Edgar Filing: SWIFT ENERGY CO

Document

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, 2016

Commission File Number 1-8754

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in Its Charter)



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

17001 Northchase Drive, Suite 100 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	o	Accelerated Filer	þ	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 by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d)of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.



Yes	þ	No	o

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)	10,034,354 Shares outstanding at November 1, 2016

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2016

INDEX



		Page
Part I	FINANCIAL INFORMATION

Item 1.	Condensed Consolidated Financial Statements

	Condensed Consolidated Balance Sheets	3

	Condensed Consolidated Statements of Operations	4

	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	30

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	47

Item 4.	Controls and Procedures	48

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	49
Item 1A.	Risk Factors	49
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	49
Item 3.	Defaults Upon Senior Securities	49
Item 4.	Mine Safety Disclosures	49
Item 5.	Other Information	49
Item 6.	Exhibits	49

SIGNATURES		51
Exhibit Index		52

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Condensed Consolidated Balance Sheets

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



	Successor			Predecessor
	September 30, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	2,447		$	29,460
Accounts receivable, net	21,343			21,704
Other current assets	3,247			10,683
Total Current Assets	27,037			61,847

Property and Equipment:
Property and Equipment, including $47,310 and $18,839 of unproved property costs not being amortized at the end of each period	569,325			6,035,757
Less – Accumulated depreciation, depletion, amortization & impairment	(160,117		)	(5,577,854		)
Property and Equipment, Net	409,208			457,903
Other Long-Term Assets	9,203			5,248
Total Assets	$	445,448		$	524,998
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities:
Accounts payable and accrued liabilities	$	33,394		$	7,663
Accrued capital costs	4,295			—
Accrued interest	1,704			490
Undistributed oil and gas revenues	10,441			—
Current portion of long-term debt	—			324,900
Total Current Liabilities	49,834			333,053

Long-Term Debt	254,000			—
Asset Retirement Obligations	55,361			56,390
Other Long-Term Liabilities	2,929			3,891
Liabilities subject to compromise	—			984,388
Commitments and Contingencies (Note 10)

Stockholders' Equity (Deficit):
Predecessor Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding	—			—
Predecessor Common stock, $.01 par value, 150,000,000 shares authorized, 44,771,258 shares issued and 44,591,863 shares outstanding	—			448
Predecessor Additional paid-in capital	—			776,358
Predecessor Treasury stock held, at cost, 179,395 shares	—			(2,491		)
Successor Preferred stock, $.01 par value, 10,000,000 shares authorized, none outstanding	—			—
Successor Common stock, $.01 par value, 40,000,000 shares authorized, 10,000,001 shares issued and 10,000,001 shares outstanding	100			—
Successor Additional paid-in capital	232,431			—
Accumulated deficit	(149,207		)	(1,627,039		)
Total Stockholders’ Equity (Deficit)	83,324			(852,724		)
Total Liabilities and Stockholders’ Equity (Deficit)	$	445,448		$	524,998

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

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



	Successor		Predecessor
	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
Revenues:
Oil and gas sales	$	47,959	$	60,024
Price-risk management and other, net	2,632		92
Total Revenues	50,591		60,116

Costs and Expenses:
General and administrative, net	11,691		8,679
Depreciation, depletion, and amortization	13,287		35,606
Accretion of asset retirement obligation	1,099		1,410
Lease operating costs	9,481		17,990
Transportation and gas processing	4,883		5,446
Severance and other taxes	2,683		4,613
Interest expense, net	5,880		19,438
Write-down of oil and gas properties	—		321,522
Loss on reorganization items, net	1,193		—
Total Costs and Expenses	50,197		414,704

Income (Loss) Before Income Taxes	394		(354,588		)

Provision (Benefit) for Income Taxes	—		—

Net Income (Loss)	$	394	$	(354,588	)

Per Share Amounts-

Basic: Net Income (Loss)	$	0.04	$	(7.96	)

Diluted: Net Income (Loss)	$	0.04	$	(7.96	)

Weighted Average Shares Outstanding - Basic	10,000		44,546

Weighted Average Shares Outstanding - Diluted	10,361		44,546

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

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



	Successor			Predecessor
	Period from April 23, 2016 through September 30, 2016			Period from January 1, 2016 through April 22, 2016			Nine Months Ended September 30, 2015
Revenues:
Oil and gas sales	$	78,540		$	43,027		$	195,663
Price-risk management and other, net	(7,296		)	(245		)	(1,041		)
Total Revenues	71,244			42,782			194,622

Costs and Expenses:
General and administrative, net	15,919			9,245			31,525
Depreciation, depletion, and amortization	26,621			20,439			138,392
Accretion of asset retirement obligation	1,931			1,610			4,156
Lease operating costs	17,262			14,933			54,188
Transportation and gas processing	9,069			6,090			15,855
Severance and other taxes	4,547			3,917			14,169
Interest expense, net	10,137			13,347			56,407
Write-down of oil and gas properties	133,496			77,732			1,084,595
(Gain) loss on reorganization items, net	1,469			(956,142		)	—
Total Costs and Expenses, Net of Gains	220,451			(808,829		)	1,399,287

Income (Loss) Before Income Taxes	(149,207		)	851,611			(1,204,665		)

Provision (Benefit) for Income Taxes	—			—			(80,133		)

Net Income (Loss)	$	(149,207	)	$	851,611		$	(1,124,532	)

Per Share Amounts-

Basic: Net Income (Loss)	$	(14.92	)	$	19.06		$	(25.31	)

Diluted: Net Income (Loss)	$	(14.92	)	$	18.64		$	(25.31	)

Weighted Average Shares Outstanding - Basic	10,000			44,692			44,431

Weighted Average Shares Outstanding - Diluted	10,000			45,697			44,431

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

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



	Common Stock			Additional Paid-in Capital			Treasury Stock			Retained Earnings (Accumulated Deficit)			Total
Balance, December 31, 2015 (Predecessor)	$	448		$	776,358		$	(2,491	)	$	(1,627,039	)	$	(852,724	)

Purchase of treasury shares (65,170 shares)	—			—			(5		)	—			(5		)
Issuance of restricted stock (229,690 shares)	2			(2		)	—			—			—
Amortization of share-based compensation	—			1,118			—			—			1,118
Net Income	—			—			—			851,611			851,611
Balance, April 22, 2016 (Predecessor)	$	450		$	777,474		$	(2,496	)	$	(775,428	)	$	—

Cancellation of Predecessor equity	$	(450	)	$	(777,474	)	$	2,496		$	775,428		$	—
Balance, April 22, 2016 (Predecessor)	$	—		$	—		$	—		$	—		$	—


Issuance of Successor common stock & warrants	$	100		$	229,299		$	—		$	—		$	229,399
Balance, April 22, 2016 (Successor)	$	100		$	229,299		$	—		$	—		$	229,399

Amortization of share-based compensation	—			3,132			—			—			3,132
Net Loss	—			—			—			(149,207		)	(149,207		)
Balance, September 30, 2016 (Successor)	$	100		$	232,431		$	—		$	(149,207	)	$	83,324

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

Swift Energy Company and Subsidiaries (in thousands)



	Successor			Predecessor
	Period from April 23, 2016 through September 30, 2016			Period from January 1, 2016 through April 22, 2016			Nine Months Ended September 30, 2015
Cash Flows from Operating Activities:
Net income (loss)	$	(149,207	)	$	851,611		$	(1,124,532	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
Depreciation, depletion, and amortization	26,621			20,439			138,392
Write-down of oil and gas properties	133,496			77,732			1,084,595
Accretion of asset retirement obligations	1,931			1,610			4,156
Deferred income taxes	—			—			(80,133		)
Share-based compensation expense	3,132			886			3,288
Loss (gain) on derivatives	7,308			—			(271		)
Cash settlements on derivatives	(1,100		)	—			2,299
Reorganization items (non-cash)	—			(977,696		)	—
Other	1,721			229			1,599
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other current assets	14,669			(5,474		)	11,841
Increase (decrease) in accounts payable and accrued liabilities	(10,202		)	(10,495		)	(4,768		)
Increase (decrease) in income taxes payable	—			—			(450		)
Increase (decrease) in accrued interest	1,041			(308		)	(7,606		)
Net Cash Provided by (Used in) Operating Activities	29,410			(41,466		)	28,410

Cash Flows from Investing Activities:
Additions to property and equipment	(36,794		)	(24,530		)	(126,752		)
Proceeds from the sale of property and equipment	594			48,661			977
Net Cash Provided by (Used in) Investing Activities	(36,200		)	24,131			(125,775		)

Cash Flows from Financing Activities:
Proceeds from bank borrowings	49,000			328,000			258,200
Payments of bank borrowings	(48,000		)	(324,900		)	(153,500		)
Net proceeds from issuances of common stock	—			—			302
Purchase of treasury shares	—			(4		)	(150		)
Payments of debt issuance costs	(502		)	(6,482		)	(571		)
Net Cash Provided by (Used In) Financing Activities	498			(3,386		)	104,281

Net increase (decrease) in Cash and Cash Equivalents	(6,292		)	(20,721		)	6,916

Cash and Cash Equivalents at Beginning of Period	8,739			29,460			406

Cash and Cash Equivalents at End of Period	$	2,447		$	8,739		$	7,322

Supplemental Disclosures of Cash Flow Information:

Cash paid during period for interest, net of amounts capitalized	$	8,021		$	10,367		$	62,012
Cash paid during period for income taxes	$	—		$	—		$	450
Cash paid for reorganization items	$	12,017		$	15,643		$	—
Changes in capital accounts payable and capital accruals	$	(17,554	)	$	1,843		$	(36,615	)
See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements (Unaudited)

Swift Energy Company and Subsidiaries

(1) General Information

The condensed consolidated financial statements included herein are unaudited and have been prepared by the Company and reflect necessary adjustments, all of which were of a recurring nature unless otherwise disclosed herein, and are in the opinion of our management necessary for a fair presentation. Certain information and 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 for the fiscal year ended December 31, 2015 as filed with the Securities and Exchange Commission on March 4, 2016 though, as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh start accounting. Our independent registered public accounting firm for the year ended December 31, 2015 expressed their audit opinion dated March 4, 2016 on such financial statements with a going concern uncertainty explanatory paragraph.

(1A) Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On December 31, 2015, Swift Energy Company ("Swift Energy," the "Company" or "we") and eight of its U.S. subsidiaries (the "Chapter 11 Subsidiaries") filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the U.S. Bankruptcy Code (the "Bankruptcy Code") in the U.S. Bankruptcy Court for the District of Delaware under the caption In re Swift Energy Company, et al (Case No. 15-12670). The Company and the Chapter 11 Subsidiaries received bankruptcy court confirmation of their joint plan of reorganization (the "Plan") on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016 (the "Effective Date").

Effect of the Bankruptcy Proceedings. During the bankruptcy proceedings, the Company conducted normal business activities and was authorized to pay and has paid (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, pre-petition amounts owed to pipeline owners that transport the Company's production, and funds belonging to third parties, including royalty holders and partners.

In addition, subject to certain specific exceptions under the Bankruptcy Code, the Chapter 11 filings automatically stayed most judicial or administrative actions against the Company and efforts by creditors to collect on or otherwise exercise rights or remedies with respect to pre-petition claims. As a result, we did not record interest expense on the Company’s senior notes for the period of January 1, 2016 through April 22, 2016 (as the predecessor). For that period, contractual interest on the senior notes totaled $21.6 million.

Plan of Reorganization. Pursuant to the Plan, the significant transactions that occurred upon emergence from bankruptcy were as follows:


•	the approximately $906 million of indebtedness outstanding on account of the Company’s senior notes, $75.0 million in borrowings under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for 88.5% of the post-emergence Company’s common stock;


•	the lenders under the DIP Credit Agreement (as defined and more fully described below) received an additional backstop fee consisting of 7.5% of the post-emergence Company’s common stock;


•	the Company’s pre-petition common stock was canceled and the current shareholders received 4% of the post-emergence Company’s common stock and warrants to purchase up to 30% of the reorganized Company's equity. See Note 1B of these condensed consolidated financial statements for more information;


•	claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;


•	the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence 5% or more of the outstanding common stock of the Company;


•	the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately $46.9 million including deposits received prior to the closing date; and

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•	the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (the "New Credit Facility") with an initial $320 million borrowing base was established. For more information refer to Note 5 of these condensed consolidated financial statements.

