting for Conveyed Interests. Notwithstanding anything to the contrary in this Agreement or any of the Transaction Documents, Buyer and Seller acknowledge and agree that: (i) if any Conveyed Interest is withheld by Seller and permanently deemed to be an

Excluded Asset (whether in connection with any Title Defect, Preferential Purchase Right, Consent or Environmental Defect), then (x) Buyer shall not be responsible for, and Seller shall reimburse Buyer to the extent paid by Buyer, the Allocated Value of such Conveyed Interest and any costs or expenses in connection with such Conveyed Interest, and (y) Buyer shall not be entitled to any revenues in connection with such Conveyed Interest; and (ii) if any Conveyed Interest is withheld by Seller and is thereafter conveyed to Buyer pursuant to the terms of this Agreement, then all costs, expenses and revenues with respect to such Conveyed Interest shall be shared between Buyer and Seller as if such interest had been conveyed as of Closing.

[Remainder of page intentionally left blank. Signature page follows.]

IN WITNESS WHEREOF, Seller and Buyer have executed this Agreement on the date first above written.

SELLER:

SWIFT ENERGY OPERATING, LLC

By:/s/ Bruce H. Vincent Name: Bruce H. Vincent

Title: President

BUYER:

SAKA ENERGI FASKEN LLC

By:/s/ Tumbur Parlindungan

Name: Tumbur Parlindungan

Title: President

EX-10.2

EXHIBIT 10.2

FOURTH AMENDMENT AND CONSENT

This FOURTH AMENDMENT AND CONSENT (“Amendment”) dated as of April 30, 2014 (the “Effective Date”), is by and among Swift Energy Company, a Texas corporation (“Swift Co”), and Swift Energy Operating, LLC, a Texas limited liability company (“SwiftLLC”; and together with Swift Co, individually, a “Borrower” and, collectively, the “Borrowers”), the Lenders party hereto, and JPMorgan Chase Bank, N.A., as administrative agent for the Lenders (in such capacity, the “Administrative Agent”).

WHEREAS, the Borrowers, the lenders from time to time party thereto (the “Lenders”), and the Administrative Agent are parties to the Second Amended and Restated Credit Agreement dated as of September 21, 2010, as amended by the First Amendment and Consent thereto dated as of May 12, 2011, the Second Amendment thereto dated as of October 2, 2012 and the Third Amendment thereto dated as of October 31, 2012 (as so amended, and as further amended, restated or otherwise modified from time to time, the “Credit Agreement”); and

WHEREAS, the parties hereto have agreed to make certain amendments to and consents under the Credit Agreement as provided for herein;

NOW THEREFORE, in consideration of the premises and the mutual covenants, representations and warranties contained herein, and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto hereby agree as follows:

AGREEMENT

Section 1. Defined Terms. Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning given such term in the Credit Agreement.

Section 2. Consent. The Administrative Agent and the Lenders hereby consent to the disposition in one or more transactions of (x) all of the Oil and Gas Properties described on Exhibit Aattached hereto (the “CLAETX Properties”) and (y) up to 50% of the Borrowers’ and their respective Subsidiaries’ interests in the Oil and Gas Properties described on Exhibit B attached hereto (the “Fasken Properties”) and agree that such dispositions (collectively, the “Asset Sales”) shall not constitute a Default or Event of Default under Section 7.1(b)of the Credit Agreement as a result of a violation of Section 6.4of the Credit Agreement; provided, that

(a)notwithstanding the consent set forth in this Section 2, each Asset Sale shall be included in the calculation of the dispositions permitted under Section 6.4(e) of the Credit Agreement, (b) notwithstanding the consent set forth in this Section 2, each Asset Sale shall trigger an automatic reduction of the Borrowing Base pursuant to Section 2.11(e)of the Credit Agreement, (c) the sum of the Loan Balance and the L/C Exposure does not exceed the Borrowing Base before or after giving effect to any such Asset Sale, any automatic reduction in the Borrowing Base pursuant to Section 2.11(e) and any mandatory prepayment pursuant to Section 2.12(b), (d) no Default or Event of Default has occurred and is continuing before or after giving effect to any such Asset Sale and (e) in connection with each Asset Sale, the Borrowers enter into a letter of intent, definitive purchase and sale agreement, or another similar instrument for the Asset Sale

#4523609.6

prior to the one-year anniversary of the Effective Date of this Amendment. The express consent set forth in this Section 2 is limited to the extent described herein and shall not be construed to be a consent to or a permanent waiver of any terms, provisions, covenants, warranties or agreements contained in the Credit Agreement or in any of the other Loan Documents, unless expressly provided so herein. The Administrative Agent and the Lenders reserve the right to exercise any rights and remedies available to them in connection with any present or future defaults with respect to the Credit Agreement or any other provision of any Loan Document.

Section 3.Amendments to the Credit Agreement.

(a)The definition of “Compliance Certificate” in Section 1.2of the Credit Agreement is hereby amended and restated in its entirety as follows:

“Compliance Certificate and Hedging Report” shall mean each certificate substantially in the form attached hereto as Exhibit IV, signed by any Responsible Officer and furnished to the Administrative Agent from time to time in accordance with the terms hereof.

(b)The definition of “Permitted Liens” in Section 1.2of the Credit Agreement is hereby amended by deleting clause (l).

(c)Section 1.2of the Credit Agreement is hereby amended by adding the following new defined terms in their appropriate alphabetical order:

“Approved Counterparty” means (a) any Lender or any Affiliate of a Lender or (b) any other Person that has (or the credit support provider of such Person has) a long term senior unsecured debt or corporate credit rating of A- or A3 by S&P or Moody’s (or their equivalent) or higher.

“Borrowing Base Hedge” means any hedge position or Hedging Agreement considered by the Administrative Agent in determining the then effective Borrowing Base.

(d)Section 5.4of the Credit Agreement is hereby amended and restated in its entirety as follows:

5.4 Compliance Certificate and Hedging Report. Concurrently with the furnishing of the Financial Statements submitted pursuant to Sections 5.2 and 5.3, provide the Administrative Agent a Compliance Certificate and Hedging Report; and concurrently with the furnishing of the Financial Statements submitted pursuant to Section 5.3 if requested by any Lender, provide each Lender a certificate in customary form from the independent certified public accountants for the Borrower stating that their audit has not disclosed the existence of any Default or Event of Default or, if their audit has disclosed the existence of any Default or Event of Default, specifying the nature, period of existence and status thereof.

(e)Clause (h)of Section 6.1of the Credit Agreement is hereby amended and restated in its entirety as follows:

(h) obligations with respect to Hedging Agreements permitted under Section 6.21.

(f)Clause (e)of Section 6.4of the Credit Agreement is hereby amended and restated in its entirety as follows:

(e) the sale or other disposition of Oil and Gas Properties included in the calculation of the Borrowing Base; provided that, (i) the sum of the aggregate Release Price of such Oil and Gas Properties and all other Oil and Gas Properties included in the calculation of the Borrowing Base disposed of since the most recent scheduled Borrowing Base determination pursuant to Section 2.11 plus aggregate Borrowing Base value attributed by the Required Lenders to all Borrowing Base Hedges that have been subject to novations, assignments, amendments, modifications or terminations since the most recent scheduled Borrowing Base determination pursuant to Section 2.11 does not exceed 10% of the then current Borrowing Base, (ii) no Default or Event of Default has occurred and is continuing and (iii) the sum of the Loan Balance and the L/C Exposure does not exceed the Borrowing Base before or after giving effect to such disposition, any automatic reduction in the Borrowing Base pursuant to Section 2.11(e) and any mandatory prepayment pursuant to Section 2.12(b); and

(g)Article VI of the Credit Agreement is hereby amended by adding the following as a new Section 6.21:

6.21 Hedging Agreements. No Borrower will, or will it permit any of its Subsidiaries to, enter into or maintain any Hedging Agreement, except Hedging Agreements entered into in the ordinary course of business with any Approved Counterparty and not for speculative purposes to:

(a)hedge or mitigate crude oil, natural gas, and natural gas liquids price risks to which any Borrower or any Subsidiary has actual exposure; provided that such Hedging Agreement (i) does not have a term greater than sixty (60) months from the date such Hedging Agreement is entered into, and (ii) at any time, when aggregated with all other Hedging Agreements in effect on any date of determination, would not cause the aggregate notional volume per month for each of crude oil, natural gas, and natural gas liquids, calculated separately, under all Hedging Agreements then in effect to exceed (x) eighty percent (80%) of the “forecasted production from total proved reserves” (as defined below) of the Borrowers and their Subsidiaries for any month during the first two (2) years of the forthcoming five year period or (y) eighty percent (80%)

of the “forecasted production from proved developed producing reserves” (as defined below) of the Borrowers and their Subsidiaries for any month during the last three (3) years of the forthcoming five year period, and

(b)effectively cap, collar or exchange interest rates (from fixed to floating rates, from one floating rate to another floating rate or otherwise) with respect to any interest-bearing liability or investment of the Borrowers and their Subsidiaries; providedthat, no such Hedging Agreement shall require any Borrower or any Subsidiary to put up money, assets, or other security (other than Liens contemplated by clause (j) of the definition of Permitted Liens) against the event of its nonperformance prior to actual default by such Borrower or such Subsidiary in performing its obligations thereunder.

As used in this Section, (x) “forecasted production from total proved reserves” means the forecasted production of crude oil, natural gas and natural gas liquids as reflected in the most recent Reserve Report delivered to the Administrative Agent pursuant to Section 5.5, after giving effect to any pro forma adjustments for the consummation of any acquisitions or dispositions since the effective date of such Reserve Report and (y) “forecasted production from proved developed producing reserves” means the forecasted production of crude oil, natural gas, and natural gas liquids from proved developed producing reserves as reflected in the most recent Reserve Report delivered to the Administrative Agent pursuant to Section 5.5, after giving effect to any pro forma adjustments for the consummation of any acquisitions or dispositions since the effective date of such Reserve Report.

Notwithstanding the forgoing, if any Borrower or any Subsidiary is not in compliance with clause (a)(ii) above, such compliance shall not cause a Default hereunder unless Borrower fails to, within 30 days after the earlier of notice thereof by the Administrative Agent to any Borrower or knowledge thereof by any Borrower, either (1) deliver a Reserve Report evidencing “forecasted production from total proved reserves” and “forecasted production from proved developed producing reserves” that result in compliance with clause (a)(ii) or (2) provide evidence that the applicable Borrower or Subsidiary has unwound, terminated or otherwise created offsetting positions for its Hedging Agreements (herein collectively referred to as a “Hedging Modification”) that result in compliance with clause (a)(ii) (and, for the avoidance of doubt, such Hedging Modifications must otherwise be in compliance with the terms of this Agreement).

In connection with the novation, assignment, amendment, modification or termination of any Borrowing Base Hedges, if the sum of the Borrowing Base value attributed by the Required Lenders to such Borrowing Base Hedges and all other Borrowing Base Hedges that have

been novated, assigned, amended, modified or terminated since the most recent scheduled Borrowing Base determination pursuant to Section 2.11 plus the aggregate Release Price of all Oil and Gas Properties included in the calculation of the Borrowing Base which have been disposed of since the most recent scheduled Borrowing Base determination pursuant to Section 2.11 equals or exceeds 5% of the Borrowing Base, the Borrowing Base shall be automatically reduced by an amount equal to 100% of the aggregate Borrowing Base value attributed by the Required Lenders to such Borrowing Base Hedges.

(h)Exhibit IVto the Credit Agreement (Form of Compliance Certificate and Hedging Report) is hereby amended and restated in its entirety in the form of Exhibit IVattached hereto.

Section 4. Borrowing Base Reaffirmation. The Administrative Agent hereby notifies the Borrowers, and the undersigned Lenders hereby agree and acknowledge, that the amount of the Borrowing Base has been reaffirmed by the Administrative Agent and the Lenders in accordance with Section 2.11(b) and (c)of the Credit Agreement, and has been set by the Administrative Agent and the Lenders at $450,000,000, effective as of the Effective Date. The Borrowing Base shall remain in effect at such level until the Borrowing Base is redetermined or otherwise adjusted in accordance with the terms of the Credit Agreement.