In accordance with the Plan, the post-emergence Company’s new board of directors was initially to be made up of seven directors consisting of the Chief Executive Officer, two directors appointed by Strategic Value Partners LLC ("SVP"), a former holder of the Company’s senior notes, two directors appointed by other former holders of the Company’s senior notes, one additional independent director and one independent new non-executive chairman of the Board. In addition, pursuant to the Plan, SVP and the other former holders of the Company’s senior notes were given certain continuing director nomination rights subject to minimum share ownership conditions.

DIP Credit Agreement. In connection with the pre-petition negotiations of the restructuring support agreement, certain holders of the Company’s senior notes agreed to provide the Company and the Chapter 11 Subsidiaries a debtor-in-possession credit facility (the “DIP Credit Agreement"). The DIP Credit Agreement provided for a multi-draw term loan of up to $75.0 million, which became available to the Company upon the satisfaction of certain milestones and contingencies. Upon emergence from bankruptcy, the Company had drawn down the entire $75.0 million available. Pursuant to the Plan, the borrowings under the DIP Credit Agreement, at the option of the lenders to the DIP Credit Agreement, converted into the post-emergence Company’s common stock, which was part of the 88.5% of the common stock distributed to the holders of the Company's senior notes and certain unsecured creditors. As such, the $75.0 million borrowed under the DIP Credit Agreement was not required to be repaid in cash and was terminated upon the Company’s exit from bankruptcy. For more information refer to Note 5 of these condensed consolidated financial statements.

Financial Statement Classification of Liabilities Subject to Compromise. Our financial statements included amounts classified as liabilities subject to compromise, a majority of which were equitized upon emergence from bankruptcy on April 22, 2016. See Note 1B of these condensed consolidated financial statements for more information.

(1B) Fresh Start Accounting

Upon the Company's emergence from Chapter 11 bankruptcy, the Company adopted fresh start accounting, pursuant to Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 852, “Reorganizations”, and applied the provisions thereof to its financial statements. The Company qualified for fresh start accounting because (i) the holders of existing voting shares of the pre-emergence debtor-in-possession, referred to herein to as the "Predecessor" or "Predecessor Company," received less than 50% of the voting shares of the post-emergence successor entity, which we refer to herein as the "Successor" or "Successor Company" and (ii) the reorganization value of the Company's assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. The Company applied fresh start accounting as of April 22, 2016, when it emerged from bankruptcy protection. Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares of the Successor Company caused a related change of control of the Company under ASC 852. Upon the application of fresh start accounting, Swift allocated the reorganization value to its individual assets based on their estimated fair values. Reorganization value represents the fair value of the Successor Company's assets before considering liabilities. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Plan, the Consolidated Financial Statements on or after April 22, 2016, are not comparable with the Consolidated Financial Statements prior to that date. References to “Successor” or “Successor Company” relate to the financial position and results of operations of the reorganized Company subsequent to April 22, 2016. References to “Predecessor” or “Predecessor Company” refer to the financial position and results of operations of the Company prior to April 22, 2016.

Reorganization Value. Reorganization value represents the fair value of the Successor Company’s total assets and is intended to approximate the amount a willing buyer would pay for the assets immediately after restructuring. Under fresh start accounting, we allocated the reorganization value to our individual assets based on their estimated fair values.

Our reorganization value is derived from an estimate of enterprise value. Enterprise value represents the estimated fair value of an entity’s long term debt and shareholders’ equity. In support of the Plan, the enterprise value of the Successor Company was estimated and approved by the bankruptcy court to be in the range of $460 million to $800 million. Based on the estimates and assumptions used in determining the enterprise value, as further discussed below, the Company estimated the enterprise value to be approximately $474 million. This valuation analysis was prepared using reserve information, development schedules, other financial information and financial projections and applying standard valuation techniques, including risked net asset value analysis and public comparable company analyses.

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Valuation of Oil and Gas Properties. The Company’s principal assets are its oil and gas properties, which the Company accounts for under the Full Cost Accounting method as described in Note 2. With the assistance of valuation experts, the Company determined the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the bankruptcy emergence date.

The Company’s Reserves Engineers developed full cycle production models for all of the Company’s developed wells and identified undeveloped drilling locations within the Company’s leased acreage. The undeveloped locations were categorized based on varying levels of risk using industry standards. The proved locations were limited to wells expected to be drilled in the Company’s five year plan. The locations were then segregated into geographic areas. Future cash flows before application of risk factors were estimated by using the New York Mercantile Exchange five year forward prices for West Texas Intermediate oil and Henry Hub natural gas with inflation adjustments applied to periods beyond five years. These prices were adjusted for typical differentials realized by the Company for location and product quality adjustments. Transportation cost estimates were based on agreements in place at the emergence date. Development and operating costs were based on the Company’s recent cost trends adjusted for inflation.

Risk factors were determined separately for each geographic area. Based on the geological characteristics of each area appropriate risk factors for each of the reserve categories were applied. The Company and its valuation experts considered production, geological and mechanical risk to determine the probability factor for each reserve category in each area.

The risk adjusted after tax cash flows were discounted at 12%. This discount factor was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected returns on equity for similar industry participants. The after tax cash flow computations included utilization of the Company’s unamortized tax basis in the properties as of the emergence date. Plugging and abandonment costs were included in the cash flow projections for undeveloped reserves but were excluded for developed reserves since the fair value of this liability was determined separately and included in the emergence date liabilities reported on the balance sheet.

From this analysis the Company concluded the fair value of its proved reserves was $509.4 million, and the value of its probable reserves was $45.5 million as of the effective date. The fair value of the possible reserves was determined to be de minimus and no value was therefore recognized. The value of probable reserves was classified as unevaluated costs. The Company also reviewed its undeveloped leasehold acreage and concluded that the fair value of its probable reserves appropriately captured the fair value of its undeveloped leasehold acreage. These amounts are reflected in the Fresh Start Adjustments item number 12 below.

The following table reconciles the enterprise value to the estimated fair value of the Successor Company's common stock as of the Effective Date (in thousands):



	April 22, 2016
Enterprise Value	$	473,660
Plus: Cash and cash equivalents	8,739
Less: Fair value of debt	(253,000		)
Less: Fair value of warrants	(14,967		)
Fair value of Successor common stock	$	214,432

Shares outstanding at April 22, 2016	10,000

Per share value	$	21.44

Upon issuance of the New Credit Facility on April 22, 2016, the Company received net proceeds of approximately $253 million and incurred debt issuance costs of approximately $7.0 million.

In accordance with the Plan, the Company issued two series of warrants (each for up to 15% of the reorganized Company's equity) to the former holders of the Company’s common stock, one to expire on the close of business on April 22, 2019 (the “2019 Warrants”) and the other to expire on the close of business on April 22, 2020 (the “2020 Warrants” and, together with the 2019 Warrants, the “Warrants”). Following the Effective Date, there were 2019 Warrants outstanding to purchase up to an aggregate of 2,142,857 shares of Common Stock at an initial exercise price of $80.00 per share. Following the Effective Date, there were 2020 Warrants outstanding to purchase up to an aggregate of 2,142,857 shares of Common Stock at an initial exercise price of $86.18 per share. All unexercised Warrants shall expire, and the rights of the holders of such Warrants (the “Warrant Holders”) to purchase

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Common Stock shall terminate at the close of business on the first to occur of (i) their respective expiration dates or (ii) the date of completion of (A) any Fundamental Equity Change (as defined in the Warrant Agreement) or (B) an Asset Sale (as defined in the Warrant Agreement). The fair value of the 2019 and 2020 Warrants was $3.26 and $3.73 per warrant, respectively. A Black- Scholes pricing model with the following assumptions was used in determining the fair value: strike price of $80 and $86.18; expected volatility of 70% and 65%; expected dividend rate of 0.0%; risk free interest rate of 1.01% and 1.19%; and expiration date of 3 and 4 years, respectively. The fair value of these warrants was estimated using Level 2 inputs (for additional discussion of the Level 2 inputs, refer to Note 7 of these condensed consolidated financial statements).

The following table reconciles the enterprise value to the estimated reorganization value as of the Effective Date (in thousands):



	April 22, 2016
Enterprise Value	$	473,660
Plus: Cash and cash equivalents	8,739
Plus: Other working capital liabilities	73,318
Plus: Other long-term liabilities	58,992
Reorganization value of Successor assets	$	614,709

Reorganization value and enterprise value were estimated using numerous projections and assumptions that are inherently subject to significant uncertainties and resolution of contingencies that are beyond our control. Accordingly, the estimates set forth herein are not necessarily indicative of actual outcomes, and there can be no assurance that the estimates, projections or assumptions will be realized.

Condensed Consolidated Balance Sheet. The adjustments set forth in the following condensed consolidated balance sheet reflect the effect of the consummation of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes highlight methods used to determine fair values or other amounts of the assets and liabilities as well as significant assumptions.

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The following table reflects the reorganization and application of ASC 852 on our condensed consolidated balance sheet as of April 22, 2016 (in thousands):



	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments				Successor Company
ASSETS
Current Assets:
Cash and cash equivalents	$	57,599		$	(48,860	)	(1)	$	—			$	8,739
Accounts receivable	34,278			(597		)	(2)	—				33,681
Other current assets	3,503			—				—				3,503
Total current assets	95,380			(49,457		)		—				45,923
Property and equipment	6,007,326			—				(5,448,759		)	(12)	558,567
Less - accumulated depreciation, depletion and amortization	(5,676,252		)	—				5,676,252			(12)	—
Property and equipment, net	331,074			—				227,493				558,567
Other Long-term assets	4,629			6,388			(3)	(798		)	(13)	10,219
Total Assets	$	431,083		$	(43,069	)		$	226,695			$	614,709



	Predecessor Company			Reorganization Adjustments				Fresh Start Adjustments					Successor Company
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	64,324		$	(4,666	)	(4)	$	(885	)	(14	)	$	58,773
Accrued capital costs	5,410			—				—					5,410
Accrued interest	768			(104		)	(5)	—					664
Undistributed oil and gas revenues	8,471			—				—					8,471
Current portion of debt	364,500			(364,500		)	(6)	—					—
Total current liabilities	443,473			(369,270		)		(885		)			73,318

Long-term debt	—			253,000			(7)	—					253,000
Asset retirement obligation	51,800			—				6,101			(14	)	57,901
Other long-term liabilities	2,124			—				(1,033		)	(15	)	1,091
Liabilities subject to compromise	911,381			(911,381		)	(8)	—					—
Total Liabilities	1,408,778			(1,027,651		)		4,183					385,310
Stockholders' Equity:
Preferred stock				—				—					—
Common stock (Predecessor)	450			(450		)	(9)	—					—
Common stock (Successor)	—			100			(10)	—					100
Additional paid-in capital (Predecessor)	777,475			(777,475		)	(9)	—					—
Additional paid-in capital (Successor)	—			229,299			(10)	—					229,299
Treasury stock held at cost	(2,496		)	2,496			(9)	—					—
Retained earnings (accumulated deficit)	(1,753,124		)	1,530,612			(11)	222,512			(16	)	—
Total Stockholders' Equity (Deficit)	(977,695		)	984,582				222,512					229,399
Total Liabilities and Stockholders' Equity	$	431,083		$	(43,069	)		$	226,695				$	614,709

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Reorganization Adjustments


1.	Reflects the net cash payments recorded as of the Effective Date from implementation of the Plan (in thousands):



Sources:
Net proceeds from New Credit Facility	253,000
Total Sources	$	253,000
Uses:
Repayment of Prior First Lien Credit Facility	289,500
Debt issuance costs	6,482
Predecessor accounts payable paid upon emergence	5,878
Total Uses	$	301,860
Net Uses	$	(48,860	)


2.	Reflects the impairment of a short-term leasehold improvement build-out receivable for $0.6 million that will no longer be reimbursed by the building lessor as the Company's office lease contract was rejected as part of the bankruptcy.