Section 5. Conditions to Effectiveness. This Amendment shall become effective as of the Effective Date upon the satisfaction of the following conditions precedent:

(a)the Administrative Agent shall have received counterparts hereof duly executed by each Borrower, the Administrative Agent and the Required Lenders; and

(b)the Administrative Agent shall have received counterparts of the attached Acknowledgment and Reaffirmation duly executed by each Guarantor.

Section 6. Representations and Warranties. Each Borrower hereby represents and warrants that after giving effect hereto:

(a)the representations and warranties of the Borrowers contained in the Loan Documents are true and correct in all material respects on and as of the Effective Date, other than those representations and warranties that expressly relate solely to a specific earlier date, which shall remain correct as of such earlier date; and

(b)no Default or Event of Default has occurred and is continuing. Section 7.Effect of Amendment.

(a)The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Lender, the Issuing Bank or the Administrative Agent under any of the Loan Documents, nor, except as expressly provided herein, constitute a waiver or amendment of any provision of any of the Loan Documents.

(b)Upon and after the execution of this Amendment by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as modified hereby.

(c)This Amendment is a Loan Document executed pursuant to the Credit Agreement and shall (unless otherwise expressly indicated herein) be construed, administered and applied in accordance with the terms and provisions thereof.

(d)Except as specifically modified above, the Credit Agreement and the other Loan Documents are and shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.

Section 8. Governing Law. This Amendment shall be deemed to be made under and shall be construed in accordance with and governed by the laws of the State of Texas without giving effect to principles thereof relating to conflicts of law; provided, however, that Chapter 345 of the Texas Finance Code (which regulates certain revolving credit loan accounts and revolving triparty accounts) shall not apply.

Section 9. Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement. Transmission by facsimile of an executed counterpart of this Amendment shall be deemed to constitute due and sufficient delivery of such counterpart.

Section 10. ENTIRE AGREEMENT. THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[Remainder of Page Intentionally Left Blank]

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their respective duly authorized officers as of the Effective Date.

BORROWERS:

SWIFT ENERGY COMPANY

By: /s/ Alton D. Heckaman, Jr.

Alton D. Heckaman, Jr.

Executive Vice President and Chief Financial Officer

SWIFT ENERGY OPERATING, LLC

By: /s/ Alton D. Heckaman, Jr.

Alton D. Heckaman, Jr.

Executive Vice President and

Chief Financial Officer

ADMINISTRATIVE AGENT, ISSUING BANKAND LENDER:

JPMORGAN CHASE BANK, N.A.

By: /s/ Jo Linda Papadakis

Name: Jo Linda Papadakis

Title: Authorized Officer

LENDER:

WELLS FARGO BANK, N.A.

By:/s/Ellen Cheng

Name: Ellen Cheng

Title: Assistant Vice President

LENDER:

COMPASS BANK

By: /s/ Les Werme

Name: Les Werme

Title: Vice President

LENDER:

ROYAL BANK OF CANADA

By: /s/ Kristan Spivey

Name: Kristan Spivey

Title: Authorized Signatory

LENDER:

AMEGY BANK NATIONAL ASSOCIATION

By: /s/ H. Brock Hudson

Name: H. Brock Hudson

Title: Senior Vice President

LENDER:

COMERICA BANK

By: /s/ Jason Klesel

Name: Jason Klesel

Title: Commercial Banking Officer

LENDER:

U.S. BANK NATIONAL ASSOCIATION

By: /s/Mark E. Thompson

Name: Mark E. Thompson

Title: Senior Vice President

LENDER:

BRANCH BANKING & TRUST COMPANY

By: /s/ Ryan K. Michael

Name: Ryan K. Michael

Title: Senior Vice President

LENDER:

CANADIAN IMPERIAL BANK OF COMMERCE

By: /s/ Trudy Nelson

Name: Trudy Nelson

Title: Authorized Signatory

By:/s/Daria Mahoney

Name: Daria Mahoney

Title: Authorized Signatory

LENDER:

UNION BANK, N.A.

By: /s/ Rachel Bowman

Name: Rachel Bowman

Title: Vice President

LENDER:

WHITNEY BANK

By: /s/ David E. Sisler

Name: David E. Sisler

Title: Senior Vice President

Acknowledgment and Reaffirmations

Each of the undersigned (each a “Guarantor” and collectively the “Guarantors”) hereby

(i) acknowledges receipt of a copy of the foregoing Fourth Amendment and Consent dated as of

_April 30,, 2014 among Swift Energy Company, Swift Energy Operating, LLC, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent for such lenders (in such capacity, the “Administrative Agent”) and (ii) reaffirms its obligations under the Guaranty Agreement dated as of September 21, 2010 by the Guarantors in favor of the Administrative Agent for the benefit of the Secured Parties (as defined therein).

GASRS LLC

By: /s/ Bruce H. Vincent

Bruce H. Vincent

President

SWENCO-WESTERN, LLC

By: /s/ Alton D. Heckaman, Jr.

Alton D. Heckaman, Jr.

Executive Vice President, Chief

Financial Officer and Secretary

EX-31.1

Exhibit 31.1

CERTIFICATION

I, Terry E. Swift, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2014, of Swift Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 17, 2014	/s/Terry E. Swift
		Terry E. Swift Chairman of the Board and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Alton D. Heckaman, Jr., certify that:

1. I have reviewed this Quarterly Report on Form 10-Q for the period ended September 30, 2014, of Swift Energy Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting, to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	November 17, 2014	/s/Alton D. Heckaman, Jr.
		Alton D. Heckaman, Jr. Executive Vice-President Chief Financial Officer Principal Accounting Officer

EX-32

Exhibit 32

Certification of Chief Executive Officer and Chief Financial Officer

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the accompanying Quarterly Report on Form 10-Q for the period ended September 30, 2014 (the “Report”) of Swift Energy Company (“Swift”) as filed with the Securities and Exchange Commission on November 17, 2014, the undersigned, in his capacity as an officer of Swift, hereby certifies pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to his knowledge:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Swift.

Date:	November 17, 2014	/s/ Alton D. Heckaman, Jr.
		Alton D. Heckaman, Jr. Executive Vice-President Chief Financial Officer Principal Accounting Officer
Date:	November 17, 2014	/s/ Terry E. Swift
		Terry E. Swift Chairman of the Board and Chief Executive Officer

XML

Fair Value Measurements (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Total [Member] | Natural Gas Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	$ 0.7	$ 0.5
Fair Value of Derivative Liabilities		0.7
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Total [Member] | Natural Gas Basis Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Liabilities	0.6
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Total [Member] | Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets		0.3
Fair Value of Derivative Liabilities		0.2
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Natural Gas Basis Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Liabilities	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets		0
Fair Value of Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	0.7	0.5
Fair Value of Derivative Liabilities		0.7
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Natural Gas Basis Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Liabilities	0.6
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets		0.3
Fair Value of Derivative Liabilities		0.2
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets	0	0
Fair Value of Derivative Liabilities		0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Natural Gas Basis Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Liabilities	0
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Oil Derivative Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value of Derivative Assets		0
Fair Value of Derivative Liabilities		0
Senior Notes [Member] | Senior Notes Due 2017 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of senior notes	251.9	256.7
Carrying value of senior notes	250.0	250.0
Senior Notes [Member] | Senior Notes Due 2020 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of senior notes	225.0	239.1
Carrying value of senior notes	222.7	222.4
Senior Notes [Member] | Senior Notes Due 2022 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of senior notes	411.0	409.0
Carrying value of senior notes	$ 404.6	$ 404.9

XML

Accounting Changes and Error Corrections Accounting Changes and Error Corrections (Details Textual) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Depreciation, Depletion and Amortization	$ 65,331	$ 67,274	$ 201,072	$ 187,503
Net Income	2,474	7,359	14,743	22,946	(2,442)
Provision for Income Taxes	3,001	5,625	14,200	15,235
Restatement Adjustment [Member]
Depreciation, Depletion and Amortization		326		977
Net Income		(1,527)		129
Provision for Income Taxes		(867)		73
Ceiling Test Error Correction [Member] | Restatement Adjustment [Member]
Depreciation, Depletion and Amortization		300		1,000
Net Income		200		600
Provision for Income Taxes		$ 100		$ 400

XML

Accounting Changes and Error Corrections Accounting Changes and Error Corrections (Notes)

9 Months Ended

Sep. 30, 2014

Accounting Changes and Error Corrections [Abstract]

Accounting Changes and Error Corrections

Restatement of Previously Issued Condensed Consolidated Financial Statements

Overview. In connection with the preparation of our financial statements for the quarter ended September 30, 2014, we determined that the ceiling test calculation we had prepared at December 31, 2013, March 31, 2009 and December 31, 2008, to determine whether the net book value of the Company's oil and gas properties exceed the ceiling, incorrectly included the deferred income tax effect of the Company's asset retirement obligations when computing the ceiling test limitation of its oil and natural gas properties under the full-cost method of accounting. The Company determined that the error caused a material overstatement of its full-cost ceiling test write-down of oil and gas properties in periods prior to 2014, more specifically in the fourth quarter of 2013, in the first quarter of 2009 and the fourth quarter of 2008, including associated depletion for all periods presented. As a result of this error, in this Form 10-Q we are restating our unaudited condensed consolidated financial information for the three and nine months ended September 30, 2013.

For the 2013 periods presented herein, the correction of the error principally results in an increase in our depreciation, depletion and amortization expense for the three and nine months ended September 30, 2013 of approximately $0.3 million and $1.0 million, respectively, and decreased net income for the three and nine months ended September 30, 2013 by approximately $0.2 million and $0.6 million, respectively (net of a decrease to the income tax benefit for the three and nine months ended September 30, 2013, of approximately $0.1 million and $0.4 million, respectively).

Along with restating our financial statements to correct the error discussed above, we have recorded adjustments for certain previously identified immaterial accounting errors related to the periods covered by this Form 10-Q. When these financial statements were originally issued, we assessed the impact of these errors and concluded that they were not material to our financial statements for the three and nine months ended September 30, 2013. However, in conjunction with our need to restate our financial statements as a result of the error noted above, we have determined that it would be appropriate to make adjustments within this Form 10-Q for all such previously unrecorded adjustments.

The combined impacts of all adjustments to the applicable line items in our unaudited condensed consolidated financial statements for the periods covered by this Form 10-Q are provided in the tables below.

The following tables present the effect of the correction of the error and other adjustments on selected line items of our previously reported unaudited condensed consolidated financial statements for the three and nine months ended September 30, 2013 (in thousands):

	Condensed Consolidated Statements of Operations For the Three Months Ended September 30, 2013							Condensed Consolidated Statements of Operations For the Nine Months Ended September 30, 2013
	(As Reported)		Adjustments			(As Restated)		(As Reported)		Adjustments			(As Restated)
Oil and Gas Sales	$	155,049	$	(2,068	)	$	152,981	$	442,418	$	(403	)	$	442,015
Total Revenues	153,001		(2,068		)	150,933		441,704		(403		)	441,301
Depreciation, depletion, and amortization	66,948		326			67,274		186,526		977			187,503
Lease operating cost	23,078		—			23,078		77,459		(540		)	76,919
Transportation and gas processing	5,783		—			5,783		16,678		(1,292		)	15,386
Severance and other taxes	11,695		—			11,695		31,971		250			32,221
Total Costs and Expenses	137,623		326			137,949		403,725		(605		)	403,120
Income (Loss) from Continuing Operations Before Income Taxes	15,378		(2,394		)	12,984		37,979		202			38,181
Provision (Benefit) for Income Taxes	6,492		(867		)	5,625		15,162		73			15,235
Net Income (Loss)	8,886		(1,527		)	7,359		22,817		129			22,946
Basic EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.53	$	—		$	0.53
Diluted EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.52	$	0.01		$	0.53

	Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2013
	(As Reported)			Adjustments			(As Restated)
Net income (loss)	$	22,817		$	129		$	22,946
Depreciation, depletion, and amortization	186,526			977			187,503
Deferred income taxes	15,162			73			15,235
Other	(3,796		)	(297		)	(4,093		)
(Increase) decrease in accounts receivable	(3,696		)	403			(3,293		)
Increase (decrease) in accounts payable and accrued liabilities	3,873			(1,285		)	2,588
Net Cash Provided by Operating Activities	225,607			—			225,607

XML

Share-Based Compensation (Details Textual) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Stock option activity in shares and weighted average price
Options outstanding, beginning of period, shares			1,488,314
Options outstanding, beginning of period, weighted average price			$ 33.38
Options granted, shares			0
Options granted, weighted average price			$ 0.00
Options canceled, shares			(90,527)
Options canceled, weighted average price			$ 25.20
Options exercised, shares			0
Options exercised, weighted average price			$ 0.00
Options outstanding, end of period, shares	1,397,787		1,397,787
Options oustanding, end of period, weighted average price	$ 33.88		$ 33.88
Options exercisable, end of period, shares	1,295,616		1,295,616
Options exercisable, end of period, weighted average price	$ 33.98		$ 33.98
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Tax shortfall in earnings related to share-based compensation	$ 200,000		$ 2,100,000
Stock-based compensation expenses			5,571,000	8,454,000
Share-based compensation (capitalized)	900,000	1,200,000	2,900,000	4,400,000
Remaining contract life of outstanding stock options.			4 years 9 months
Remaining contract life of exercisable stock option			4 years 7 months
Employee Stock Option [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Unrecognized compensation cost for stock grants	200,000		200,000
Weighted average remaining recognition period of cost for stock grants			5 months
Restricted Stock Awards [Member]
Restricted stock activity
Restricted shares outstanding, beginning of period, shares			1,267,110
Restricted shares outstanding, beginning of period, weighted average price			$ 21.54
Restricted shares granted, shares			743,150
Restricted shares granted, weighted average price			$ 11.58
Restricted shares canceled, shares			(139,973)
Restricted shares canceled, weighted average price			$ 15.16
Restricted shares vested, shares			(308,825)
Restricted shares vested, weighted average price			$ 34.27
Restricted shares outstanding, end of period, shares	1,561,462		1,561,462
Restricted shares outstanding, end of period, weighted average price	$ 14.85		$ 14.85
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Unrecognized compensation cost for stock grants	12,400,000		12,400,000
Weighted average remaining recognition period of cost for stock grants			1 year 8 months
Grant date fair value of shares vested			10,600,000
Restricted Stock Units (RSUs) [Member]
Restricted stock activity
Restricted shares outstanding, beginning of period, shares			189,700
Restricted shares outstanding, beginning of period, weighted average price			$ 15.01
Restricted shares granted, shares			185,250	189,700
Restricted shares granted, weighted average price			$ 11.68	$ 15.01
Restricted shares canceled, shares			0
Restricted shares canceled, weighted average price			$ 0.00
Restricted shares vested, shares			0
Restricted shares vested, weighted average price			$ 0.00
Restricted shares outstanding, end of period, shares	374,950		374,950
Restricted shares outstanding, end of period, weighted average price	$ 13.36		$ 13.36
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Unrecognized compensation cost for stock grants	2,800,000		2,800,000
Weighted average remaining recognition period of cost for stock grants			2 years 0 months
Restricted Stock Awards Vesting Term			3 years 1 month
Minimum [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Restricted Stock Awards Vesting Term			1 year
Percent of payout for performance based restricted stock unit grants			0.00%
Maximum Payout [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Restricted Stock Awards Vesting Term			3 years
Percent of payout for performance based restricted stock unit grants			200.00%
Target Payout [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Percent of payout for performance based restricted stock unit grants			100.00%
General and Administrative Expense [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Stock-based compensation expenses	1,700,000	2,200,000	5,100,000	7,800,000
Lease Operating Cost [Member]
Share-based Compensation Arrangement, Additional General Disclosures [Abstract]
Stock-based compensation expenses	$ 100,000	$ 100,000	$ 200,000	$ 200,000

XML

Summary of Significant Accounting Policies (Details Textual) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jul. 15, 2014 acre	Dec. 31, 2013
Summary of Significant Accounting Policies (Textual) [Abstract]
Total capitalized internal costs	$ 6,900,000	$ 7,900,000	$ 20,900,000	$ 23,900,000
Total capitalized interest cost on unproved properties	1,200,000	1,800,000	3,700,000	5,600,000
Discount rate for estimated future net revenues from proved properties			10.00%
Allowance for doubtful accounts receivable, current	400,000		400,000			100,000
Trade Accounts Receivable, Gross	51,900,000		51,900,000			56,900,000
Accounts receivable related to joint interest owners	1,900,000		1,900,000			1,600,000
Severance Tax Receivable	7,900,000		7,900,000			11,600,000
Other Receivables	1,700,000		1,700,000			800,000
Net gain (loss) on derivative activities	5,000,000	(2,000,000)	(2,700,000)	(800,000)
Non-Cash Fair Value Adjustment for Derivatives	1,200,000
Receivables from settled derivatives	1,000,000		1,000,000
Liabilities, Fair Value Disclosure	100,000		100,000
Derivative, Fair Value, Net	100,000		100,000			(100,000)
Percentage of working interest in wells			100.00%
Total amount of supervision fees charged to wells	3,500,000	2,800,000	9,200,000	8,900,000
Inventories carried at cost	3,100,000		3,100,000			3,500,000
Adjustments to Additional Paid in Capital, Income Tax Deficiency from Share-based Compensation	200,000		2,100,000
Outstanding checks included in trade accounts payable	9,600,000		9,600,000			26,100,000
Acreage Sold in Oil and Gas Properties					8,300
Interest Sold in Oil and Gas Properties					36.00%
Restricted Cash and Cash Equivalents, Current	34,500,000		34,500,000
Restricted Cash Attributable to Company	11,800,000		11,800,000
Increase in Restricted Cash in Operating Activities	29,800,000
Decrease in Restricted Cash in Operating Activities	7,100,000
Restricted cash and cash equivalents included in other long term assets	1,000,000		1,000,000			1,000,000
Asset Retirement Obligation - current portion	13,292,000		13,292,000			15,859,000
Other Current Assets [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative Asset, Fair Value, Gross Asset	700,000		700,000
Other Current Liabilities [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative Liability, Fair Value, Gross Liability	500,000		500,000
Other Noncurrent Liabilities [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Derivative Liability, Fair Value, Gross Liability	100,000		100,000
Senior Notes [Member] | Senior Notes Due 2017 [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Debt Instrument, Interest Rate, Stated Percentage	7.125%		7.125%
Balance of issuance costs for credit facility	1,400,000		1,400,000
Senior Notes [Member] | Senior Notes Due 2020 [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Debt Instrument, Interest Rate, Stated Percentage	8.875%		8.875%
Balance of issuance costs for credit facility	3,200,000		3,200,000
Senior Notes [Member] | Senior Notes Due 2022 [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Debt Instrument, Interest Rate, Stated Percentage	7.875%		7.875%
Balance of issuance costs for credit facility	6,100,000		6,100,000
Line of Credit [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Balance of issuance costs for credit facility	$ 2,500,000		$ 2,500,000
Minimum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life			2 years
Maximum [Member]
Summary of Significant Accounting Policies (Textual) [Abstract]
Property, Plant and Equipment, Useful Life			20 years

XML

Earnings Per Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Basic EPS Two Class Method:
Net Income	$ 2,474	$ 7,359	$ 14,743	$ 22,946	$ (2,442)
Income, share amounts	43,850,000	43,389,000	43,768,000	43,308,000
Earnings Per Share, Basic	$ 0.06	$ 0.17	$ 0.34	$ 0.53
Dilutive Securities:
Dilutive RSA's, Shares	564,000	288,000	469,000	249,000
Dilutive RSU's, Shares	59,000	27,000	62,000	67,000
Diluted EPS:
Net Income (Loss) Available to Common Stockholders, Diluted	$ 2,474	$ 7,359	$ 14,743	$ 22,946
Weighted Average Number of Shares Outstanding, Diluted	44,473,000	43,704,000	44,299,000	43,624,000
Earnings Per Share, Diluted	$ 0.06	$ 0.17	$ 0.33	$ 0.53
Stock Options [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	1,400,000	1,600,000	1,400,000	1,600,000
Restricted Stock [Member]
Earnings Per Share (Textual)
Antidilutive shares excluded from EPS, shares	200,000	200,000	300,000	300,000
Restricted Stock Units (RSUs) [Member]
Earnings Per Share (Textual)
Contingently Issuable Shares Not Included in Diluted EPS	700,000	400,000	700,000	400,000

XML

Long-Term Debt (Details) (USD $)	3 Months Ended			9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Dec. 31, 2013		Dec. 31, 2011
Bank Borrowings
Long-Term Debt	$ 1,079,269,000	[1]		$ 1,079,269,000	[1]		$ 1,142,368,000	[1]
Capitalized interest on our unproved properties	1,200,000		1,800,000	3,700,000		5,600,000
Number of syndicated banks	11			11
Line of Credit Facility, Current Borrowing Capacity	417,600,000			417,600,000
Maximum availability aggregate facility amount	500,000,000			500,000,000
Line of Credit, Current Commitment Amount	417,600,000			417,600,000
Percentage of applicable margin with federal fund rate	0.50%
Percentage of applicable margin with LIBOR	1.00%
Lead bank's prime rate	3.25%
Interest expense including amortization of debt issuance costs	18,197,000		17,495,000	55,295,000		51,297,000
Minimum [Member]
Bank Borrowings
Commitment Fee Basis Points For The Credit Facility	0.375%
Minimum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	50
Minimum [Member] | Eurodollar Interest Rate [Member]
Bank Borrowings
Debt instrument escalating rates for eurodolllar rate loans	150
Maximum [Member]
Bank Borrowings
Commitment Fee Basis Points For The Credit Facility	0.50%
Maximum [Member] | Alternative Base Interest Rate [Member]
Bank Borrowings
Debt instrument escalating basis spread on base rate	150
Maximum [Member] | Eurodollar Interest Rate [Member]
Bank Borrowings
Debt instrument escalating rates for eurodolllar rate loans	250
Senior Notes [Member] | Senior Notes Due 2017 [Member]
Bank Borrowings
Long-Term Debt	250,000,000			250,000,000			250,000,000
Long-term Debt, Maturities, Repayments of Principal in Year Three	250,000,000			250,000,000
Interest expense including amortization of debt issuance costs	4,600,000		4,600,000	13,700,000		13,700,000
Senior Notes
Senior notes, issued	250,000,000			250,000,000
Stated Rate of Senior notes	7.125%			7.125%
Percentage at which senior notes are issued, of par value	100.00%			100.00%
Redemption price plus accrued and unpaid interest	102.375%
Redemption price, plus accrued and unpaid interest declining in twelve-month intervals	100.00%
Initial Debt Issuance Costs Capitalized	4,200,000			4,200,000
Holder right to require company to repurchase notes at purchase price in cash	101.00%
Senior Notes [Member] | Senior Notes Due 2020 [Member]
Bank Borrowings
Long-Term Debt	222,691,000	[1]		222,691,000	[1]		222,446,000	[1]
Long-term Debt, Maturities, Repayments of Principal after Year Five	225,000,000			225,000,000
Interest expense including amortization of debt issuance costs	5,200,000		5,200,000	15,600,000		15,500,000
Senior Notes
Senior notes, issued	225,000,000			225,000,000
Stated Rate of Senior notes	8.875%			8.875%
Original unamortized issuance discount on senior notes	3,600,000			3,600,000
Percentage at which senior notes are issued, of par value	98.389%			98.389%
Effective Interest Rate On Senior Notes Including Discount	9.125%			9.125%
Redemption price plus accrued and unpaid interest	104.438%
Redemption price, plus accrued and unpaid interest declining in twelve-month intervals	100.00%
Initial Debt Issuance Costs Capitalized	5,000,000			5,000,000
Holder right to require company to repurchase notes at purchase price in cash	101.00%
Senior Notes [Member] | Senior Notes Due 2022 [Member]
Bank Borrowings
Long-Term Debt	404,578,000	[1]		404,578,000	[1]		404,922,000	[1]
Long-term Debt, Maturities, Repayments of Principal after Year Five	400,000,000			400,000,000
Interest expense including amortization of debt issuance costs	7,900,000		7,900,000	23,700,000		23,700,000
Senior Notes
Senior notes, issued	400,000,000			400,000,000					250,000,000
Stated Rate of Senior notes	7.875%			7.875%
Original unamortized issuance discount on senior notes	2,100,000			2,100,000
Percentage at which senior notes are issued, of par value	99.156%			99.156%
Effective Interest Rate On Senior Notes Including Discount	8.00%			8.00%
Redemption price plus accrued and unpaid interest	103.938%
Redemption price, plus accrued and unpaid interest declining in twelve-month intervals	100.00%
Percentage of maximum redemption of principal amount of notes	35.00%
Redemption of Debts with Net Proceeds of Qualifying Offerings at Price Above Principle Amount of Debts	107.875%
Initial Debt Issuance Costs Capitalized	7,500,000			7,500,000
Holder right to require company to repurchase notes at purchase price in cash	101.00%
Senior Notes [Member] | Additional Senior Notes Due 2022 [Member]
Senior Notes
Senior notes, issued	150,000,000			150,000,000
Percentage at which senior notes are issued, of par value	105.00%			105.00%
Effective Interest Rate On Senior Notes Including Discount	6.993%			6.993%
Debt Instrument, Unamortized Premium	7,500,000			7,500,000
Line of Credit [Member]
Bank Borrowings
Long-Term Debt	202,000,000			202,000,000			265,000,000
Maximum level of cash dividends in any fiscal year	15,000,000			15,000,000
Equity Restrictions	50,000,000			50,000,000
Interest expense including amortization of debt issuance costs	1,700,000		1,600,000	5,900,000		4,000,000
Commitment fees included in interest expense, net	$ 200,000		$ 200,000	$ 600,000		$ 900,000