Reflects the capitalization of debt issuance costs on the New Credit Facility for $7.0 million, of which $6.5 million was paid on emergence and $0.5 million included in accounts payable and accrued liabilities and paid in the subsequent month, as well as the impairment of a long-term leasehold improvement build-out receivable for $0.6 million relating to an office lease contract that was rejected in connection with the bankruptcy.


4.	Reflects the settlement of predecessor accounts payable of $5.2 million partially offset by capitalized debt issuance costs of $0.5 million.


5.	Reflects the settlement of accrued interest on the Company's DIP Credit Agreement which was equitized upon emergence.


6.	On the Effective Date, the Company repaid in full all borrowings outstanding of $289.5 million under the Prior First Lien Credit Facility. In addition the Company equitized the outstanding DIP Credit Agreement borrowings of $75 million via the issuance of equity valued at $142.3 million.


7.	Reflects the $253 million in new borrowings under the New Credit Facility.


8.	Liabilities subject to compromise were settled as follows in accordance with the Plan (in thousands):




7.125% senior notes due 2017	$	250,000
8.875% senior notes due 2020	225,000
7.875% senior notes due 2022	400,000
Accrued interest	30,043
Accounts payable and accrued liabilities	1,713
Other long-term liabilities	4,625
Liabilities subject to compromise of the Predecessor Company (LSTC)	911,381
Fair value of equity issued to former holders of the senior notes of the Predecessor	(47,443		)
Gain on settlement of Liabilities subject to compromise	$	863,938


9.	Reflects the cancellation of the Predecessor Company equity to retained earnings.


10.	Reflects the issuance of 10.0 million shares of common stock at a per share price of $21.44 and 4.3 million warrants to purchase up to 30% of the reorganized Company's equity valued at $15.0 million with an average per unit value of $3.49. Former holders of the senior notes and certain unsecured creditors were issued 8.85 million shares of common stock while the Backstop

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Lenders (as defined in the DIP Credit Agreement) were issued 0.75 million shares of common stock. Former shareholders received the warrants and 0.4 million shares of common stock.


11.	Reflects the cumulative impact of the reorganization adjustments discussed above (in thousands):




Gain on settlement of Liabilities subject to compromise	$	863,938
Fair value of equity issued in excess of DIP principal	(67,329		)
Fair value of equity and warrants issued to Predecessor stockholders	(23,544		)
Fair value of equity issued to DIP lenders for backstop fee	(16,082		)
Other reorganization adjustments	(1,800		)
Cancellation of Predecessor Company equity	775,429
Net impact to accumulated deficit	$	1,530,612

Fresh Start Adjustments


12.	The following table summarizes the fair value adjustment on our oil and gas properties and accumulated depletion, depreciation and amortization (in thousands):



	Predecessor Company			Fresh Start Adjustments			Successor Company
Oil and Gas Properties
Proved properties	$	5,951,016		$	(5,441,655	)	$	509,361
Unproved properties	12,057			33,448			45,505
Total Oil and Gas Properties	5,963,073			(5,408,207		)	554,866
Less - Accumulated depletion and impairments	(5,638,741		)	5,638,741			—
Net Oil and Gas Properties	324,332			230,534			554,866

Furniture, Fixtures, and other equipment	44,252			(40,551		)	3,701
Less - Accumulated depreciation	(37,510		)	37,510			—
Net Furniture, Fixtures and other equipment	$	6,742		$	(3,041	)	$	3,701
Net Oil and Gas Properties, Furniture and fixtures and accumulated depreciation	$	331,074		$	227,493		$	558,567


13.	Reflects the adjustment of other non-current assets to fair value.


14.	Reflects the current and long-term portion of the Company’s asset retirement obligation computed in accordance with ASC 410-20, applying the appropriate discount rate to future costs as of the emergence date, which the Company has determined to be a reasonable fair value estimate.


15.	Reflects the adjustment of other non-current liabilities to fair value.


16.	Reflects the cumulative impact of fresh start adjustments as discussed above.

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Reorganization Items

Reorganization items represent liabilities settled, net of amounts incurred subsequent to the Chapter 11 filing as a direct result of the Plan and are classified as “(Gain) Loss on Reorganization items, net” in the Condensed Consolidated Statements of Operations. The following table summarizes reorganization items (in thousands):



	Successor			Predecessor
	Period from April 23, 2016 through September 30, 2016			Period from January 1, 2016 through April 22, 2016
Gain on settlement of liabilities subject to compromise	$	—		$	(863,938	)
Fair value of equity issued in excess of DIP principal	—			67,329
Fresh start adjustments	—			(222,512		)
Reorganization legal and professional fees and expenses	1,595			25,573
Fair value of equity issued to DIP lenders for backstop fee	—			16,082
Other reorganization items	(126		)	21,324
(Gain) Loss on Reorganization items, net	$	1,469		$	(956,142	)

(2) Summary of Significant Accounting Policies

Fresh Start Accounting. Upon emergence from bankruptcy the Company adopted Fresh Start Accounting, see Note 1B for further details.

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.

Reclassifications. Certain reclassifications have been made to prior periods’ reported amounts in the Consolidated Statement of Cash Flows in order to conform to the current period presentation. These reclassifications did not impact the Company’s net loss, stockholders’ equity or cash flows.

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 estimates of reorganization value, enterprise value and fair value of assets and liabilities upon emergence from bankruptcy and application of fresh start accounting,


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


•	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 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,

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•	estimates made in our income tax calculations,


•	estimates of the Liabilities subject to compromise versus not subject to compromise,


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


•	estimates in the assessment of current litigation claims against the Company, and


•	estimates in amounts due with respect to open state regulatory audits.

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 are expected to be recorded in the period during which the adjustments are known.

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, 2016 (successor) and the three months ended September 30, 2015 (predecessor), such internal costs capitalized totaled $2.0 million and $3.1 million, respectively. For the period of January 1, 2016 through April 22, 2016 (predecessor), period of April 23, 2016 through September 30, 2016 (successor) and the nine months ended September 30, 2015 (predecessor), such internal capitalized costs totaled $2.9 million, $3.5 million and $10.1 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 5 of these condensed consolidated financial statements for further discussion on capitalized interest costs).

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):



	Successor As of September 30, 2016			Predecessor As of December 31, 2015
Property and Equipment
Proved oil and gas properties	$	518,289		$	5,972,666
Unproved oil and gas properties	47,310			18,839
Furniture, fixtures, and other equipment	3,726			44,252
Less – Accumulated depreciation, depletion, amortization & impairment	(160,117		)	(5,577,854		)
Property and Equipment, Net	$	409,208		$	457,903

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.

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 (which excludes natural gas consumed in operations) during the period by the total estimated units of proved oil and natural gas reserves (which excludes natural gas consumed in operations) at the beginning of the period. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and gas property costs are amortized. The period over which we will amortize these properties is dependent on our production from these properties in future years.

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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, 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) 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”).

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.

Primarily due to pricing differences between the 12-month average oil and gas prices used in the Ceiling Test and the forward strip prices used to estimate the initial fair value of oil and gas properties on the Company’s April 22, 2016 (successor) balance sheet, we incurred a non-cash impairment write-down for the period of April 23, 2016 through September 30, 2016 (successor) of $133.5 million. As the full amount of this write-down was incurred at June 30, 2016, there was no such write-down for the three months ended September 30, 2016 (successor). Write-downs in prior periods were primarily the result of declining historical prices along with timing changes and reduction of projects and changes in our reserves product mix. For the three months ended September 30, 2015 (predecessor), we reported a non-cash impairment write-down of $321.5 million on our oil and natural gas properties. For the period of January 1, 2016 through April 22, 2016 (predecessor) and the nine months ended September 30, 2015 (predecessor), we reported non-cash impairment write-downs of $77.7 million, and $1.1 billion, respectively, on our oil and natural gas properties.

If future capital expenditures outpace 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, it is possible that non-cash write-downs of our oil and natural gas properties will occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties due to decreases in oil or natural gas prices.

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. The Company 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, 2016 and December 31, 2015, we did not have any material natural gas imbalances.

Accounts Receivable. We assess the collectability of accounts receivable, and based on our judgment, we accrue a reserve when we believe a receivable may not be collected. At September 30, 2016 and December 31, 2015, we had an allowance for doubtful accounts of less than $0.1 million and approximately $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.

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At September 30, 2016, our “Accounts receivable” balance included $15.7 million for oil and gas sales, $2.6 million for joint interest owners, $2.1 million for severance tax credit receivables and $0.9 million for other receivables. At December 31, 2015, our “Accounts receivable” balance included $14.9 million for oil and gas sales, $4.9 million for joint interest owners, $1.2 million for severance tax credit receivables and $0.7 million for other receivables.

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 allocated to each well based on general and administrative costs incurred for well maintenance and support. The amount of supervision fees charged for the three months ended September 30, 2016 (successor), the three months ended September 30, 2015 (predecessor), the period of January 1, 2016 through April 22, 2016 (predecessor), period of April 23, 2016 through September 30, 2016 (successor) and the nine months ended September 30, 2015 (predecessor) did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $1.7 million and $2.1 million for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively, and were $2.7 million, $3.0 million and $7.0 million for the period of January 1, 2016 through April 22, 2016 (predecessor), period of April 23, 2016 through September 30, 2016 (successor) and the nine months ended September 30, 2015 (predecessor), respectively.

Other Current Assets. Included in "Other current assets" on the accompanying condensed consolidated balance sheets are prepaid expenses totaling $2.5 million and $4.4 million at September 30, 2016 and December 31, 2015, respectively. These prepaid amounts cover well insurance, drilling contracts and various other prepaid expenses. Additionally inventories, which consist primarily of tubulars and other equipment and supplies, totaled $0.4 million at September 30, 2016 and $0.6 million at December 31, 2015.

Income Taxes. Deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

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 likelihood 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, 2016, 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 and state income tax returns for years prior to 2015 are subject to examination to the extent of our net operating loss (NOL) carryforwards. There are no material unresolved items related to periods previously audited by these taxing authorities.

The Company has evaluated the full impact of the reorganization on our carryover tax attributes and believes it will not incur an immediate cash income tax liability as a result of emergence from bankruptcy. The Company will be able to fully absorb cancellation of debt income with NOL carryforwards. The amount of remaining NOL carryforward available will be limited under IRC Sec. 382 due to the change in control. The Company’s amortizable tax basis exceeded the book carrying value of its assets at April 22 and September 30, 2016, leaving the Company in a net deferred tax asset position. Management has determined that it is not more likely than not that the Company will realize future cash benefits from this additional tax basis and remaining carryover items and accordingly has taken a full valuation allowance to offset its tax assets.

The Company expects to incur a net taxable loss in the current taxable period thus no current income taxes are anticipated to be paid and no benefit will be recorded due to the full valuation allowance of their tax assets.

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



	Successor As of September 30, 2016		Predecessor As of December 31, 2015
Trade accounts payable ⁽¹⁾	$	5,056	$	—
Accrued operating expenses ⁽¹⁾	3,126		—
Accrued compensation costs ⁽¹⁾	3,513		—
Asset retirement obligation – current portion	2,922		7,165
Accrued non-income based taxes ⁽¹⁾	6,505		—
Accrued price risk liabilities ⁽¹⁾	5,373		—
Accrued corporate and legal fees ⁽¹⁾	4,472		—
Other payables ⁽¹⁾⁽²⁾	2,427		498
Total accounts payable and accrued liabilities	$	33,394	$	7,663

(1) Classified as Liabilities subject to compromise as of December 31, 2015. Total Liabilities subject to compromise were $984.4 million as of December 31, 2015.

(2) Total balance at December 31, 2015 was $5.3 million, of which $4.8 million was classified as Liabilities subject to compromise with the remaining portion classified as "Other payables".

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.

Treasury Stock. Our treasury stock repurchases are reported at cost and are included “Treasury stock held, at cost" on the accompanying condensed consolidated balance sheets. All treasury stock was canceled upon emergence from bankruptcy and no new treasury stock existed at September 30, 2016.

Recognition of Severance Expense for Executive Retirements. On August 9, 2016, the Company announced that the Chief Executive Officer and Chief Financial Officer for the Company would be retiring. In the third quarter of 2016 we accrued $2.1 million for severance payments that will be paid out in accordance with their employment agreement. This amount was expensed in "General and administrative, net" in the condensed consolidated statement of operations for the three months ended September 30, 2016 (successor) and the period of April 23, 2016 through September 30, 2016 (successor), respectively. Additionally we accelerated expense related to the equity awards held by the retiring Chief Executive Officer and Chief Financial Officer. See Note 3 for more details.