[1] Amounts are shown net of any debt discount or premium

XML

General Information

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

General Information

(1)           General Information

The condensed consolidated financial statements included herein have been prepared by Swift Energy Company (“Swift Energy,” the “Company,” or “we”) 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 note 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/A for the fiscal year ended December 31, 2013 as filed with the Securities and Exchange Commission on November 17, 2014.

XML

Acquisitions and Dispositions Acquisitions and Dispositions (Details) (USD $)	Sep. 30, 2014		Jul. 15, 2014 acre	Dec. 31, 2013
Business Combinations [Abstract]
Acreage Sold in Oil and Gas Properties			8,300
Participation Interest Sold in Oil and Gas Properties			36.00%
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds			$ 175,000,000
Cash Received at Closing from Oil and Gas Properties			125,000,000
Remaining Cash Carry of Field Development Costs	35,000,000
Cash Carry of Field Development Costs			50,000,000
Sale Proceeds Received at Closing			147,000,000
Deferred Credits and Other Liabilities, Current	$ 22,685,000	[1]	$ 12,500,000	$ 0	[1]

[1] This amount equals the liability related to funds received from Saka Energi that are maintained in a restricted cash account. Refer to the "Short-Term Restricted Cash" discussion below for further information.

XML

Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Current Assets:
Cash and cash equivalents	$ 9,041		$ 3,277
Accounts receivable	63,385		70,897
Deferred tax asset	9,693		10,715
Other current assets	42,063		7,600
Total Current Assets	124,182		92,489
Property and Equipment:
Property and Equipment	5,863,650		5,714,099
Less - Accumulated depreciation, depletion, and amortization	(3,326,908)		(3,125,282)
Property and Equipment, Net	2,536,742		2,588,817
Other Long-Term Assets	14,235		17,199
Total Assets	2,675,159		2,698,505
Current Liabilities:
Accounts payable and accrued liabilities	100,493		82,318
Accrued capital costs	48,498		61,164
Accrued interest	12,986		21,561
Undistributed oil and gas revenues	13,089		10,990
Total Current Liabilities	175,066		176,033
Long-Term Debt	1,079,269	[1]	1,142,368	[1]
Deferred Tax Liabilities	253,689		241,205
Asset Retirement Obligation	67,155		63,225
Other Long-Term Liabilities	9,631		10,324
Commitments and Contingencies	0		0
Stockholders' Equity:
Preferred stock, $0.01 par value	0		0
Common stock, $0.01 par value	443		439
Additional paid-in capital	769,663		762,242
Treasury stock held, at cost	(9,744)		(12,575)
Retained earnings	329,987		315,244
Total Stockholders' Equity	1,090,349	[2]	1,065,350
Total Liabilities and Stockholders' Equity	$ 2,675,159		$ 2,698,505

[1] Amounts are shown net of any debt discount or premium

[2] Unaudited

XML

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Stock issued for benefit plans (shares)	154,665	104,890
Options exercised (shares)	0	1,125
Purchase of treasury stock (shares)	79,720	98,020
Employee stock purchase plan (shares)	71,825	72,273
Issuance of restricted stock (shares)	309,075	391,581

XML

Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS

The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the three and nine months ended September 30, 2014 and 2013 (in thousands, except per share amounts):

	Three Months Ended September 30, 2014					Three Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	2,474	43,850	$	0.06	$	7,359	43,389	$	0.17
Dilutive Securities:
Restricted Stock Awards			564					288
Restricted Stock Units			59					27
Diluted EPS:
Net Income and Assumed Share Conversions	$	2,474	44,473	$	0.06	$	7,359	43,704	$	0.17

	Nine Months Ended September 30, 2014					Nine Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	14,743	43,768	$	0.34	$	22,946	43,308	$	0.53
Dilutive Securities:
Restricted Stock Awards			469					249
Restricted Stock Units			62					67
Diluted EPS:
Net Income and Assumed Share Conversions	$	14,743	44,299	$	0.33	$	22,946	43,624	$	0.53

XML

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair value of senior notes

Based upon quoted market prices as of September 30, 2014 and December 31, 2013, the fair value and carrying value of our senior notes was as follows (in millions):

	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
7.125% senior notes due in 2017	$	251.9	$	250.0	$	256.7	$	250.0
8.875% senior notes due in 2020	$	225.0	$	222.7	$	239.1	$	222.4
7.875% senior notes due in 2022	$	411.0	$	404.6	$	409.0	$	404.9

Fair value of plan assets

The following table presents our assets and liabilities that are measured at fair value as of September 30, 2014 and December 31, 2013, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 2 of these condensed consolidated financial statements. 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
	Total Assets / Liabilities		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs  (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2014
Assets:
Natural Gas Derivatives	$	0.7	$	—	$	0.7	$	—
Liabilities:
Natural Gas Basis Derivatives	0.6		—		0.6		—
December 31, 2013
Assets:
Natural Gas Derivatives	0.5		—		0.5		—
Oil Derivatives	0.3		—		0.3		—
Liabilities:
Natural Gas Derivatives	0.7		—		0.7		—
Oil Derivatives	0.2		—		0.2		—

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash Flows from Operating Activities:
Net Income	$ 14,743	$ 22,946
Adjustments to reconcile net income to net cash provided by operation activities -
Depreciation, depletion, and amortization	201,072	187,503
Accretion of asset retirement obligation	4,246	4,732
Deferred income taxes	13,507	15,235
Stock-based compensation expenses	5,571	8,454
Other Noncash Income (Expense)	(390)	(4,093)
(Increase) Decrease in accounts receivable	14,159	(3,293)
Increase (decrease) in accounts payable and accrued liabilities	7,299	2,588
Increase (decrease) in income taxes payable	543	(208)
Increase (decrease) in accrued interest	(8,575)	(8,257)
Net Cash Provided by Operating Activities	252,175	225,607
Cash Flows from Investing Activities:
Additions to property and equipment	(316,972)	(435,722)
Proceeds from the sale of property and equipment	145,535	6,990
Transfer of company funds from restricted cash	6,501	0
Transfer of company funds to restricted cash	(18,345)	0
Net Cash Used in Investing Activities	(183,281)	(428,732)
Cash Flows from Financing Activities:
Proceeds from bank borrowings	639,000	968,500
Payments of bank borrowings	(702,000)	(764,900)
Net proceeds from issuances of common stock	824	946
Purchase of treasury shares	(954)	(1,494)
Net Cash Used in Financing Activities	(63,130)	203,052
Net Increase (Decrease) in Cash and Cash Equivalents	5,764	(73)
Cash and Cash Equivalents at Beginning of Period	3,277	170
Cash and Cash Equivalents at End of Period	9,041	97
Supplemental Disclosures of Cash Flows Information:
Cash paid during period for interest, net of amounts capitalized	61,983	57,990
Cash paid during period for income taxes	$ 150	$ 208

XML

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Capitalized Costs, Unproved Properties	$ 65,767	$ 71,452
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value per share (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	44,296,246	43,915,346
Common stock, shares outstanding	43,857,765	43,401,920
Treasury stock shares held, at cost	438,481	513,426

XML

Commitments and Contingencies Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies Disclosure [Text Block]

(9)           Commitments and Contingencies

During 2014, the Company entered into additional gas transportation agreements. As of September 30, 2014, the minimum commitments under these agreements total approximately $36.3 million covering transportation from 2015 through 2020.

We had no other material changes from amounts referenced under Note 5 in our Notes to Consolidated Financial Statements from our Annual Report on Form 10-K/A for the year ending December 31, 2013.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	SWIFT ENERGY CO
Entity Central Index Key	0000351817
Document Type	10-Q
Current Fiscal Year End Date	--12-31
Document Period End Date	Sep. 30, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		43,859,472

XML

Summary of Significant Accounting Policies (Policies)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Restatement, Policy

Restatement of Previously Issued Condensed Consolidated Financial Statements

Overview. In connection with the preparation of our financial statements for the quarter ended September 30, 2014, we determined that the ceiling test calculation we had prepared at December 31, 2013, March 31, 2009 and December 31, 2008, to determine whether the net book value of the Company's oil and gas properties exceed the ceiling, incorrectly included the deferred income tax effect of the Company's asset retirement obligations when computing the ceiling test limitation of its oil and natural gas properties under the full-cost method of accounting. The Company determined that the error caused a material overstatement of its full-cost ceiling test write-down of oil and gas properties in periods prior to 2014, more specifically in the fourth quarter of 2013, in the first quarter of 2009 and the fourth quarter of 2008, including associated depletion for all periods presented. As a result of this error, in this Form 10-Q we are restating our unaudited condensed consolidated financial information for the three and nine months ended September 30, 2013.

For the 2013 periods presented herein, the correction of the error principally results in an increase in our depreciation, depletion and amortization expense for the three and nine months ended September 30, 2013 of approximately $0.3 million and $1.0 million, respectively, and decreased net income for the three and nine months ended September 30, 2013 by approximately $0.2 million and $0.6 million, respectively (net of a decrease to the income tax benefit for the three and nine months ended September 30, 2013, of approximately $0.1 million and $0.4 million, respectively).

Along with restating our financial statements to correct the error discussed above, we have recorded adjustments for certain previously identified immaterial accounting errors related to the periods covered by this Form 10-Q. When these financial statements were originally issued, we assessed the impact of these errors and concluded that they were not material to our financial statements for the three and nine months ended September 30, 2013. However, in conjunction with our need to restate our financial statements as a result of the error noted above, we have determined that it would be appropriate to make adjustments within this Form 10-Q for all such previously unrecorded adjustments.

Principles of Consolidation

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 gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in oil and gas properties 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.