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 requires entities 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. In August 2015, the FASB issued ASU 2015-14 which defers the effective date of previously issued ASU 2014-09 by one year for both public and private companies. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. We are currently reviewing the new requirements to determine the impact of this guidance on our financial statements.

In August 2014, the FASB issued ASU 2014-15, which provides guidance on determining when and how to disclose going-concern uncertainties in the financial statements. The new standard requires management to perform interim and annual assessments of an entity’s ability to continue as a going concern within one year of the date the financial statements are issued. An entity must provide certain disclosures if “conditions or events raise substantial doubt about the entity’s ability to continue as a going concern.” The guidance applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted.

In February 2016, the FASB issued ASU 2016-02, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods

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within those fiscal years. We are currently reviewing these new requirements to determine the impact of this guidance on our financial statements.

In March 2016, the FASB issued ASU 2016-09, which simplifies several aspects of the accounting for employee share based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with early adoption permitted. This standard was adopted by the Company as of the bankruptcy emergence date April 22, 2016. The adoption of this guidance did not result in any adjustments.

In August 2016, the FASB issued ASU 2016-15, which provides greater clarity to preparers on the treatment of eight specific items within an entity’s statement of cash flows with the goal of reducing existing diversity on these items. The guidance is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the ASU in an interim period, adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. We are currently reviewing these new requirements to determine the impact of this guidance on our financial statements.

(3) Share-Based Compensation

Emergence from Voluntary Reorganization

Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company’s common stock was canceled and new common stock was issued. The Company's previous share-based compensation awards were either vested or canceled upon the Company's emergence from bankruptcy.

Share-Based Compensation Plans

Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company's previous share-based compensation plans were canceled and the new Swift Energy Company 2016 Equity Incentive Plan was approved in accordance with the joint plan of reorganization. Under the previous share-based compensation plan the outstanding restricted stock awards and restricted stock unit awards for most employees vested under on an accelerated basis while awards issued to certain officers of the Company and the Board of Directors were canceled.

For awards granted after emergence from bankruptcy, the Company does not estimate the forfeiture rate during the initial calculation of compensation cost but rather has elected to account for forfeitures in compensation cost when they occur. For the predecessor periods the Company had estimated the forfeiture rate for share-based compensation during the initial calculation of compensation cost.

The Company computes a deferred tax benefit for restricted stock awards, unit awards and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock units the Company's actual tax deduction is based on the value of the units at the time of vesting. For the period of April 23, 2016 through September 30, 2016 (successor) no units vested. For the period of January 1, 2016 through April 22, 2016 (predecessor) the tax deduction realized was significantly less than the associated deferred tax asset, however the tax asset had been fully offset with a valuation allowance in prior periods so no incremental tax expense was realized. For the nine months ended September 30, 2015 (predecessor), we did recognize an income tax shortfall in earnings of $1.4 million, primarily related to restricted stock awards that vested at a price lower than the grant date fair value.

Share-based compensation for the predecessor and successor periods are not comparable. The 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 $2.9 million and $1.1 million for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor). For the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through September 30, 2016 (successor) the expense was $0.9 million and $3.1 million, respectively, while during the nine months ended September 30, 2015 (predecessor) the expense was $3.1 million.

We have not capitalized any share-based compensation for the three months ended September 30, 2016 (successor) and the period of April 23, 2016 through September 30, 2016 (successor). We capitalized $0.4 million and $1.0 million of share-based compensation for three and nine months ended September 30, 2015 (predecessor), respectively, and capitalized $0.2 million of share-based compensation for the period of January 1, 2016 through April 22, 2016 (predecessor). We view stock option awards

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and restricted stock unit awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and we amortize the awards on a straight-line basis over the life of the awards.

Stock Option Awards

On June 8, 2016, 105,811 stock option awards were granted to various officers and directors with an exercise price of $23.25. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the vesting period (generally one to three years). We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards with the following assumptions for stock option awards issued during the period of April 23, 2016 through September 30, 2016 (successor):



	Stock Option Valuation Assumptions
Expected Dividend	—
Expected volatility	69.3		%
Risk-free interest rate	1.42		%
Expected life of stock option awards (in years)	4
Weighted average grant-date fair value	$	12.64

To estimate expected volatility of our 2016 stock option grants we used the historical volatility of stock prices based on a group of our peer companies.

Restricted Stock Unit Awards

The 2016 equity incentive compensation plan allows for the issuance of restricted stock unit awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The compensation cost related to these awards is based on the grant date fair value and is typically expensed over the requisite service period (generally one to three years).

On June 8, 2016, 254,905 restricted stock unit awards were granted to various officers and directors with a grant-date fair value of $23.25. These grants generally vest over a period of one to three years.

The following table represents restricted stock unit award activity for the period of April 23, 2016 through September 30, 2016 (successor):



	Shares	Grant Date Price
Restricted stock units outstanding, beginning of period (successor)	—	$	—
Restricted stock units granted	254,905	$	23.25
Restricted stock units canceled	—	$	—
Restricted stock units vested	—	—
Restricted stock units outstanding, end of period (successor)	254,905	$	23.25

In accordance with their employment agreements, the Chief Executive Officer and Chief Financial Officer will vest in all of their share-based compensation awards in conjunction with their retirements. As such, all expense for their stock option awards and restricted stock unit awards was accelerated and is included in the share-based compensation expense for the three months ended September 30, 2016 (successor). The total expense included in the period for such awards was $1.6 million for 76,058 restricted stock unit awards and $0.7 million for 60,847 stock option awards. No shares were canceled or vested during the three months ended September 30, 2016 (successor).

(4) Earnings Per Share

Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company’s then outstanding common stock was canceled and new common stock and warrants were issued.

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

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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. As we recognized a net loss for the period of April 23, 2016 through September 30, 2016 (successor) and the three and nine months ended September 30, 2015 (predecessor), the unvested share-based payments and stock options were not recognized in Diluted EPS calculations as they would be antidilutive. Certain of our stock options and restricted stock grants that would potentially dilute Basic EPS in the future were also antidilutive for the period of January 1, 2016 through April 22, 2016 (predecessor), and are discussed below.

The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the periods indicated below (in thousands, except per share amounts):



	Successor Three Months Ended September 30, 2016					Predecessor Three Months Ended September 30, 2015
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)			Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	394	10,000	$	0.04	$	(354,588	)	44,546	$	(7.96	)
Dilutive Securities:
Restricted Stock Awards			—						—
Restricted Stock Unit Awards			255						—
Stock Option Awards			106						—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	394	10,361	$	0.04	$	(354,588	)	44,546	$	(7.96	)



	Successor from April 23, 2016 through September 30, 2016							Predecessor from January 1, 2016 through April 22, 2016					Nine Months Ended September 30, 2015
	Net Income (Loss)			Shares	Per Share Amount			Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)			Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(149,207	)	10,000	$	(14.92	)	$	851,611	44,692	$	19.06	$	(1,124,532	)	44,431	$	(25.31	)
Dilutive Securities:
Restricted Stock Awards				—						1,005						—
Restricted Stock Unit Awards				—						—						—
Stock Option Awards				—						—						—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(149,207	)	10,000	$	(14.92	)	$	851,611	45,697	$	18.64	$	(1,124,532	)	44,431	$	(25.31	)

All stock options to purchase shares and restricted stock unit awards were dilutive for the three months ended September 30, 2016 (successor) and were included in the table above.

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Approximately 1.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the period of January 1, 2016 through April 22, 2016 (predecessor), because the exercise price was out of the money, while 1.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three and nine months ended September 30, 2015 (predecessor), respectively, because these stock options were antidilutive.

Approximately 0.3 million restricted stock awards for the period of January 1, 2016 through April 22, 2016 (predecessor), and approximately 1.0 million and 0.8 million restricted stock awards for the three and nine months ended September 30, 2015 (predecessor), respectively, were not included in the computation of Diluted EPS because they were antidilutive.

Approximately 0.8 million shares for the period of January 1, 2016 through April 22, 2016 (predecessor) and approximately 1.2 million shares for the three and nine months ended September 30, 2015 (predecessor) 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.

(5) Long-Term Debt

Bankruptcy Filing. The Chapter 11 filing of the Company and the Chapter 11 Subsidiaries constituted an event of default with respect to our then-existing debt obligations. As a result, the Company's pre-petition unsecured senior notes and secured debt under the Prior First Lien Credit Facility became immediately due and payable, but any efforts to enforce such payment obligations were automatically stayed as a result of the Chapter 11 filing. On April 22, 2016, upon the Company's emergence from bankruptcy, the senior notes and borrowing under the DIP Credit Agreement (along with certain unsecured claims) were exchanged for 88.5% of the common stock of the reorganized entity. Additional information regarding the bankruptcy proceedings is included in Note 1A of these condensed consolidated financial statements.

Our debt balances as of September 30, 2016 and December 31, 2015, were as follows (in thousands):



	Successor As of September 30, 2016		Predecessor As of December 31, 2015
7.125% senior notes due 2017 ⁽¹⁾	$	—	$	—
8.875% senior notes due 2020 ⁽¹⁾	—		—
7.875% senior notes due 2022 ⁽¹⁾	—		—
Bank Borrowings	254,000		324,900
Total Debt	$	254,000	$	324,900
Less: Current portion of long-term debt ⁽²⁾	$	—	$	(324,900	)
Long-Term Debt	$	254,000	$	—
(1) Classified as Liabilities subject to compromise as of December 31, 2015.
(2) As a result of our Chapter 11 filing, we classified our Prior First Lien Credit Agreement borrowings and DIP Credit Agreement borrowings as current as of December 31, 2015.

New Credit Facility. As discussed in Note 1A of these condensed consolidated financial statements, on the Effective Date, the Prior First Lien Credit Facility was terminated and paid in full, and the Company entered the New Credit Facility among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto. The New Credit Facility matures on April 22, 2019 and provides for advancing loans of up to the maximum credit amount that the lenders, in the aggregate, make available, subject to the Company meeting certain financial requirements, including certain financial tests. As of the Effective Date, the maximum credit amount was $500.0 million with an initial borrowing base of $320.0 million. The obligations under the New Credit Facility are secured, subject to certain exceptions, by a first priority lien of the Company's, and certain of its subsidiaries, oil and natural gas properties containing at least 95% of the Company's estimated proved producing reserves. The terms of the New Credit Facility also include the following, based on terms as defined in the New Credit Facility agreement:

•

As of the Effective Date, the initial borrowing base of $320.0 million is allocated between a non-conforming borrowing base of $70 million, which terminates on November 1, 2017, and a conforming borrowing base of $250 million. Until November 1, 2017 if the conforming borrowing base is re-determined and increased or decreased, the non-conforming borrowing base will be automatically revised so that the amount of the overall borrowing base will equal the total borrowing base in effect immediately prior to such redetermination. Upon termination of the non-conforming borrowing base on November 1, 2017, all borrowings and interest under the non-conforming borrowing base are payable in full. As of

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September 30, 2016, the Company had borrowings of $4 million and $250 million on the non-conforming borrowing base and conforming borrowing base, respectively.


•	Borrowing base redeterminations are scheduled to occur semi-annually in November and May and are determined by the lenders in their discretion and in the usual and customary manner.


•	The interest rate for Alternative Base Rate ("ABR") loans will be based on the ABR plus the applicable margin, and the interest rate for Eurodollar loans will be based on the adjusted London Interbank Offered Rate (“LIBOR”), plus the applicable margin.

•

The applicable margins vary and have escalating rates of either (a) 500 to 600 basis points for ABR loans and 600 to 700 basis points for Eurodollar loans, during the non-conforming period, and depending on the level of the non-conforming borrowing base and the non-conforming borrowing base loans outstanding, or (b) 200 to 300 basis points for ABR loans and 300 to 400 basis points for Eurodollar loans depending on the borrowing base utilization percentage, after the non-conforming period or when the non-conforming borrowing base is zero. As of September 30, 2016, our average borrowing rate was 7.5%.