Subsequent Events

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

Use of Estimates

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 amounts 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 therefrom,

• 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 sales, 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 share-based 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,

• estimates in the calculation of the fair value of hedging assets and liabilities, and

• estimates in the assessment of current litigation claims against the company.

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 adjustments occur.

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.

Property and Equipment

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 three months ended September 30, 2014 and 2013, such internal costs capitalized totaled $6.9 million and $7.9 million, respectively. For the nine months ended September 30, 2014 and 2013, such internal costs capitalized totaled $20.9 million and $23.9 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the three months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $1.2 million and $1.8 million, respectively. For the nine months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $3.7 million and $5.6 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 (in thousands):

	September 30, 2014			December 31, 2013 (As Restated)
Property and Equipment
Proved oil and gas properties	$	5,755,886		$	5,600,279
Unproved oil and gas properties	65,767			71,452
Furniture, fixtures, and other equipment	41,997			42,368
Less – Accumulated depreciation, depletion, and amortization	(3,326,908		)	(3,125,282		)
Property and Equipment, Net	$	2,536,742		$	2,588,817

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 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 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 two and 20 years. Repairs and maintenance are charged to expense as incurred.

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

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 price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). This calculation is done on a country-by-country basis.

The calculations of the Ceiling Test and provision for DD&A are 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.

It is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the future and that non-cash write-downs of oil and natural gas properties could occur in the future. For example, if future capital expenditures out pace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, non-cash write-downs of our oil and natural gas properties could occur. We cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties.

Revenue Recognition

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 condensed consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying condensed consolidated balance sheets when our ownership share of production exceeds sales. As of September 30, 2014 and December 31, 2013, we did not have any material natural gas imbalances.

Reclassification of Prior Period Balances

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

Accounts Receivable

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 September 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts of approximately $0.4 million and $0.1 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

Debt Issuance Costs

Debt Issuance Costs. Legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with extensions of our bank credit facility and public debt offerings were capitalized and are amortized on an effective interest basis over the life of each of the respective senior note offerings and credit facility.

Price-Risk Management Activities

Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized in earnings. The changes in the fair value of our derivatives are recognized in "Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. 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 swaps, floors, calls, collars and participating collars.

Supervision Fees

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying condensed consolidated statements of operations. Our supervision fees are based on COPAS industry guidelines. The amount of supervision fees charged for the three and nine months ended September 30, 2014 and 2013 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $3.5 million and $2.8 million for the three months ended September 30, 2014 and 2013, respectively and $9.2 million and $8.9 million for the nine months ended September 30, 2014 and 2013, respectively.

Inventories

Inventories. Inventories consist primarily of tubulars and other equipment and supplies that we expect to place in service in production operations.

Income Taxes

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 policy is to record interest and penalties relating to uncertain tax positions in income tax expense.

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below

Cash and Cash Equivalents

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.

Saka Energi Transaction

Saka Energi Transaction). On July 15, 2014, we closed our transaction with PT Saka Energi Indonesia ("Saka Energi") to fully develop 8,300 acres of Fasken area Eagle Ford shale properties owned by Swift Energy in Webb County, Texas. Swift Energy sold a 36% full participating interest in the Fasken properties to Saka Energi.

Subject to the terms of the transaction, Swift Energy and Saka Energi are required to deposit cash on a monthly basis into a separate Swift Energy-owned bank account to fund their respective portions of the on-going Fasken development program for the following month. All cash deposited in the account is contractually restricted for use in the Fasken development program and therefore is recorded as restricted cash until the Company has performed the related development activities.

As of September 30, 2014, we recorded $34.5 million of restricted cash including $11.8 million for deposits from Swift Energy with the remaining deposits from Saka Energi. The restricted cash balance is reported in “Other current assets” while the related deposit liability is reported in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

During the quarter Saka Energi deposited $29.8 million into the account while $7.1 million was withdrawn from the account in order to fund on-going development operations in the Fasken area. The cash changes from the account relating to Saka Energi’s contributions are shown in the operating activities section of the accompanying condensed consolidated statements of cash flows. The cash changes from the account relating to Swift Energy’s contributions are reported in the investing activities section on the accompanying condensed consolidated statements of cash flows

Long-term Restricted Cash

Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of September 30, 2014 and December 31, 2013, these assets were approximately $1.0 million. 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. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.

Asset Retirement Obligation

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 as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

New Accounting Pronouncements

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09, providing a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance. The guidance is effective for annual and interim reporting periods beginning after December 15, 2016 and upon adoption, entities are required to recognize revenue using the following five-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation. Adoption of this standard could result in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. We plan to review and assess the effect and implement any necessary requirements as needed.

Share-based Compensation

Share-Based Compensation

We have various types of share-based compensation plans. Refer to our definitive proxy statement for our annual meeting of shareholders filed with the SEC on April 2, 2014, as well as Note 6 of our consolidated financial statements in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013, 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 stock options are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. We receive an additional tax deduction when restricted stock awards vest 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.

Earnings Per Share

Earnings Per Share

The Company computes earnings per share in accordance with FASB ASC 260-10. Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2014 and 2013, and are discussed below.

Fair Value Measurements

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.

Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Commitments and Contingencies

(9)           Commitments and Contingencies

During 2014, the Company entered into additional gas transportation agreements. As of September 30, 2014, the minimum commitments under these agreements total approximately $36.3 million covering transportation from 2015 through 2020.

We had no other material changes from amounts referenced under Note 5 in our Notes to Consolidated Financial Statements from our Annual Report on Form 10-K/A for the year ending December 31, 2013.

XML

Condensed Consolidated Statements of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:
Oil and gas sales	$ 133,896	$ 152,981	$ 441,440	$ 442,015
Price-risk management and other, net	4,898	(2,048)	(2,472)	(714)
Total Revenues	138,794	150,933	438,968	441,301
Costs and Expenses:
General and administrative, net	10,981	11,146	33,565	35,062
Depreciation, depletion, and amortization	65,331	67,274	201,072	187,503
Accretion of asset retirement obligation	1,445	1,478	4,246	4,732
Lease operating cost	22,067	23,078	70,606	76,919
Transportation and gas processing	5,107	5,783	16,412	15,386
Severance and other taxes	10,191	11,695	28,829	32,221
Interest expense, net	18,197	17,495	55,295	51,297
Total Costs and Expenses	133,319	137,949	410,025	403,120
Income Before Income Taxes	5,475	12,984	28,943	38,181
Provision for Income Taxes	3,001	5,625	14,200	15,235
Net Income	$ 2,474	$ 7,359	$ 14,743	$ 22,946
Per Share Amounts-
Earnings Per Share (Basic)	$ 0.06	$ 0.17	$ 0.34	$ 0.53
Earnings Per Share (Diluted)	$ 0.06	$ 0.17	$ 0.33	$ 0.53
Weighted Average Shares Outstanding - Basic	43,850	43,389	43,768	43,308
Weighted Average Shares Outstanding - Diluted	44,473	43,704	44,299	43,624

XML

Earnings Per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Share

(4)           Earnings Per Share

The Company computes earnings per share in accordance with FASB ASC 260-10. Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings per share ("Diluted EPS") assumes, as of the beginning of the period, exercise of stock options and restricted stock grants using the treasury stock method. Diluted EPS also assumes conversion of performance-based restricted stock units to common shares based on the number of shares (if any) that would be issuable, according to predetermined performance and market goals, if the end of the reporting period was the end of the performance period. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the three and nine months ended September 30, 2014 and 2013, 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 nine months ended September 30, 2014 and 2013 (in thousands, except per share amounts):

	Three Months Ended September 30, 2014					Three Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	2,474	43,850	$	0.06	$	7,359	43,389	$	0.17
Dilutive Securities:
Restricted Stock Awards			564					288
Restricted Stock Units			59					27
Diluted EPS:
Net Income and Assumed Share Conversions	$	2,474	44,473	$	0.06	$	7,359	43,704	$	0.17

	Nine Months Ended September 30, 2014					Nine Months Ended September 30, 2013
						(As Restated)
	Net Income		Shares	Per Share Amount		Net Income		Shares	Per Share Amount
Basic EPS:
Net Income and Share Amounts	$	14,743	43,768	$	0.34	$	22,946	43,308	$	0.53
Dilutive Securities:
Restricted Stock Awards			469					249
Restricted Stock Units			62					67
Diluted EPS:
Net Income and Assumed Share Conversions	$	14,743	44,299	$	0.33	$	22,946	43,624	$	0.53

Approximately 1.4 million and 1.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended September 30, 2014 and 2013, respectively, and approximately 1.4 million and 1.6 million stock options to purchase shares were not included in the computation of Diluted EPS for the nine months ended September 30, 2014 and 2013 because these stock options were antidilutive. Approximately 0.2 million restricted stock awards were not included in the computation of Diluted EPS for the three months ended September 30, 2014 and 2013, and approximately 0.3 million restricted stock awards were not included in the computation of Diluted EPS for the nine months ended September 30, 2014 and 2013 because they were antidilutive. Approximately 0.7 million and 0.4 million shares for three and nine months ended September 30, 2014 and 2013, respectively, related to performance-based restricted stock units that could be converted to common shares based on predetermined performance and market goals were not included in the computation of Diluted EPS because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the performance period.

XML

Share-Based Compensation

9 Months Ended

Sep. 30, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

(3)           Share-Based Compensation

We have various types of share-based compensation plans. Refer to our definitive proxy statement for our annual meeting of shareholders filed with the SEC on April 2, 2014, as well as Note 6 of our consolidated financial statements in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013, 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 stock options are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. We receive an additional tax deduction when restricted stock awards vest 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 three and nine months ended September 30, 2014, we recognized an income tax shortfall in earnings of $0.2 million and $2.1 million, respectively, primarily related to restricted stock awards that vested at a price lower than the grant date fair value. For the three and nine months ended September 30, 2013, we did not recognize any material excess tax benefit or shortfall in earnings. There were no stock option exercises for the nine months ended September 30, 2014 and 2013.

Share-based compensation expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations, was $1.7 million and $2.2 million for the three months ended September 30, 2014 and 2013, respectively and $5.1 million and $7.8 million for the nine months ended September 30, 2014 and 2013, respectively. Share-based compensation recorded in lease operating cost was $0.1 million for the three months ended September 30, 2014 and 2013 and was $0.2 million for the nine months ended September 30, 2014 and 2013, respectively. We also capitalized $0.9 million and $1.2 million of share-based compensation for the three months ended September 30, 2014 and 2013, respectively, and capitalized $2.9 million and $4.4 million for the nine months ended September 30, 2014 and 2013, respectively. We view stock option awards and restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life of component awards and amortize the awards on a straight-line basis over the life of the awards.

Stock Option Awards

We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards. During the nine months ended September 30, 2014 and 2013 we did not grant any stock option awards.

At September 30, 2014, we had $0.2 million of unrecognized compensation cost related to stock option awards, which is expected to be recognized over a weighted-average period of 0.4 years. The following table represents stock option award activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Exercise Price
Options outstanding, beginning of period	1,488,314	$	33.38
Options granted	—	$	—
Options canceled	(90,527)	$	25.20
Options exercised	—	$	—
Options outstanding, end of period	1,397,787	$	33.88
Options exercisable, end of period	1,295,616	$	33.98

Our stock option awards outstanding and exercisable at September 30, 2014 were out of the money and therefore had no aggregate intrinsic value. At September 30, 2014, the weighted average contract life of stock option awards outstanding was 4.8 years and the weighted average contract life of stock option awards exercisable was 4.6 years. There were no stock option exercises for the nine months ended September 30, 2014 and 2013.

Restricted Stock Awards

The plans, as described in Note 6 of our consolidated financial statements in our Annual Report on Form 10-K/A for the fiscal year ended December 31, 2013, allow for the issuance of restricted stock awards that generally 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 September 30, 2014, we had unrecognized compensation expense of $12.4 million related to restricted stock awards which is expected to be recognized over a weighted-average period of 1.7 years. The grant date fair value of shares vested during the nine months ended September 30, 2014 was $10.6 million.