•

Certain covenants, including (a) a ratio of total debt to EBITDA as defined in the agreement not to exceed 6.5 to 1.0 for the quarter ending September 30, 2016, declining gradually over time to 3.5 to 1.0 for the quarter ending March 31, 2019, and thereafter, (b) a current ratio of not less than 1.0 to 1.0 at the end of each quarter beginning June 30, 2016, and (c) a minimum liquidity requirement of $10 million. As of September 30, 2016, the Company was in compliance with these new covenants and liquidity requirements.

Interest expense on the New Credit Facility, including commitment fees and amortization of debt issuance costs, totaled $6.1 million and $10.4 million for the three months ended September 30, 2016 (successor) and the period of April 23, 2016 through September 30, 2016 (successor), respectively. The amount of commitment fee amortization included in interest expense, net was less than $0.1 million and $0.1 million for the three months ended September 30, 2016 (successor) and the period of April 23, 2016 through September 30, 2016 (successor), respectively.

Additionally, we capitalized interest on our unproved properties in the amount $0.3 million for both the three months ended September 30, 2016 (successor) and the period of April 23, 2016 through September 30, 2016 (successor).

Senior Notes Liabilities. Senior Notes due in 2017 of $250.0 million, Senior Notes due in 2020 of $225.0 million and Senior Notes due in 2022 of $400.0 million are included in Liabilities subject to compromise in the Condensed Consolidated Balance Sheet as of December 31, 2015. These notes were canceled upon emergence from bankruptcy.

Prior First Lien Credit Facility Liabilities. Amounts outstanding under our pre-petition Prior First Lien Credit Facility due in 2017 of $324.9 million were classified as a current liability in the Condensed Consolidated Balance Sheet dated as of December 31, 2015 due to cross-default provisions as a result of the bankruptcy filings.

Debtor-In-Possession Financing. As part of the Chapter 11 filings, we entered into the DIP Credit Agreement. The proceeds of borrowings under the DIP Credit Agreement were primarily used to pay down the pre-petition Prior First Lien Credit Facility upon emergence from bankruptcy, and were also used to pay certain costs, fees and expenses related to the Chapter 11 cases, authorized pre-petition claims, and amounts due in connection with the DIP Credit Agreement, including on account of certain “adequate protection” obligations. Pursuant to the Plan, the DIP Credit Agreement, at the option of the lenders, converted into the post-emergence Company’s common stock, which was part of the 88.5% of the common stock distributed to the then current holders of the senior notes and certain unsecured creditors upon emergence from the bankruptcy proceedings. As a result, the $75.0 million borrowed under the DIP Credit Agreement was not required to be repaid and terminated upon the Company’s exit from bankruptcy.

We paid the lenders under the DIP Credit Agreement a 3.0% commitment fee, at the time funds were made available under the facility, totaling $0.9 million. The commitment fee was included in interest expense during the period of January 1, 2016 through April 22, 2016 (predecessor). Total interest expense on the DIP Credit Agreement was $6.4 million during the period of January 1, 2016 through April 22, 2016 (predecessor).

Prior First Lien Credit Facility Bank Borrowings. We had $324.9 million in outstanding borrowings under our Prior First Lien Credit Facility at December 31, 2015. The interest rate on our Prior First Lien Credit Facility was 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 was 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 then applied. The applicable margins varied depending on the level of outstanding debt with escalating rates of 100 to 200 basis points above the Alternative Base Rate and escalating rates of 200 to

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300 basis points above the Eurodollar rate loans. The commitment fee terms associated with the Prior First Lien Credit Facility were 0.50%. During the bankruptcy proceedings we paid interest on our Prior First Lien Credit Facility in the normal course.

Interest expense on the Prior First Lien Credit Facility, including commitment fees and amortization of debt issuance costs, totaled $2.3 million for the three months ended September 30, 2015 (predecessor) and $6.8 million and $6.3 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and nine months ended September 30, 2015 (predecessor), respectively. The amount of commitment fees included in interest expense, net was $0.1 million for the three months ended September 30, 2015 (predecessor) and not material for the period of January 1, 2016 through April 22, 2016 (predecessor) and $0.5 million for the nine months ended September 30, 2015 (predecessor).

Additionally, we capitalized interest on our unproved properties in the amount $1.2 million and $3.6 million for the three and nine months ended September 30, 2015 (predecessor), respectively. Capitalized interest on our unproved properties would have been immaterial for the period of January 1, 2016 through April 22, 2016 (predecessor) and therefore we did not capitalize any interest.

Senior Notes Due 2022. These notes consisted of $400.0 million of 7.875% senior notes due 2022 that were scheduled to mature on March 1, 2022. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. On April 22, 2016, the obligations of the Company and the Chapter 11 Subsidiaries with respect to these notes were canceled pursuant to the plan of reorganization and the holders thereof were issued common stock of the post-emergence entity in exchange therefor.

Senior Notes Due 2020. These notes consisted of $225.0 million of 8.875% senior notes due 2020 issued at 98.389% of par, which equated to an effective yield to maturity of 9.125%. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. On April 22, 2016, the obligations of the Company and the Chapter 11 Subsidiaries with respect to these notes were canceled pursuant to the plan of reorganization and the holders thereof were issued common stock of the post-emergence entity in exchange therefor.

Senior Notes Due 2017. These notes consisted 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 were scheduled to mature on June 1, 2017. The filing of the petition for bankruptcy protection constituted an “event of default” under the indenture governing these senior notes. On April 22, 2016, the obligations of the Company and the Chapter 11 Subsidiaries with respect to these notes were canceled pursuant to the plan of reorganization and the holders thereof were issued common stock of the post-emergence entity in exchange therefor.

Debt Issuance Costs. Our policy is to capitalize legal fees, accounting fees, underwriting fees, printing costs, and other direct expenses associated with our senior notes, amortizing those costs on an effective interest basis over the term of the senior notes, while issuance costs related to a line of credit arrangement are capitalized and then amortized ratably over the term of the line of credit arrangement, regardless of whether there are any outstanding borrowings.

Interest Expense on Senior Notes. There was no interest expense on the senior notes, for the period of January 1, 2016 through April 22, 2016 (predecessor) due to our bankruptcy proceedings. Contractual interest on the senior notes for the period of January 1, 2016 through April 22, 2016 (predecessor) totaled $21.6 million. Interest expense on the senior notes totaled $17.7 million and $53.0 million for the three and nine months ended September 30, 2015 (predecessor).

(6) Acquisitions and Dispositions

On April 15, 2016, we closed our transaction with Texegy LLC for the sale of a 75% working interest share of the Company's holdings in the South Bearhead Creek and Burr Ferry field areas located in Central Louisiana. The net proceeds of $46.9 million received by the Company in this transaction, including deposits received prior to the closing date, were credited to the full cost pool and used primarily to reduce the amount of borrowings under the Company’s Prior First Lien Credit Facility, and for other general corporate purposes. This disposition also included the buyer's assumption of approximately $6.5 million of plugging and abandonment liability. No gain or loss was recorded on the sale of this property.

Effective April 25, 2016, we disposed of our Masters Creek field in Central Louisiana. We received net proceeds of less than $0.1 million and the buyer's assumption of approximately $8.1 million of plugging and abandonment liability. No gain or loss was recorded on the sale of this property.

Effective September 30, 2016, we closed our transaction with Blue Marble Resources LLC for the sale of the Company's holdings in our Sun TSH field located in South Texas. We received net proceeds of approximately $0.9 million and the buyer

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assumed approximately $1.8 million of plugging and abandonment liability. No gain or loss was recorded on the sale of the property.

There were no other material acquisitions or dispositions during the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through September 30, 2016 (successor) or the nine months ended September 30, 2015 (predecessor).

(7) Price-Risk Management Activities

Derivatives are recorded on the balance sheet at fair value with changes in fair value 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.

During the three months ended September 30, 2016 (successor) and for the period of April 23, 2016 through September 30, 2016 (successor) there was a $2.6 million gain and $7.3 million loss, respectively. There were no cash settlements for derivatives during the period of April 23, 2016 through June 30, 2016. The Company made net cash payments of $1.1 million for settled derivative contracts during the three months ended September 30, 2016 (successor). During the three and nine months ended September 30, 2015 (predecessor) there was a net gain of less than $0.1 million and a net gain of $0.3 million, respectively, related to our derivative activities. There were no derivative instruments outstanding during the period of January 1, 2016 through April 22, 2016.

At September 30, 2016, we had $0.1 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 2016. At September 30, 2016, we also had $0.4 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 2016.

The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. There was $0.2 million in current unsettled derivative assets, while our long-term unsettled derivative assets were not material. There was $5.0 million and $1.1 million in current and long-term unsettled derivative liabilities, respectively, as of September 30, 2016.

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. Under the right of set-off, there was $5.9 million in net fair value liability at September 30, 2016. For further discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements.

The following tables summarize the weighted average prices as well as future production volumes for our unsettled derivative contracts in place as of September 30, 2016:



Oil Derivative Swaps (NYMEX WTI Settlements)	Total Volumes (Bbls)	Weighted Average Price
2016 Contracts
4Q16	155,997	$	48.28

2017 Contracts
1Q17	106,245	$	48.04
2Q17	97,401	$	48.13
3Q17	90,000	$	48.16
4Q17	84,798	$	48.18

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Natural Gas Derivative Swaps (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Weighted Average Price
2016 Contracts
4Q16	3,500,002	$	2.75

2017 Contracts
1Q17	3,975,000	$	2.89
2Q17	3,625,005	$	2.80
3Q17	3,339,999	$	2.81
4Q17	3,125,001	$	2.83



Natural Gas Basis Derivative Swap (East Texas Houston Ship Channel vs NYMEX Settlements)	Total Volumes (MMBtu)	Weighted Average Price
2016 Contracts
4Q16	3,500,002	$	(0.06	)

2017 Contracts
1Q17	3,975,000	$	(0.06	)
2Q17	3,625,005	$	(0.04	)
3Q17	3,339,999	$	(0.04	)
4Q17	3,125,001	$	(0.05	)

(8) Fair Value Measurements

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

The carrying amount of the revolving long-term debt approximates fair value because the Company's current borrowing base rate does not materially differ from market rates for similar bank borrowings.

Based upon quoted market prices as of December 31, 2015, the fair value and carrying value of our senior notes was as follows (in millions):



	Predecessor As of December 31, 2015
	Fair Value		Carrying Value
7.125% senior notes due 2017	$	23.0	$	250.0
8.875% senior notes due 2020	$	21.4	$	225.0
7.875% senior notes due 2022	$	34.5	$	400.0

Our senior notes due in 2017, 2020 and 2022 were stated at carrying value on our accompanying condensed consolidated balance sheets until they were canceled as part of the Company's plan of reorganization and emergence from bankruptcy. If we had recorded these notes at fair value they would have been Level 1 in our fair value hierarchy as they were traded in an active market with quoted prices for identical instruments until they were canceled.

The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):

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.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of September 30, 2016, and are categorized using the fair value hierarchy. As of December 31, 2015, all of the Company's hedging agreements had settled. For additional discussion related to the fair value of the Company's derivatives, refer to Note 7 of these condensed consolidated financial statements.



	Fair Value Measurements at
	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
September 30, 2016
Assets
Natural Gas Basis Derivatives	$	0.1	$	—	$	0.1	$	—
Oil Derivatives	0.1		—		0.1		—
Liabilities
Natural Gas Derivatives	4.4		—		4.4		—
Natural Gas Basis Derivatives	0.3		—		0.3		—
Oil Derivatives	$	1.4	$	—	$	1.4	$	—

Our current and long-term 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”, "Other long-term assets", "Accounts payable and accrued liabilities" and "Other long-term liabilities", respectively.

(9) Asset Retirement Obligations

Liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets are initially recorded at fair value in the period in which they are incurred. When a liability is initially recorded, the carrying amount of the related 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.