The following table represents restricted stock award activity for the nine months ended September 30, 2014:

	Shares		Wtd. Avg. Grant Price
Restricted shares outstanding, beginning of period	1,267,110		$	21.54
Restricted shares granted	743,150		$	11.58
Restricted shares canceled	(139,973	)	$	15.16
Restricted shares vested	(308,825	)	$	34.27
Restricted shares outstanding, end of period	1,561,462		$	14.85

Performance-Based Restricted Stock Units

For the nine months ended September 30, 2014 and 2013, the Company granted 185,250 and 189,700 units, respectively, of performance-based restricted stock units containing predetermined market and performance conditions with a cliff vesting period of 3.1 years. These units were granted at 100% of target payout while the conditions of the grants allow for a payout ranging between no payout and 200% of target.

The compensation expense for the market condition is based on the per unit grant date valuation using a Monte-Carlo simulation. The performance condition is remeasured quarterly and compensation expense is recorded based on the closing market price of our stock per unit on the grant date multiplied by the expected payout level. The payout level is calculated based on actual performance achieved during the performance period compared to a defined peer group.

As of September 30, 2014, we had unrecognized compensation expense of $2.8 million related to our restricted stock units which is expected to be recognized over a weighted-average period of 2.0 years. No shares vested during the nine months ended September 30, 2014 and 2013. The weighted average grant date fair value for the restricted stock units granted during the nine months ended September 30, 2014 and 2013 was $11.68 and $15.01 per unit, respectively.

The following table represents restricted stock unit activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Grant Price
Restricted stock units outstanding, beginning of period	189,700	$	15.01
Restricted stock units granted	185,250	$	11.68
Restricted stock units canceled	—	$	—
Restricted stock units vested	—	$	—
Restricted stock units outstanding, end of period	374,950	$	13.36

XML

Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Long-term debt

Our long-term debt as of September 30, 2014 and December 31, 2013, was as follows (in thousands):

	September 30, 2014		December 31, 2013
7.125% senior notes due in 2017	$	250,000	$	250,000
8.875% senior notes due in 2020 (1)	222,691		222,446
7.875% senior notes due in 2022 (1)	404,578		404,922
Bank Borrowings due in 2017	202,000		265,000
Long-Term Debt (1)	$	1,079,269	$	1,142,368
(1) Amounts are shown net of any debt discount or premium

XML

Accounting Changes and Error Corrections Accounting Changes and Error Corrections (Tables)

9 Months Ended

Sep. 30, 2014

Accounting Changes and Error Corrections [Abstract]

Schedule of Error Corrections and Prior Period Adjustments

	Condensed Consolidated Statements of Operations For the Three Months Ended September 30, 2013							Condensed Consolidated Statements of Operations For the Nine Months Ended September 30, 2013
	(As Reported)		Adjustments			(As Restated)		(As Reported)		Adjustments			(As Restated)
Oil and Gas Sales	$	155,049	$	(2,068	)	$	152,981	$	442,418	$	(403	)	$	442,015
Total Revenues	153,001		(2,068		)	150,933		441,704		(403		)	441,301
Depreciation, depletion, and amortization	66,948		326			67,274		186,526		977			187,503
Lease operating cost	23,078		—			23,078		77,459		(540		)	76,919
Transportation and gas processing	5,783		—			5,783		16,678		(1,292		)	15,386
Severance and other taxes	11,695		—			11,695		31,971		250			32,221
Total Costs and Expenses	137,623		326			137,949		403,725		(605		)	403,120
Income (Loss) from Continuing Operations Before Income Taxes	15,378		(2,394		)	12,984		37,979		202			38,181
Provision (Benefit) for Income Taxes	6,492		(867		)	5,625		15,162		73			15,235
Net Income (Loss)	8,886		(1,527		)	7,359		22,817		129			22,946
Basic EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.53	$	—		$	0.53
Diluted EPS:  Net Income (Loss)	$	0.20	$	(0.03	)	$	0.17	$	0.52	$	0.01		$	0.53

	Consolidated Statements of Cash Flows For the Nine Months Ended September 30, 2013
	(As Reported)			Adjustments			(As Restated)
Net income (loss)	$	22,817		$	129		$	22,946
Depreciation, depletion, and amortization	186,526			977			187,503
Deferred income taxes	15,162			73			15,235
Other	(3,796		)	(297		)	(4,093		)
(Increase) decrease in accounts receivable	(3,696		)	403			(3,293		)
Increase (decrease) in accounts payable and accrued liabilities	3,873			(1,285		)	2,588
Net Cash Provided by Operating Activities	225,607			—			225,607

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

(7)           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.

Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Based upon quoted market prices as of September 30, 2014 and December 31, 2013, the fair value and carrying value of our senior notes was as follows (in millions):

	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
7.125% senior notes due in 2017	$	251.9	$	250.0	$	256.7	$	250.0
8.875% senior notes due in 2020	$	225.0	$	222.7	$	239.1	$	222.4
7.875% senior notes due in 2022	$	411.0	$	404.6	$	409.0	$	404.9

Our senior notes due in 2017, 2020 and 2022 are stated as liabilities at carrying value on our accompanying condensed consolidated balance sheets, net of any discount or premium. If we recorded these notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments.

The following table presents our assets and liabilities that are measured at fair value as of September 30, 2014 and December 31, 2013, and are categorized using the fair value hierarchy. For additional discussion related to the fair value of the Company's derivatives, refer to Note 2 of these condensed consolidated financial statements. 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
	Total Assets / Liabilities		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs  (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2014
Assets:
Natural Gas Derivatives	$	0.7	$	—	$	0.7	$	—
Liabilities:
Natural Gas Basis Derivatives	0.6		—		0.6		—
December 31, 2013
Assets:
Natural Gas Derivatives	0.5		—		0.5		—
Oil Derivatives	0.3		—		0.3		—
Liabilities:
Natural Gas Derivatives	0.7		—		0.7		—
Oil Derivatives	0.2		—		0.2		—

Our unsettled derivative assets and liabilities in the table above are measured at gross fair value and are shown on the accompanying condensed consolidated balance sheets in “Other current assets” and "Accounts payable and accrued liabilities", respectively.

Level 1 – Uses quoted prices in active markets for identical, unrestricted assets or liabilities. Instruments in this category have comparable fair values for identical instruments in active markets.

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 are periodically verified against quotes from brokers and include our commodity derivatives that we value using commonly accepted industry-standard models which contain inputs such as contract prices, risk-free rates, volatility measurements and other observable market data that 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.

XML

Long-Term Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Long-Term Debt

(5)           Long-Term Debt

Our long-term debt as of September 30, 2014 and December 31, 2013, was as follows (in thousands):

	September 30, 2014		December 31, 2013
7.125% senior notes due in 2017	$	250,000	$	250,000
8.875% senior notes due in 2020 (1)	222,691		222,446
7.875% senior notes due in 2022 (1)	404,578		404,922
Bank Borrowings due in 2017	202,000		265,000
Long-Term Debt (1)	$	1,079,269	$	1,142,368
(1) Amounts are shown net of any debt discount or premium

As of September 30, 2014, we had $202.0 million of outstanding bank borrowings on our credit facility which has a maturity date of November 1, 2017. The maturities on our senior notes are $250.0 million in 2017, $225.0 million in 2020 and $400.0 million in 2022.

We have capitalized interest on our unproved properties in the amount of $1.2 million and $1.8 million for the three months ended September 30, 2014 and 2013, respectively, and we have capitalized interest on our unproved properties in the amount of $3.7 million and $5.6 million for the nine months ended September 30, 2014 and 2013, respectively.

Bank Borrowings. Effective October 17, 2014, our syndicate of 11 banks reaffirmed the borrowing base and commitment amount of $417.6 million on our $500.0 million credit facility. The maturity date of November 1, 2017 remained unchanged.

We had $202.0 million and $265.0 million in outstanding borrowings under our credit facility at September 30, 2014 and December 31, 2013, respectively. The interest rate on our credit facility is either (a) the lead bank’s prime rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. However with respect to (a), if the lead bank’s prime rate is not higher than each of the federal funds rate plus 0.5%, and the adjusted London Interbank Offered Rate (“LIBOR”) plus 1%, the greatest of these three rates will then apply. The applicable margins vary depending on the level of outstanding debt with escalating rates of 50 to 150 basis points above the Alternative Base Rate and escalating rates of 150 to 250 basis points for Eurodollar rate loans. At September 30, 2014, the lead bank’s prime rate was 3.25%. The commitment fee associated with the credit facility fluctuated between 0.38% and 0.50% for the three months ended September 30, 2014.

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 as defined in the terms of our credit facility) and limitations on incurring other debt. Since inception, no cash dividends have been declared on our common stock. As of September 30, 2014, we were in compliance with the provisions of this agreement. The credit facility is secured by our oil and natural gas properties. Under the terms of the credit facility, the commitment amount can be less than or equal to the total amount of the borrowing base with unanimous consent of the bank group as it might change from time to time.

Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $1.7 million and $1.6 million for the three months ended September 30, 2014 and 2013, respectively. Interest expense on the credit facility, including commitment fees and amortization of debt issuance costs, totaled $5.9 million and $4.0 million for the nine months ended September 30, 2014 and 2013, respectively. The amount of commitment fees included in interest expense, net was $0.2 million for the three months ended September 30, 2014 and 2013, and was $0.6 million and $0.9 million for the nine months ended September 30, 2014 and 2013.

Senior Notes Due In 2022. These notes consist of $400.0 million of 7.875% senior notes that will mature on March 1, 2022. On November 30, 2011, we issued $250.0 million of these senior notes at a discount of $2.1 million or 99.156% of par, which equates to an effective yield to maturity of 8%. The original discount of $2.1 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. On October 3, 2012, we issued an additional $150.0 million of these senior notes at 105% of par, which equates to a yield to worst of 6.993%. The premium of $7.5 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. 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 March 1 and September 1 and commenced on March 1, 2012. On or after March 1, 2017, we may redeem some or all of these notes, with certain restrictions, at a redemption price, plus accrued and unpaid interest, of 103.938% of principal, declining  in twelve-month intervals to 100% in 2020 and thereafter. In addition, prior to March 1, 2015, we may redeem up to 35% of the principal amount of the notes with the net proceeds of qualified offerings of our equity at a redemption price of 107.875% of the principal amount of the notes, plus accrued and unpaid interest. We incurred approximately $7.5 million of debt issuance costs related to these notes, which is included in “Other Long–Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

Interest expense on the senior notes due in 2022, including amortization of debt issuance costs and debt premium, totaled $7.9 million for the three months ended September 30, 2014 and 2013 and $23.7 million for the nine months ended September 30, 2014 and 2013.

Senior Notes Due In 2020. These notes consist of $225.0 million of 8.875% senior notes issued at 98.389% of par, which equates to an effective yield to maturity of 9.125%. The notes were issued on November 25, 2009 with an original discount of $3.6 million and will mature on January 15, 2020. The original discount of $3.6 million is recorded in “Long-Term Debt” on our condensed consolidated balance sheets and will be amortized over the life of the notes using the effective interest method. 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 January 15, 2010. 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. We incurred approximately $5.0 million of debt issuance costs related to these notes, which is included in “Other Long–Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

Interest expense on the senior notes due in 2020, including amortization of debt issuance costs and debt discount, totaled $5.2 million for the three months ended September 30, 2014 and 2013 and $15.6 million and $15.5 million for the nine months ended September 30, 2014 and 2013, respectively.

Senior Notes Due In 2017. These notes consist of $250.0 million of 7.125% senior notes due in 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. We may redeem some or all of these notes, with certain restrictions, starting at a redemption price of 102.375% of the principal, plus accrued and unpaid interest, declining in twelve-month intervals to 100% on June 1, 2015 and thereafter. We incurred approximately $4.2 million of debt issuance costs related to these notes, which is included in “Other Long-Term Assets” on the accompanying condensed 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, limitations on our ability to repurchase shares, incur debt, create liens, make investments, transfer or sell assets, enter into transactions with affiliates and consolidate, merge or transfer all or substantially all of our assets. We were in compliance with the provisions of the indenture governing these senior notes as of September 30, 2014.

Interest expense on the senior notes due in 2017, including amortization of debt issuance costs, totaled $4.6 million for the three months ended September 30, 2014 and 2013 and $13.7 million for the nine months ended September 30, 2014 and 2013.

XML

Acquisitions and Dispositions

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Acquisitions and Dispositions

(6)           Acquisitions and Dispositions

On July 15, 2014, we closed our transaction with Saka Energi to fully develop 8,300 acres of Fasken area Eagle Ford shale properties owned by Swift Energy in Webb County, Texas, with an effective date of January 1, 2014. Swift Energy sold a 36% full participating interest in the Fasken properties to Saka Energi for $175 million in total cash consideration, with $125 million paid at closing (subject to adjustments for the interim period between the effective date and the closing date) and $50 million in cash to be paid by Saka Energi over time to carry a portion of Swift Energy's field development costs incurred after the effective date. As of September 30, 2014, approximately $35 million remained of Saka Energi's original $50 million carry obligation. At closing, the company received approximately $147 million in proceeds, including a $12.5 million deposit received during the prior quarter which was held in an escrow account until the closing date, as well as adjustments for the interim period between the effective date and the closing date. The proceeds initially were used to reduce our outstanding borrowings on our credit facility which were partially offset by additional borrowings against the credit facility during the quarter to fund development expenditures. No gain or loss was recognized for the transaction as the proceeds were applied to the full cost pool.

XML

Condensed Consolidating Financial Information

9 Months Ended

Sep. 30, 2014

Guarantees [Abstract]

Condensed Consolidating Financial Information

(8)           Condensed Consolidating Financial Information

Swift Energy Company (the parent) is the issuer and Swift Energy Operating, LLC (a wholly owned indirect subsidiary of Swift Energy Company) is the sole guarantor of our senior notes due in 2017, 2020 and 2022. Swift Energy Company does not have any independent assets or operations. The guarantees on our senior notes due in 2017, 2020 and 2022 are full and unconditional. All subsidiaries of Swift Energy Company, other than Swift Energy Operating, LLC, are minor.

XML

Commitments and Contingencies Commitments and Contingencies (Details Textual) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]
Gas Transportation Commitment	$ 36.3

XML

Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock option activity

The following table represents stock option award activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Exercise Price
Options outstanding, beginning of period	1,488,314	$	33.38
Options granted	—	$	—
Options canceled	(90,527)	$	25.20
Options exercised	—	$	—
Options outstanding, end of period	1,397,787	$	33.88
Options exercisable, end of period	1,295,616	$	33.98

Restricted stock activity

The following table represents restricted stock award activity for the nine months ended September 30, 2014:

	Shares		Wtd. Avg. Grant Price
Restricted shares outstanding, beginning of period	1,267,110		$	21.54
Restricted shares granted	743,150		$	11.58
Restricted shares canceled	(139,973	)	$	15.16
Restricted shares vested	(308,825	)	$	34.27
Restricted shares outstanding, end of period	1,561,462		$	14.85

Restricted Stock Units Activity

The following table represents restricted stock unit activity for the nine months ended September 30, 2014:

	Shares	Wtd. Avg. Grant Price
Restricted stock units outstanding, beginning of period	189,700	$	15.01
Restricted stock units granted	185,250	$	11.68
Restricted stock units canceled	—	$	—
Restricted stock units vested	—	$	—
Restricted stock units outstanding, end of period	374,950	$	13.36

XML

Summary of Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Jul. 15, 2014	Dec. 31, 2013
Property and Equipment
Proved oil and gas properties	$ 5,755,886			$ 5,755,886				$ 5,600,279
Unproved oil and gas properties	65,767			65,767				71,452
Furniture, fixtures, and other equipment	41,997			41,997				42,368
Less - Accumulated depreciation, depletion, and amortization	(3,326,908)			(3,326,908)				(3,125,282)
Property and Equipment, Net	2,536,742			2,536,742				2,588,817
Accounts Payable and Accrued Liabilities
Trade accounts payable	25,624	[1]		25,624	[1]			30,769	[1]
Accrued operating expenses	14,451			14,451				16,016
Accrued payroll costs	11,212			11,212				10,938
Asset retirement obligation - current portion	13,292			13,292				15,859
Accrued taxes	9,626			9,626				5,845
Deferred liability	22,685	[2]		22,685	[2]		12,500	0	[2]
Other payables	3,603			3,603				2,891
Total accounts payable and accrued liabilities	100,493			100,493				82,318
Roll-forward of our asset retirement obligation
Asset Retirement Obligation recorded as of January 1				79,084
Accretion expense	1,445		1,478	4,246		4,732
Liabilities incurred for new wells and facilities construction				470
Reductions due to sold and abandoned wells				(2,914)
Revisions in estimates				(439)
Asset Retirement Obligation	$ 80,447			$ 80,447
Year 2014 [Member] | Natural Gas Derivative Contract [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBTU (Energy Item Type)	3,330,000			3,330,000
Derivative, Swap Type, Average Fixed Price	4.32			4.32
Year 2014 [Member] | Natural Gas Derivative Contract [Member] | Collar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBTU (Energy Item Type)	1,035,000			1,035,000
Derivative, Average Floor Price	4.15			4.15
Derivative, Average Cap Price	4.55			4.55
Year 2014 [Member] | Natural Gas Basis Derivative Contract [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBTU (Energy Item Type)	4,200,000			4,200,000
Derivative, Swap Type, Average Fixed Price	(0.11)			(0.11)
Year 2015 [Member] | Natural Gas Derivative Contract [Member] | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBTU (Energy Item Type)	900,000			900,000
Derivative, Swap Type, Average Fixed Price	4.42			4.42
Year 2015 [Member] | Natural Gas Basis Derivative Contract [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Future Gas Production Hedged in MMBTU (Energy Item Type)	8,200,000			8,200,000
Derivative, Swap Type, Average Fixed Price	(0.02)			(0.02)

[1] Included in “trade accounts payable” are liabilities of approximately $9.6 million and $26.1 million at September 30, 2014 and December 31, 2013, respectively, for outstanding checks.

[2] This amount equals the liability related to funds received from Saka Energi that are maintained in a restricted cash account. Refer to the "Short-Term Restricted Cash" discussion below for further information.

XML

Condensed Consolidated Statements of Stockholders' Equity (USD $) In Thousands		Total	Common Stock	Additional Paid-in Capital	Treasury Stock	Retained Earnings
Beginning Balance at Dec. 31, 2012		$ 1,052,783	$ 435	$ 748,517	$ (13,855)	$ 317,686
Stock issued for benefit plans		1,622		(1,171)	2,793
Stock options exercised		4		4
Purchase of treasury shares		(1,513)			(1,513)
Tax benefits from stock compensation		(1,607)		(1,607)
Employee stock purchase plan		946	1	945
Issuance of restricted stock			3	(3)
Amortization of share-based compensation		15,557		15,557
Net Income		(2,442)				(2,442)
Ending Balance at Dec. 31, 2013		1,065,350	439	762,242	(12,575)	315,244
Stock issued for benefit plans		1,909		(1,876)	3,785
Purchase of treasury shares		(954)			(954)
Employee stock purchase plan		824	1	823
Issuance of restricted stock			3	(3)
Amortization of share-based compensation		8,477		8,477
Net Income		14,743				14,743
Ending Balance at Sep. 30, 2014	[1]	$ 1,090,349	$ 443	$ 769,663	$ (9,744)	$ 329,987

[1] Unaudited

XML

Summary of Significant Accounting Policies

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

(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 gas properties, with a focus on inland waters and onshore oil and natural gas reserves in Louisiana and Texas. Our undivided interests in oil and gas properties 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.

Subsequent Events. We have evaluated subsequent events of our consolidated financial statements. There were no material subsequent events requiring additional disclosure in 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 amounts 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 therefrom,

• 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 sales, 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 share-based 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,

• estimates in the calculation of the fair value of hedging assets and liabilities, and

• estimates in the assessment of current litigation claims against the company.

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 adjustments occur.

We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated.

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 three months ended September 30, 2014 and 2013, such internal costs capitalized totaled $6.9 million and $7.9 million, respectively. For the nine months ended September 30, 2014 and 2013, such internal costs capitalized totaled $20.9 million and $23.9 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties. For the three months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $1.2 million and $1.8 million, respectively. For the nine months ended September 30, 2014 and 2013, capitalized interest on unproved properties totaled $3.7 million and $5.6 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 (in thousands):

	September 30, 2014			December 31, 2013 (As Restated)
Property and Equipment
Proved oil and gas properties	$	5,755,886		$	5,600,279
Unproved oil and gas properties	65,767			71,452
Furniture, fixtures, and other equipment	41,997			42,368
Less – Accumulated depreciation, depletion, and amortization	(3,326,908		)	(3,125,282		)
Property and Equipment, Net	$	2,536,742		$	2,588,817

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 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 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 two and 20 years. Repairs and maintenance are charged to expense as incurred.

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 price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”). This calculation is done on a country-by-country basis.

The calculations of the Ceiling Test and provision for DD&A are 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.

It is reasonably possible that our estimate of discounted future net cash flows from proved oil and natural gas reserves could change in the future and that non-cash write-downs of oil and natural gas properties could occur in the future. For example, if future capital expenditures out pace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline, non-cash write-downs of our oil and natural gas properties could occur. We cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties.

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 condensed consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying condensed consolidated balance sheets when our ownership share of production exceeds sales. As of September 30, 2014 and December 31, 2013, we did not have any material natural gas imbalances.

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

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At September 30, 2014 and December 31, 2013, we had an allowance for doubtful accounts of approximately $0.4 million and $0.1 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

At September 30, 2014, our “Accounts receivable” balance included $51.9 million for oil and gas sales, $1.9 million for joint interest owners, $7.9 million for severance tax credit receivables and $1.7 million for other receivables. At December 31, 2013, our “Accounts receivable” balance included $56.9 million for oil and gas sales, $1.6 million for joint interest owners, $11.6 million for severance tax credit receivables and $0.8 million for other receivables.

Debt Issuance Costs. Legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with extensions of our bank credit facility and public debt offerings were capitalized and are amortized on an effective interest basis over the life of each of the respective senior note offerings and credit facility.

The 7.125% senior notes due in 2017 mature on June 1, 2017, and the balance of their issuance costs at September 30, 2014, was $1.4 million. The 8.875% senior notes due in 2020 mature on January 15, 2020, and the balance of their issuance costs at September 30, 2014, was $3.2 million. The 7.875% senior notes due in 2022 mature on March 1, 2022, and the balance of their issuance costs at September 30, 2014, was $6.1 million. The balance of revolving credit facility issuance costs at September 30, 2014, was $2.5 million.

Price-Risk Management Activities. The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized in earnings. The changes in the fair value of our derivatives are recognized in "Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. 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 swaps, floors, calls, collars and participating collars.

During the three months ended September 30, 2014 and 2013, we recorded a net gain of $5.0 million and a net loss of $2.0 million, respectively, relating to our derivative activities. The 2014 amount includes a revenue increase of $1.2 million during the third quarter of 2014 for the non-cash fair value adjustments on commodity derivatives. For the nine months ended September 30, 2014 and 2013, we recorded net losses of $2.7 million and $0.8 million, respectively, relating to our derivative activities. The effects of our derivatives are included in the "Other" section of our operating activities on the accompanying condensed consolidated statements of cash flows.