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Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company applied fresh start accounting. This included adjusting the Asset Retirement Obligations based on the estimated fair values at April 22, 2016. The following provides a roll-forward of our asset retirement obligations (in thousands):



	2016
Asset Retirement Obligations recorded as of January 1 (Predecessor)	$	63,555
Accretion expense	1,610
Liabilities incurred for new wells and facilities construction	1
Reductions due to sold wells and facilities	(6,545		)
Reductions due to plugged wells and facilities	(85		)
Revisions in estimates	488
Asset Retirement Obligations as of April 22 (Predecessor)	$	59,024
Fair value fresh start adjustment	$	5,216


Asset Retirement Obligations as of April 22 (Successor)	$	64,240
Accretion expense	1,931
Liabilities incurred for new wells and facilities construction	15
Reductions due to sold wells and facilities	(9,971		)
Reductions due to plugged wells and facilities	(916		)
Revisions in estimates	2,984
Asset Retirement Obligations as of September 30 (Successor)	$	58,283

At September 30, 2016 and December 31, 2015, approximately $2.9 million and $7.2 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

(10) Commitments and Contingencies

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

We had no material changes in our contractual commitments during the three months ended September 30, 2016 (successor).

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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 for the year ended December 31, 2015. The following information contains forward-looking statements; see “Forward-Looking Statements” on page 45 of this report.

Company Overview

As discussed in Notes 1A and 1B, the Company applied fresh start accounting upon emergence from bankruptcy on the Effective Date which resulted in the Company becoming a new entity for financial reporting purposes. The effects of the Plan and the application of fresh-start accounting were reflected in our condensed consolidated financial statements as of April 22, 2016 and the related adjustments thereto were recorded in our condensed consolidated statements of operations as reorganization items for the period April 1, 2016 to April 22, 2016 (predecessor). References to the Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date.

We are an independent oil and natural gas company formed in 1979 engaged in the exploration, development, acquisition and operation of oil and natural gas properties, with a focus on our reserves and production from our South 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. Natural gas production accounted for 76% of our volumetric production and 60% of our sales revenue for our initial successor reporting period of April 23, 2016 to September 30, 2016 (successor).

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

On December 31, 2015, Swift Energy Company ("Swift Energy," the "Company" or "we") and eight of its U.S. subsidiaries (the “Chapter 11 Subsidiaries”) filed voluntary petitions seeking relief under Chapter 11 of Title 11 of the U.S. Bankruptcy Code (the "Bankruptcy Code") in the U.S. Bankruptcy Court for the District of Delaware under the caption In re Swift Energy Company, et al (Case No. 15-12670). The Company and the Chapter 11 Subsidiaries received bankruptcy court confirmation of their joint plan of reorganization (the "Plan") on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016 (the "Effective Date").

Plan of Reorganization. Pursuant to the Plan, the significant transactions that occurred upon emergence from bankruptcy were as follows:


•	the approximately $906 million of indebtedness outstanding on account of the Company’s senior notes, the $75 million drawn under the Company's DIP Credit Agreement (described below) and certain other unsecured claims were exchanged for 88.5% of the post-emergence Company’s common stock;


•	the lenders under the DIP Credit Agreement (as defined and more fully described below) received a backstop fee consisting of 7.5% of the post-emergence Company’s common stock which was not included in the 88.5% distributed to creditors;


•	the Company’s pre-petition common stock was canceled and the current shareholders received 4% of the post-emergence Company’s common stock and warrants to purchase up to 30% of the reorganized Company's equity;


•	the warrants (each for up to 15% of the reorganized Company's equity), are exercisable at prices that represent a substantial increase from the value at emergence, as follows:

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Issue Date	Expiration Date	Shares	Strike Price
April 22, 2016	April 22, 2019	2,142,857	$80.00
April 22, 2016	April 22, 2020	2,142,857	$86.18


•	claims of other creditors were paid in full in cash, reinstated or otherwise treated in a manner acceptable to the creditors;


•	the Company entered into a registration rights agreement to provide customary registration rights to certain holders of the Company’s post-emergence common stock who, together with their affiliates received upon emergence 5% or more of the outstanding common stock of the Company;


•	the Company sold (effective April 15, 2016) a portion of its interest in its Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, for net proceeds of approximately $46.9 million including deposits received prior to the closing date; and


•	the Company's previous credit facility (the "Prior First Lien Credit Facility") was terminated and a new senior secured credit facility (the "New Credit Facility") with an initial $320 million borrowing base was established. For more information refer to Note 5 of these condensed consolidated financial statements.

In accordance with the Plan, the post-emergence Company’s new board of directors was initially to be made up of seven directors consisting of the Chief Executive Officer, two directors appointed by Strategic Value Partners LLC ("SVP"), a former holder of the Company’s senior notes, two directors appointed by other former holders of the Company’s senior notes, one independent director and one independent non-executive chairman of the Board. In addition, pursuant to the Plan, SVP and the other former holders of the Company’s senior notes were given certain continuing director nomination rights subject to minimum share ownership conditions.

DIP Credit Agreement. During the bankruptcy, we had a debtor-in-possession credit facility (the “DIP Credit Agreement") that provided for a multi-draw term loan of up to $75.0 million, which became available to the Company upon the satisfaction of certain milestones and contingencies. Upon emergence from bankruptcy, the Company had drawn down the entire $75.0 million available. Pursuant to the Plan, the borrowings under the DIP Credit Agreement, at the option of the lenders to the DIP Credit Agreement, converted into the post-emergence Company’s common stock, which was part of the 88.5% of the common stock distributed to the holders of the Company's senior notes and certain unsecured creditors. As such, the $75.0 million borrowed under the DIP Credit Agreement was not required to be repaid in cash and terminated upon the Company’s exit from bankruptcy. For more information refer to Note 5 of these condensed consolidated financial statements.

Fresh Start Accounting. Upon the Company’s emergence from Chapter 11 bankruptcy, the Company adopted fresh-start accounting in accordance with the provisions of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") 852, "Reorganizations" which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical condensed consolidated balance sheet. The effects of the Plan and the application of fresh-start accounting were reflected in our condensed consolidated financial statements as of April 22, 2016 and the related adjustments thereto were recorded in our condensed consolidated statements of operations as reorganization items for the period April 1, 2016 to April 22, 2016 (predecessor).

As a result, our condensed consolidated balance sheets and condensed consolidated statement of operations subsequent to the Effective Date will not be comparable to our condensed consolidated balance sheets and statements of operations prior to the Effective Date. Our condensed consolidated financial statements and related footnotes are presented with a black line division which delineates the lack of comparability between amounts presented on or after April 22, 2016 and dates prior. Our financial results for future periods following the application of fresh-start accounting will be different from historical trends and the differences may be material.

References to Successor relate to the Company on and subsequent to the Effective Date. References to Predecessor refer to the Company prior to the Effective Date. The condensed consolidated financial statements of the Successor have been prepared assuming that the Company will continue as a going concern and contemplate the realization of assets and the satisfaction of liabilities in the normal course of business.

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Significant Developments During Our Third Quarter of 2016

•

Management Changes: On August 9, 2016, the Company announced that the Chief Executive Officer and Chief Financial Officer of the Company would be retiring. The Company is actively engaged in finding full time replacements for these key positions. On September 27, 2016, the Company announced the appointment of Marcus C. Rowland as the non-executive Chairman of the Board, a position that was previously filled on an interim basis by another member of the Board since the Company’s emergence from its Chapter 11 restructuring. Further, on October 7, 2016, the Company announced that Robert J. Banks (current Chief Operating Officer) will also serve as interim Chief Executive Officer of the Company, filling the position vacated by the retirement of Terry E. Swift on the same date.

•

Weak crude oil and natural gas prices continue to affect our business: Oil and gas prices declined during 2015 and continue to remain relatively low by historical measures. While we are negatively impacted by weak commodity prices, the resulting industry downturn has created a much more competitive environment among oil field service companies, providing an opportunity for us to bring our cost structure in line with lower revenues. The recent rebound of oil and gas prices from their 2016 lows has allowed the Company to enter into price and basis differential hedges for a portion of calendar year 2017 production, which would mitigate any future commodity price weakness.

•

Operational Activity: At our Fasken field in the Eagle Ford play, eight wells were placed into the system during the first nine months of 2016. Seven wells were placed into the system at rates between 15 - 20 MMcf per day of natural gas and one well had mechanical issues and was placed into the system at a restricted rate of 9 MMcf per day of natural gas. The Company resumed drilling operations at Fasken in October 2016 and expects to drill four wells by the end of the year. These four wells are expected to come online in early 2017.

•

2016 cost reduction initiatives: We are continuing the cost reduction efforts initiated in 2015, and have taken additional actions during the first nine months of 2016 to significantly reduce our operating and overhead costs. In conjunction with our reorganization through Chapter 11 bankruptcy, we have renegotiated a number of contracts with vendors and service providers to bring costs in line with current market conditions. Additionally, we have undertaken several field realignment projects. For example, in Lake Washington, our primary field in South East Louisiana, we have reconfigured our gathering system in order to consolidate production handling from four platforms down to a single platform. Other initiatives include field staff reductions, intermittent production of marginal properties, disposition of uneconomic properties, full utilization of existing facilities, and elimination of redundant equipment. At the corporate level we have also undergone significant staff reductions, reduced the square footage of leased office space and are taking additional steps to further reduce overhead costs.

•

Strategic Dispositions: Effective September 30, 2016, we closed our transaction with Blue Marble Resources LLC for the sale of the Company's holdings in our Sun TSH field located in South Texas. We received net proceeds of approximately $0.9 million and the buyer assumed approximately $1.8 million of plugging and abandonment liability. No gain or loss was recorded on the sale of the property. In addition to this completed sale, we are continuing to evaluate dispositions of properties outside of our core Eagle Ford assets.

•

Stock Listing: Trading in the Company’s common stock on the NYSE was suspended intra-day on December 18, 2015, and the common stock was subsequently delisted. The common stock of the Company traded on the OTC Pink marketplace under the symbol “SFYWQ” until the common stock was canceled on April 22, 2016, pursuant to the plan of reorganization confirmed by the bankruptcy court. On October 3, 2016, the Company announced the common stock of the Company was approved for trading on the OTCQX Best Market. The Company trades under the ticker "SWTF".

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Summary of 2016 Financial Results

•

2016 year-to-date revenues and net income (loss): The Company's oil and gas revenues were $43.0 million and $78.5 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through September 30, 2016 (successor), respectively, compared to $195.7 million in the first nine months of 2015. Revenues were lower primarily due to lower oil and natural gas pricing as well as lower oil production, partially offset by higher NGL pricing and higher natural gas production. The Company's net income of $851.6 million in the period of January 1, 2016 through April 22, 2016 (predecessor) was primarily due to the gain on reorganization adjustments as part of our emergence from bankruptcy while the net loss of $149.2 million in the period of April 23, 2016 through September 30, 2016 (successor) is primarily due to decreased commodity pricing and production along with the $133.5 million non-cash write-down of our oil and gas properties.

•

2016 capital expenditures and plans: The Company's capital expenditures on a cash flow basis were $24.5 million and $36.8 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through September 30, 2016 (successor), respectively, compared to $126.8 million in the first nine months of 2015. The expenditures since April 23, 2016, were primarily devoted to completion activity in our South Texas core region as we completed four wells in our AWP Eagle Ford field and also initiated completion work for four wells in our Fasken field. These expenditures were funded by borrowings under our New Credit Facility along with operating cash flows.

The Company’s focus for 2016 has been to balance capital expenditure with cash flows. For 2016 we have a limited capital budget which is focused on completion activities in our South Texas fields, with additional drilling in this area in the fourth quarter of 2016.

•

Working capital and debt to capitalization ratio: The Company had a working capital deficit of $271.2 million at December 31, 2015, and a deficit of $22.8 million at September 30, 2016. 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. These numbers are not comparable given the Company's bankruptcy proceeding at December 31, 2015. The deficit at December 31, 2015 included the Company's prior first lien credit facility borrowings as a current liability while other current payables were reclassified as liabilities subject to compromise. Liabilities subject to compromise were excluded from the net working capital computation. The Company uses this measure to track its short-term financial position. The working capital computation does not include available liquidity through our credit facility.

•

Cash Flows: For the period of April 23, 2016 through September 30, 2016 (successor) the Company generated cash from Operating Activities of $29.4 million, of which $5.5 million was attributable to changes in working capital. Cash used for property additions was $36.8 million. This included $17.6 million attributable to net pay-down of capital related payables and accrued cost as the Company paid a significant portion of the well completion costs from earlier in the year during this period. The Company’s net borrowings on its line of credit were $1.0 million for this period.

For the period of January 1, 2016 through April 22, 2016 (predecessor) (which included the impact of cash transactions occurring upon emergence from bankruptcy) the Company’s operating cash flow deficit was $41.5 million, of which $16.3 million was attributable to working capital changes. During this period the Company incurred $25.6 million in legal and professional fees related to its bankruptcy and reorganization activities. While the Company paid $24.5 million for capital expenditures, it realized $48.7 million from asset sales (primarily from the sales of properties in Central Louisiana) and received $75 million in proceeds from its DIP credit facility. It utilized $71.9 million to pay down its bank credit facility from $324.9 million to $253.0 million prior to emergence from bankruptcy. The remaining $253 million was refinanced with the Company’s new credit facility. The Company also paid $10.4 million for interest during the period and $6.5 million for debt issuance costs associated with obtaining the new credit facility.

For the nine months ended September 30, 2015 the Company generated $28.4 million from operating activities but paid out $126.8 million for capital expenditures, including a net pay down of $36.6 million in payables and accrued capital for 2014 activity. The Company drew a net $104.7 million on its bank credit facility during the period.

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Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our Prior First Lien Credit Agreement and issuances of senior notes. Our primary use of cash flow has been to fund capital expenditures used to develop our oil and gas properties. Upon emergence from bankruptcy, our primary sources of liquidity are cash flows from operations and borrowings under the New Credit Facility. Other potential sources of liquidity in the next twelve months include proceeds from sales of non-core assets or sales of debt or equity securities. As of September 30, 2016, the Company’s liquidity consisted of approximately $2.4 million of cash-on-hand and $51 million in available borrowings (calculated as $66 million of borrowing availability less $5.1 million in letters of credit and a $10 million minimum liquidly requirement) on the $320 million borrowing base.

Disposition of Assets. Effective September 30, 2016, we closed our transaction with Blue Marble Resources LLC for the sale of our Sun TSH field located in South Texas. We received net proceeds of approximately $0.9 million and the buyer assumed approximately $1.8 million of plugging and abandonment liability.

New Credit Facility and Prior First Lien Credit Agreement. On our emergence from bankruptcy, the Prior First Lien Credit Agreement was terminated and paid in full, and the Company entered into the New Credit Facility among the Company, as borrower, JPMorgan Chase Bank, National Association, as administrative agent, and certain lenders party thereto. The New Credit Facility matures three years after our emergence from bankruptcy and provides for advancing loans of up to the maximum credit amount that the lenders, in the aggregate, make available, subject to the Company meeting certain financial requirements, including certain financial tests. As of our emergence from bankruptcy, the maximum credit amount was $500 million with an initial borrowing base of $320 million. The obligations under the New Credit Facility are being secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries including a first priority lien on properties attributed with at least 95% of estimated proved producing reserves of the Company and its subsidiaries. The first semi-annual borrowing base redetermination is in progress and expected to be completed by mid-November 2016. As of November 1, 2016, we had $250 million in outstanding borrowings under the New Credit Facility. The terms of the New Credit Facility include the following, based on terms as defined in the New Credit Facility agreement:

•

The initial borrowing base is initially allocated between a non-conforming borrowing base of $70 million, which terminates on November 1, 2017, and a conforming borrowing base of $250 million. Until November 1, 2017 if the conforming borrowing base is re-determined and increased or decreased, the non-conforming borrowing base will be automatically revised so that the amount of the overall borrowing base will equal the borrowing base in effect immediately prior to such redetermination. Upon termination of the non-conforming borrowing base on November 1, 2017, all borrowings and interest under the non-conforming borrowing base are payable in full. As of September 30, 2016, the Company had borrowings of $4 million and $250 million on the non-conforming borrowing base and conforming borrowing base, respectively.


•	Borrowing base redeterminations are scheduled to occur semi-annually in November and May and are determined by the lenders in their discretion and in the usual and customary manner.


•	The interest rate for Alternative Base Rate ("ABR") loans will be based on the ABR plus the applicable margin, and the interest rate for Eurodollar loans will be based on the adjusted London Interbank Offered Rate (“LIBOR”), plus the applicable margin.

•

The applicable margins vary and have escalating rates of either (a) 500 to 600 basis points for ABR loans and 600 to 700 basis points for Eurodollar loans, during the non-conforming period, and depending on the level of the non-conforming borrowing base and the non-conforming borrowing base loans outstanding, or (b) 200 to 300 basis points for ABR loans and 300 to 400 basis points for Eurodollar loans depending on the borrowing base utilization percentage, after the non-conforming period or when both the non-conforming borrowing base is zero and there are no non-conforming borrowing base loans outstanding. As of September 30, 2016, our average borrowing rate was 7.5%.

•

We expect to be in compliance with the covenants under this agreement during the next twelve months. Maintaining or increasing our conforming borrowing base under our New Credit Facility is dependent upon many factors, including commodities pricing, our hedge positions and our ability to raise capital to drill wells to replace produced reserves.

2016 Capital Spending. The Company’s capital expenditures are significantly reduced from 2015 levels. The primary activity in the first half of 2016 was the completion of 12 South Texas Eagle Ford wells that were drilled in late 2015. The Company

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is in the process of drilling four additional South Texas Eagle Ford wells. Capital activity for 2016 also includes some minor recompletion work in Louisiana, as well as normal and customary minor capital expenditures related to regulatory and corporate matters. For the foreseeable future we intend to focus on drilling activity in our Eagle Ford position. We expect to fund our capital program using cash flows from operations and, if necessary, borrowing availability under our credit facility, sales of non-core assets or the issuance of debt or equity securities.

Contractual Commitments and Obligations

In the ordinary course of business, we are party to various legal actions, which arise primarily from our activities as operator of oil and natural gas wells. We do not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations, or cash flows, although we cannot guarantee that a material adverse effect will not occur.

As of September 30, 2016, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K. We had no material changes in our contractual commitments and obligations from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2016.

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Results of Operations

Revenues — Three Months Ended September 30, 2016 and 2015

The tables included below set forth financial information for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor).

Certain reclassifications have been made to 2015 sales volumes from previously reported volumes to conform to the current-year presentation. Previously disclosed production volumes included natural gas consumed in operations. All current and prior year production is now shown based on volumes sold rather than volumes produced.

Crude oil production was 12% and 21% of our production volumes for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. Crude oil sales were 26% and 44% of oil and gas sales for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively.

Natural gas production was 78% and 66% of our production volumes for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. Natural gas sales were 65% and 49% of oil and gas sales for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The remaining production and sales in each period came from NGLs.

The following tables provide additional information regarding our oil and gas sales, by area, excluding any effects of our hedging activities, for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor):



Core Regions	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MBoe)	Oil and Gas Sales (In Millions)		Net Oil and Gas Production Volumes (MBoe)
	Three Months Ended September 30, 2016 (Successor)		Three Months Ended September 30, 2016 (Successor)	Three Months Ended September 30, 2015 (Predecessor)		Three Months Ended September 30, 2015 (Predecessor)
Artesia Wells	$	3.6	175	$	4.4	252
AWP	15.7		717	20.2		846
Fasken	22.7		1,388	19.6		1,224
Other South Texas	0.8		42	0.9		51
Total South Texas	42.8		2,322	45.1		2,373

Southeast Louisiana	4.2		108	10.6		221

Central Louisiana	0.8		27	4.1		129

Other	0.2		6	0.2		12

Total	$	48.0	2,463	$	60.0	2,735

The sales volumes decrease from 2015 to 2016 was primarily due to a decrease in oil production from our AWP and our Louisiana fields, partially offset by an increase in natural gas production from our Fasken field. In addition to production declines in Louisiana, our Central Louisiana volumes reflect our 75% ownership reduction in Mid-April of this year for the sale of interest in our Burr Ferry and South Bearhead Creek fields.

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The following table provides additional information regarding our oil and gas sales, by commodity type, excluding any effects of our hedging activities, for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor):



	Sales Volume				Average Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
Three Months Ended September 30, 2016 (Successor)	293	255	11.5	2,463	$	43.27	$	16.38	$	2.71
Three Months Ended September 30, 2015 (Predecessor)	581	344	10.9	2,735	$	45.24	$	12.94	$	2.70

For the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015(predecessor), there were net gains of $2.6 million and less than $0.1 million related to our derivative activities, respectively. Hedging activity is recorded in “Price-risk management and other, net” on the accompanying condensed consolidated statements of operations.

Costs and Expenses — Three Months Ended September 30, 2016 and 2015

The following table provides additional information regarding our expenses for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor):



Costs and Expenses	Three Months Ended September 30, 2016 (Successor)		Three Months Ended September 30, 2015 (Predecessor)
General and administrative, net	$	11,691	$	8,679
Depreciation, depletion, and amortization	13,287		35,606
Accretion of asset retirement obligation	1,099		1,410
Lease operating cost	9,481		17,990
Transportation and gas processing	4,883		5,446
Severance and other taxes	2,683		4,613
Interest expense, net	5,880		19,438
Write-down of oil and gas properties	—		321,522
Reorganization items, net	1,193		—
Total Costs and Expenses	$	50,197	$	414,704

Lease operating cost. These expenses on a per Boe basis were $3.85 and $6.58 for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The decrease per Boe was primarily due to a concentrated effort to reduce operating costs and included a decrease in labor costs, compression costs, chemical costs, and maintenance costs.

Transportation and gas processing. These expenses all related to gas and NGL sales. These expenses were $0.42 and $0.50 per MCF of gas sales for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The reduction was primarily attributable to improved negotiated rates for certain South Texas fields.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Boe basis were $5.39 and $13.02 for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The depletion rates for the third quarter of 2016 versus the third quarter of 2015 are not comparable due to the restatement of assets at their fair value upon emergence from bankruptcy in 2016.

General and Administrative Expenses, Net. These expenses on a per Boe basis were $4.75 and $3.17 for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The increase per Boe was primarily due to severance and equity compensation expense for retiring executives of $2.1 million and $2.3 million, respectively, partially offset by lower salaries and burdens and lower legal and professional fees.

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Severance and Other Taxes. These expenses on a per Boe basis were $1.09 and $1.69 for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.6% and 7.7% for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively. The reduction was primarily attributable to lower Louisiana oil sales as a percentage of total revenue. Louisiana oil production is taxed at significantly higher rates than our other production.

Interest. Our gross interest cost was $6.1 million and $20.7 million for the three months ended September 30, 2016 (successor) and the three months ended September 30, 2015 (predecessor), respectively, of which $0.3 million was capitalized in the third quarter of 2016, while $1.2 million was capitalized in 2015. The decrease in gross interest was primarily due to the discontinuance of interest on our senior notes. Upon emergence from bankruptcy our only interest bearing debt is our credit facility.

Write-down of oil and gas properties. Due to changes in pricing, timing of projects and changes in our reserves product mix we incurred a write-down of $321.5 million in the third quarter of 2015. There was no such write-down in the third quarter of 2016.

Income Taxes. There was no expense for income taxes in the third quarter of 2016 as the Company has sufficient deferred tax carryover assets to offset the income during this period. The unrelated deferred tax assets are fully offset by valuation allowances. There was no benefit for income taxes in the third quarter of 2015 as the benefit for income taxes was offset by valuation allowances.

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Revenues — Nine Months Ended September 30, 2016 and 2015

The tables included below set forth financial information for the periods of April 23, 2016 through September 30, 2016 (successor) and the period of January 1, 2016 through April 22, 2016 (predecessor) which are distinct reporting periods as a result of our emergence from bankruptcy on April 22, 2016.

Crude oil production was 13%, 19%, and 23% of our production volumes for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. Crude oil sales were 30%, 38% and 47% of oil and gas sales for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively.

Natural gas production was 76%, 68% and 64% of our production volumes in the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. Natural gas sales were 60%, 52%, and 44% of oil and gas sales for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor). The remaining production and sales in each period came from NGLs.