The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. The fair value of our current unsettled derivative assets at September 30, 2014 was $0.7 million which was recognized on the accompanying condensed consolidated balance sheet in “Other current assets.” The fair values of our current and non-current unsettled derivative liabilities at September 30, 2014 were $0.5 million and $0.1 million which were recognized on the accompanying condensed consolidated balance sheet in “Accounts payable and accrued liabilities” and “Other Long-Term Liabilities”, respectively.

At September 30, 2014, we had $1.0 million in receivables for settled derivatives which were recognized on the accompanying condensed consolidated balance sheet in “Accounts receivable” and were subsequently collected in October 2014. At September 30, 2014, we also had $0.1 million in payables for settled derivatives which were recognized on the accompanying condensed consolidated balance sheet in "Accounts payable and accrued liabilities" and were subsequently paid in October 2014.

The Company uses an International Swap and Derivatives Association "ISDA" master agreement for our derivative contracts. This is an industry standardized contract containing the general conditions of our derivative transactions including provisions relating to netting derivative settlement payments under certain circumstances (such as default). For reporting purposes, the Company has elected to not offset the asset and liability fair value amounts of its derivatives on the accompanying balance sheets. If all counterparties were in a default situation, the Company, under the right of set-off, would have shown a net derivative fair value asset of $0.1 million and liability of $0.1 million at September 30, 2014 and December 31, 2013, respectively. For further discussion related to the fair value of the Company's derivatives, refer to Note 7 of these condensed consolidated financial statements.

The following tables summarize the weighted average prices and future production volumes for our unsettled derivative contracts in place as of September 30, 2014:

				Collars
Natural Gas Derivatives (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Swap Fixed Price		Floor Price		Ceiling Price
2014 Contracts
Swaps	3,330,000	$	4.32
Collars	1,035,000			$	4.15	$	4.55
2015 Contracts
Swaps	900,000	$	4.42

Natural Gas Basis Derivatives (East Texas Houston Ship Channel Settlements)	Total Volumes (MMBtu)	Swap Fixed Price
2014 Contracts
Swaps	4,200,000	$	(0.11	)
2015 Contracts
Swaps	8,200,000	$	(0.02	)

Supervision Fees. Consistent with industry practice, we charge a supervision fee to the wells we operate including our wells in which we own up to a 100% working interest. Supervision fees are recorded as a reduction to “General and administrative, net”, on the accompanying condensed consolidated statements of operations. Our supervision fees are based on COPAS industry guidelines. The amount of supervision fees charged for the three and nine months ended September 30, 2014 and 2013 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $3.5 million and $2.8 million for the three months ended September 30, 2014 and 2013, respectively and $9.2 million and $8.9 million for the nine months ended September 30, 2014 and 2013, respectively.

Inventories. Inventories consist primarily of tubulars and other equipment and supplies 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 $3.1 million and $3.5 million at September 30, 2014 and December 31, 2013, respectively.

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 policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At September 30, 2014, we did not have any accrued liability for uncertain tax positions and do not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months.

Our U.S. Federal income tax returns for 2007 forward, our Louisiana income tax returns from 1999 forward and our Texas franchise tax returns after 2008 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 jurisdiction returns are significant to our financial position.

For the nine months ended September 30, 2014, we recognized an income tax expense increase of $2.1 million related to a shortfall between the tax deduction received with respect to prior restricted stock grants that vested during the year versus the actual book expense recorded over the life of those grants.

Accounts Payable and Accrued Liabilities. The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):

	September 30, 2014		December 31, 2013 (As Restated)
Trade accounts payable (1)	$	25,624	$	30,769
Accrued operating expenses	14,451		16,016
Accrued payroll costs	11,212		10,938
Asset retirement obligation – current portion	13,292		15,859
Accrued taxes	9,626		5,845
Deposit liability (2)	22,685		—
Other payables	3,603		2,891
Total accounts payable and accrued liabilities	$	100,493	$	82,318

(1) Included in “trade accounts payable” are liabilities of approximately $9.6 million and $26.1 million at September 30, 2014 and December 31, 2013, respectively, for outstanding checks.

(2) This amount equals the liability related to funds received from Saka Energi that are maintained in a restricted cash account. Refer to the "Short-Term Restricted Cash" discussion below for further information.

Cash and Cash Equivalents. We consider all highly liquid instruments with an initial maturity of three months or less to be cash equivalents. These amounts do not include cash balances that are contractually restricted.

Short-Term Restricted Cash (Saka Energi Transaction). On July 15, 2014, we closed our transaction with PT Saka Energi Indonesia ("Saka Energi") to fully develop 8,300 acres of Fasken area Eagle Ford shale properties owned by Swift Energy in Webb County, Texas. Swift Energy sold a 36% full participating interest in the Fasken properties to Saka Energi.

Subject to the terms of the transaction, Swift Energy and Saka Energi are required to deposit cash on a monthly basis into a separate Swift Energy-owned bank account to fund their respective portions of the on-going Fasken development program for the following month. All cash deposited in the account is contractually restricted for use in the Fasken development program and therefore is recorded as restricted cash until the Company has performed the related development activities.

As of September 30, 2014, we recorded $34.5 million of restricted cash including $11.8 million for deposits from Swift Energy with the remaining deposits from Saka Energi. The restricted cash balance is reported in “Other current assets” while the related deposit liability is reported in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

During the quarter Saka Energi deposited $29.8 million into the account while $7.1 million was withdrawn from the account in order to fund on-going development operations in the Fasken area. The cash changes from the account relating to Saka Energi’s contributions are shown in the operating activities section of the accompanying condensed consolidated statements of cash flows. The cash changes from the account relating to Swift Energy’s contributions are reported in the investing activities section on the accompanying condensed consolidated statements of cash flows.

Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of September 30, 2014 and December 31, 2013, these assets were approximately $1.0 million. 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. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.

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 as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. 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):

	2014
Asset Retirement Obligation recorded as of January 1	$	79,084
Accretion expense	4,246
Liabilities incurred for new wells and facilities construction	470
Reductions due to sold and abandoned wells and facilities	(2,914		)
Revisions in estimates	(439		)
Asset Retirement Obligation as of September 30	$	80,447

At September 30, 2014 and December 31, 2013, approximately $13.3 million and $15.9 million of our asset retirement obligation was classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09, providing a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance. The guidance is effective for annual and interim reporting periods beginning after December 15, 2016 and upon adoption, entities are required to recognize revenue using the following five-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation. Adoption of this standard could result in retrospective application, either in the form of recasting all prior periods presented or a cumulative adjustment to equity in the period of adoption. We plan to review and assess the effect and implement any necessary requirements as needed.

XML

Accounting Changes and Error Corrections Accountings Changes and Error Corrections (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Income Statement [Abstract]
Oil and gas sales	$ 133,896	$ 152,981	$ 441,440	$ 442,015
Total Revenues	138,794	150,933	438,968	441,301
Depreciation, Depletion and Amortization	65,331	67,274	201,072	187,503
Lease operating cost	22,067	23,078	70,606	76,919
Transportation and gas processing	5,107	5,783	16,412	15,386
Severance and other taxes	10,191	11,695	28,829	32,221
Total Costs and Expenses	133,319	137,949	410,025	403,120
Income Before Income Taxes	5,475	12,984	28,943	38,181
Provision for Income Taxes	3,001	5,625	14,200	15,235
Net Income	2,474	7,359	14,743	22,946	(2,442)
Earnings Per Share, Basic	$ 0.06	$ 0.17	$ 0.34	$ 0.53
Earnings Per Share, Diluted	$ 0.06	$ 0.17	$ 0.33	$ 0.53
Statement of Cash Flows [Abstract]
Deferred income taxes			13,507	15,235
Other Noncash Income (Expense)			(390)	(4,093)
(Increase) Decrease in accounts receivable			14,159	(3,293)
Increase (decrease) in accounts payable and accrued liabilities			7,299	2,588
Net Cash Provided by Operating Activities			252,175	225,607
Scenario, Previously Reported [Member]
Income Statement [Abstract]
Oil and gas sales		155,049		442,418
Total Revenues		153,001		441,704
Depreciation, Depletion and Amortization		66,948		186,526
Lease operating cost		23,078		77,459
Transportation and gas processing		5,783		16,678
Severance and other taxes		11,695		31,971
Total Costs and Expenses		137,623		403,725
Income Before Income Taxes		15,378		37,979
Provision for Income Taxes		6,492		15,162
Net Income		8,886		22,817
Earnings Per Share, Basic		$ 0.20		$ 0.53
Earnings Per Share, Diluted		$ 0.20		$ 0.52
Statement of Cash Flows [Abstract]
Deferred income taxes				15,162
Other Noncash Income (Expense)				(3,796)
(Increase) Decrease in accounts receivable				(3,696)
Increase (decrease) in accounts payable and accrued liabilities				3,873
Net Cash Provided by Operating Activities				225,607
Restatement Adjustment [Member]
Income Statement [Abstract]
Oil and gas sales		(2,068)		(403)
Total Revenues		(2,068)		(403)
Depreciation, Depletion and Amortization		326		977
Lease operating cost		0		(540)
Transportation and gas processing		0		(1,292)
Severance and other taxes		0		250
Total Costs and Expenses		326		(605)
Income Before Income Taxes		(2,394)		202
Provision for Income Taxes		(867)		73
Net Income		(1,527)		129
Earnings Per Share, Basic		$ (0.03)		$ 0.00
Earnings Per Share, Diluted		$ (0.03)		$ 0.01
Statement of Cash Flows [Abstract]
Deferred income taxes				73
Other Noncash Income (Expense)				(297)
(Increase) Decrease in accounts receivable				403
Increase (decrease) in accounts payable and accrued liabilities				(1,285)
Net Cash Provided by Operating Activities				$ 0

XML

Summary of Significant Accounting Policies (Tables)

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Property and Equipment

The following is a detailed breakout of our “Property and Equipment” balances (in thousands):

	September 30, 2014			December 31, 2013 (As Restated)
Property and Equipment
Proved oil and gas properties	$	5,755,886		$	5,600,279
Unproved oil and gas properties	65,767			71,452
Furniture, fixtures, and other equipment	41,997			42,368
Less – Accumulated depreciation, depletion, and amortization	(3,326,908		)	(3,125,282		)
Property and Equipment, Net	$	2,536,742		$	2,588,817

Schedule of Derivative Instruments

The following tables summarize the weighted average prices and future production volumes for our unsettled derivative contracts in place as of September 30, 2014:

				Collars
Natural Gas Derivatives (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Swap Fixed Price		Floor Price		Ceiling Price
2014 Contracts
Swaps	3,330,000	$	4.32
Collars	1,035,000			$	4.15	$	4.55
2015 Contracts
Swaps	900,000	$	4.42

Natural Gas Basis Derivatives (East Texas Houston Ship Channel Settlements)	Total Volumes (MMBtu)	Swap Fixed Price
2014 Contracts
Swaps	4,200,000	$	(0.11	)
2015 Contracts
Swaps	8,200,000	$	(0.02	)

Accounts Payable and Accrued Liabilities

The “Accounts payable and accrued liabilities” balances on the accompanying condensed consolidated balance sheets are summarized below (in thousands):

	September 30, 2014		December 31, 2013 (As Restated)
Trade accounts payable (1)	$	25,624	$	30,769
Accrued operating expenses	14,451		16,016
Accrued payroll costs	11,212		10,938
Asset retirement obligation – current portion	13,292		15,859
Accrued taxes	9,626		5,845
Deposit liability (2)	22,685		—
Other payables	3,603		2,891
Total accounts payable and accrued liabilities	$	100,493	$	82,318

(1) Included in “trade accounts payable” are liabilities of approximately $9.6 million and $26.1 million at September 30, 2014 and December 31, 2013, respectively, for outstanding checks.

Roll-forward of our asset retirement obligations

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

	2014
Asset Retirement Obligation recorded as of January 1	$	79,084
Accretion expense	4,246
Liabilities incurred for new wells and facilities construction	470
Reductions due to sold and abandoned wells and facilities	(2,914		)
Revisions in estimates	(439		)
Asset Retirement Obligation as of September 30	$	80,447