The following tables provide additional information regarding our oil and gas sales, by area, excluding any effects of our hedging activities, for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor):



Core Regions	Oil and Gas Sales (In Millions)
	April 23 - September 30, 2016 (Successor)		January 1 - April 22, 2016 (Predecessor)		Nine Months Ended September 30, 2015 (Predecessor)
Artesia Wells	$	6.1	$	3.5	$	15.4
AWP	27.1		14.7		72.6
Fasken	33.5		14.3		53.1
Other South Texas	1.3		0.9		2.7
Total South Texas	68.0		33.4		143.8

Southeast Louisiana	9.0		7.2		36.8

Central Louisiana	1.3		2.3		14.2

Other	0.2		0.1		0.9

Total	$	78.5	$	43.0	$	195.7

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Core Regions	Net Oil and Gas Production Volumes (MBoe)
	(a)	(b)	(a) + (b)	(c)	(a) + (b) - (c)
	April 23 - September 30, 2016 (Successor)	January 1 - April 22, 2016 (Predecessor)	Nine Months Ended September 30, 2016	Nine Months Ended September 30, 2015 (Predecessor)	Change		% Change
Artesia Wells	316	257	573	815	(242	)	(30	)%
AWP	1,343	951	2,294	2,921	(627	)	(21	)%
Fasken	2,318	1,213	3,531	3,310	221		7	%
Other South Texas	71	56	127	146	(19	)	(13	)%
Total South Texas	4,048	2,477	6,525	7,192	(667	)	(9	)%

Southeast Louisiana	208	216	424	717	(293	)	(41	)%

Central Louisiana	40	107	147	416	(269	)	(65	)%

Other	11	7	18	36	(18	)	(50	)%

Total	4,307	2,807	7,114	8,361	(1,247	)	(15	)%
Total Boe per day	27	25		31

The sales volumes decrease from the first nine months 2015 to 2016 was primarily due to a decrease in oil production from our AWP and our Louisiana fields, while the decrease in natural gas production both came from our Artesia, AWP and Louisiana fields. In addition to production declines in Louisiana, our Central Louisiana volumes reflect our 75% ownership reduction in Mid-April of this year for the sale of interest in our Burr Ferry and South Bearhead Creek fields. These decreases were partially offset by an increase in natural gas production from our Fasken field during the first nine months of 2016.

The following table provides additional information regarding our oil and gas sales, by commodity type, excluding any effects of our hedging activities, for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor):



	Sales Volume				Average Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
April 23 - September 30, 2016 (Successor)	546	501	19.6	4,307	$	43.77	$	15.28	$	2.40
January 1 - April 22, 2016 (Predecessor)	522	380	11.4	2,807	$	31.43	$	11.04	$	1.96
Nine Months Ended September 30, 2015	1,895	1,137	32.0	8,361	$	48.97	$	14.84	$	2.69

For the period of April 23, 2016 through September 30, 2016 (successor) and the nine months ended September 30, 2015, we recorded total net gains (losses) of $(7.3) million and $0.3 million, respectively, related to our derivative activities. There were no hedges in place for the period of January 1, 2016 through April 22, 2016 (predecessor).

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Costs and Expenses — Nine Months Ended September 30, 2016 and 2015

The following table provides additional information regarding our expenses for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor) and nine months ended September 30, 2015 (predecessor):



Costs and Expenses	April 23 - September 30, 2016 (Successor)		January 1 - April 22, 2016 (Predecessor)			Nine Months Ended September 30, 2015 (Predecessor)
General and administrative, net	$	15,919	$	9,245		$	31,525
Depreciation, depletion, and amortization	26,621		20,439			138,392
Accretion of asset retirement obligation	1,931		1,610			4,156
Lease operating cost	17,262		14,933			54,188
Transportation and gas processing	9,069		6,090			15,855
Severance and other taxes	4,547		3,917			14,169
Interest expense, net	10,137		13,347			56,407
Write-down of oil and gas properties	133,496		77,732			1,084,595
(Gain) loss on reorganization items, net	1,469		(956,142		)	—
Total Costs and Expenses	$	220,451	$	(808,829	)	$	1,399,287

Lease operating cost. These expenses on a per Boe basis were $4.01, $5.32 and $6.48 for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The decrease was due to lower workover, labor, compression, maintenance, chemicals and salt water disposal costs primarily driven by concentrated efforts to reduce operating costs.

Transportation and gas processing. These expenses all related to gas and NGL sales. These expenses on a per Mcf basis were $0.46, $0.53 and $0.50 for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The lower rate for the most recent period was primarily attributable to improved negotiated rates for certain South Texas fields.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Boe basis were $6.18, $7.28 and $16.55 for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The depletion expense recorded subsequent to April 22, 2016 is not comparable to the first nine months of 2015 due to the restatement of assets at their fair value upon emergence from bankruptcy. The decreased rate from the nine months ended September 30, 2015 (predecessor) compared to the period of January 1, 2016 through April 22, 2016 (predecessor) is attributable to a lower depletable base due to ceiling test write-downs in the second half of 2015.

General and Administrative Expenses, Net. These expenses on a per Boe basis were $3.70, $3.29 and $3.77 for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The decrease from the nine months ended September 30, 2015 (predecessor) was primarily due to lower salaries and burdens, a lower corporate benefit accrual and lower legal and professional fees, partially offset by severance and equity compensation expense for retiring executives of $2.1 million and $2.3 million, respectively, and lower capitalized amounts.

Severance and Other Taxes. These expenses on a per Boe basis were $1.06, $1.40 and $1.69 for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The decrease was primarily driven by lower oil and gas revenues as a result of decreased commodity prices along with declining oil production. Severance and other taxes, as a percentage of oil and gas sales, were approximately 5.8%, 9.1% and 7.2% for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively. The reduction as a percentage of revenue in the most recent period is primarily attributable to lower Louisiana oil sales in proportion to total revenue.

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Interest. Our gross interest cost was $10.4 million, $13.3 million and $60.0 million for the period of April 23, 2016 through September 30, 2016 (successor), period of January 1, 2016 through April 22, 2016 (predecessor), and the nine months ended September 30, 2015 (predecessor), respectively, of which $0.3 million was capitalized for the period of April 23, 2016 through September 30, 2016 (successor) and $3.6 million was capitalized for the first nine months of 2015 (predecessor). The decrease in gross interest was primarily due to the discontinuance of interest on our senior notes due to our bankruptcy proceedings, partially offset by interest expense related to the DIP Credit Agreement.

Write-down of oil and gas properties. Primarily due to pricing differences between the 12-month average oil and gas prices used in the Ceiling Test and the forward strip prices used to estimate the initial fair value of oil and gas properties on the Company's April 22, 2016 (successor balance sheet), we recorded a write-down of $133.5 million for the period of April 23, 2016 through September 30, 2016 (successor). The full amount of this write-down was incurred at June 30, 2016. Principally due to the effects of pricing, and also due to the timing of projects and changes in our reserves product mix, we recorded non-cash write-downs on a before-tax basis of $77.7 million and $1.1 billion for the period of January 1, 2016 through April 22, 2016 (predecessor) and the nine months ended September 30, 2015 (predecessor), respectively.

Reorganization Items. We incurred a net gain of $956.1 million and expenses of $1.5 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and period of April 23, 2016 through September 30, 2016 (successor), respectively. The net gain was primarily due to the gain on discharge of debt and fresh start adjustments upon emergence from bankruptcy. There were no reorganization expenses in the first nine months of 2015.

Income Taxes. The Company entered bankruptcy with Federal and state net operating loss carryovers and amortizable property basis significantly in excess of book value. This resulted in the Company having significant deferred tax assets. Given our recent history of incurring tax losses and economic uncertainty we recorded a full valuation allowance against these tax assets. The Company's emergence from bankruptcy resulted in a significant tax gain on the debt conversion to equity. We will be able to fully offset this gain with our net operating losses. Since these operating losses carried a zero book balance after valuation allowances there was no tax expense realized as a result of the gain reported for the period of January 1, 2016 through April 22, 2016 (predecessor). There was no benefit for income taxes in the period of April 23, 2016 through September 30, 2016 (successor) as the benefit for the periods was offset with valuation allowances. The tax benefit of $80.1 million for the first nine months of 2015 was due to a reduction in our deferred tax liability resulting from the write-down of oil and gas properties, partially offset by a valuation allowance.

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Critical Accounting Policies and New Accounting Pronouncements

Fresh-start Accounting. Upon emergence from bankruptcy, we adopted fresh-start accounting, which resulted in the Company becoming a new entity for financial reporting purposes. Upon adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the Effective Date. The Effective Date fair values of our assets and liabilities differed materially from the recorded values of our assets and liabilities as reflected in our historical consolidated balance sheets. The effects of the Reorganization Plan and the application of fresh-start accounting were implemented as of April 22, 2016 and the related adjustments thereto were recorded in our condensed consolidated statement of operations as reorganization items for the period of January 1, 2016 through April 22, 2016.

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) 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.

If oil and natural gas prices decline from the prices used in the Ceiling Test, it is possible that additional non-cash write-downs of oil and gas properties will occur in the future. If future capital expenditures out pace future discounted net cash flows in our reserve calculations or 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, non-cash write-downs of our oil and natural gas properties could occur in the future. We cannot control and cannot predict what future prices for oil and natural gas will be, thus we cannot estimate the amount or timing of any potential future non-cash write-down of our oil and natural gas properties if a decrease in oil and/or natural gas prices were to occur.

In March 2016, the FASB issued ASU 2016-09, which simplifies several aspects of the accounting for employee share based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with early adoption permitted. This standard was adopted as of the bankruptcy emergence date April 22, 2016. The adoption of this guidance did not result in any adjustments.

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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 (the "Exchange Act"). 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:

• future cash flows and their adequacy to maintain our ongoing operations;

• oil and natural gas pricing expectations;

• liquidity, including our ability to satisfy our short- or long-term liquidity needs;

• business strategy, including our business strategy post-emergence from bankruptcy;

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

• our borrowing capacity, future covenant compliance, cash flows and liquidity;

• financial strategy, budget, projections and operating results;

• asset disposition efforts or the timing or outcome thereof;

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

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

• timing, cost and amount of future production of oil and natural gas;

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

• availability, cost and terms of capital;

• drilling of wells;

• availability and cost for 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;

• uncertainty of our ability to improve our operating structure, financial results and profitability following emergence from Chapter 11 and other risk and uncertainties related to our emergence from Chapter 11;

• new capital structure and the adoption of fresh start accounting, including the risk that assumptions and factors used in estimating enterprise value vary significantly from the current estimates in connection with the application of fresh start accounting;

• ability to become quoted on the OTC markets; and

• other risks and uncertainties described in Part II, Item 1A. “Risk Factors,” in this quarterly report on Form 10-Q.

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

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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 for the year ended December 31, 2015. 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.

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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 in recent periods.

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. As with our Prior First Lien Credit Agreement, we do not utilize these agreements and financial instruments for trading and only enter into derivative agreements with banks in our New Credit Facility. For additional discussion related to our price-risk management policy, refer to Note 7 of the accompanying 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 guarantees 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. A large portion of our oil and gas sales are to Kinder Morgan and affiliates and we expect to continue this relationship in the future. We believe that the business risk of this relationship is mitigated by the reputation and nature of their business and the availability of other purchasers.

Interest Rate Risk. At September 30, 2016, we had $254 million drawn under our New Credit Facility which has a floating rate of interest depending on the level of the non-conforming borrowing base and the non-conforming borrowing base loans outstanding and therefore is susceptible to interest rate fluctuations.

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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 Exchange Act, 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 Exchange Act 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. Our Chief Executive Officer and Chief Financial Officer have evaluated such disclosure controls and procedures as of the end of the period covered by this quarterly report on Form 10-Q and have determined that such disclosure controls and procedures are effective.

Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the three months ended September 30, 2016 (successor) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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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 disclosed in the 2015 Annual Report Form 10-K and Second Quarter 2016 Report Form 10-Q.

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

In connection with the Company's emergence from Chapter 11 bankruptcy, all common stock was canceled. There were no repurchases of our common stock during the three months ended September 30, 2016 (successor)

Item 3. Defaults Upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

None.

Item 5. Other Information.

None.

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Item 6. Exhibits.



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

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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 3, 2016	By:	/s/ Alton D. Heckaman, Jr.
			Alton D. Heckaman, Jr. Executive Vice President Chief Financial Officer and Principal Accounting Officer

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Exhibit Index



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