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 June 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 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)	10,000,001 Shares outstanding at July 31, 2016

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 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	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	49

Item 4.	Controls and Procedures	50

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	51
Item 1A.	Risk Factors	51
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3.	Defaults Upon Senior Securities	51
Item 4.	Mine Safety Disclosures	51
Item 5.	Other Information	51
Item 6.	Exhibits	51

SIGNATURES		54
Exhibit Index		55

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Condensed Consolidated Balance Sheets

Swift Energy Company and Subsidiaries (Debtor-in-Possession December 31, 2015 through April 22, 2016) (in thousands, except share amounts)



	Successor			Predecessor
	June 30, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	4,294		$	29,460
Accounts receivable, net	22,049			21,704
Other current assets	4,078			10,683
Total Current Assets	30,421			61,847

Property and Equipment:
Property and Equipment, including $47,603 and $18,839 of unproved property costs not being amortized at the end of each period	562,123			6,035,757
Less – Accumulated depreciation, depletion, amortization & impairment	(146,830		)	(5,577,854		)
Property and Equipment, Net	415,293			457,903
Other Long-Term Assets	9,841			5,248
Total Assets	$	455,555		$	524,998
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	48,696		$	7,663
Accrued capital costs	8,262			—
Accrued interest	1,236			490
Undistributed oil and gas revenues	9,580			—
Current portion of long-term debt	—			324,900
Total Current Liabilities	67,774			333,053

Long-Term Debt	254,000			—
Asset Retirement Obligation	51,047			56,390
Other Long-Term Liabilities	2,745			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	229,490			—
Accumulated deficit	(149,601		)	(1,627,039		)
Total Stockholders’ Equity (Deficit)	79,989			(852,724		)
Total Liabilities and Stockholders’ Equity	$	455,555		$	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 (Debtor-in-Possession December 31, 2015 through April 22, 2016) (in thousands, except per-share amounts)



	Successor			Predecessor
	Period from April 23, 2016 through June 30, 2016			Period from April 1, 2016 through April 22, 2016			Three Months Ended June 30, 2015
Revenues:
Oil and gas sales	$	30,581		$	8,660		$	68,281
Price-risk management and other, net	(9,928		)	(150		)	(2,112		)
Total Revenues	20,653			8,510			66,169

Costs and Expenses:
General and administrative, net	4,228			1,127			10,290
Depreciation, depletion, and amortization	13,334			3,194			42,088
Accretion of asset retirement obligation	832			319			1,381
Lease operating cost	7,781			2,627			17,164
Transportation and gas processing	4,186			1,035			5,086
Severance and other taxes	1,864			1,585			4,424
Interest expense, net	4,257			5,281			18,741
Write-down of oil and gas properties	133,496			—			260,504
(Gain) Loss on Reorganization items, net	276			(966,571		)	—
Total Costs and Expenses, Net of Gains	170,254			(951,403		)	359,678

Income (Loss) Before Income Taxes	(149,601		)	959,913			(293,509		)

Provision (Benefit) for Income Taxes	—			—			(642		)

Net Income (Loss)	$	(149,601	)	$	959,913		$	(292,867	)

Per Share Amounts-

Basic: Net Income (Loss)	$	(14.96	)	$	21.45		$	(6.58	)

Diluted: Net Income (Loss)	$	(14.96	)	$	21.03		$	(6.58	)

Weighted Average Shares Outstanding - Basic	10,000			44,754			44,516

Weighted Average Shares Outstanding - Diluted	10,000			45,648			44,516

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Operations (Unaudited)

Swift Energy Company and Subsidiaries (Debtor-in-Possession December 31, 2015 through April 22, 2016) (in thousands, except per-share amounts)



	Successor			Predecessor
	Period from April 23, 2016 through June 30, 2016			Period from January 1, 2016 through April 22, 2016			Six Months Ended June 30, 2015
Revenues:
Oil and gas sales	$	30,581		$	43,027		$	135,639
Price-risk management and other, net	(9,928		)	(245		)	(1,133		)
Total Revenues	20,653			42,782			134,506

Costs and Expenses:
General and administrative, net	4,228			9,245			22,846
Depreciation, depletion, and amortization	13,334			20,439			102,786
Accretion of asset retirement obligation	832			1,610			2,746
Lease operating cost	7,781			14,933			36,198
Transportation and gas processing	4,186			6,090			10,409
Severance and other taxes	1,864			3,917			9,556
Interest expense, net	4,257			13,347			36,969
Write-down of oil and gas properties	133,496			77,732			763,073
(Gain) Loss on Reorganization items, net	276			(956,142		)	—
Total Costs and Expenses, Net of Gains	170,254			(808,829		)	984,583

Income (Loss) Before Income Taxes	(149,601		)	851,611			(850,077		)

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

Net Income (Loss)	$	(149,601	)	$	851,611		$	(769,944	)

Per Share Amounts-

Basic: Net Income (Loss)	$	(14.96	)	$	19.06		$	(17.35	)

Diluted: Net Income (Loss)	$	(14.96	)	$	18.64		$	(17.35	)

Weighted Average Shares Outstanding - Basic	10,000			44,692			44,374

Weighted Average Shares Outstanding - Diluted	10,000			45,697			44,374

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

Swift Energy Company and Subsidiaries (Debtor-in-Possession December 31, 2015 through April 22, 2016) (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	—			191			—			—			191
Net Loss	—			—			—			(149,601		)	(149,601		)
Balance, June 30, 2016 (Successor)	$	100		$	229,490		$	—		$	(149,601	)	$	79,989

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Cash Flows (Unaudited)

Swift Energy Company and Subsidiaries (Debtor-in-Possession December 31, 2015 through April 22, 2016) (in thousands)



	Successor			Predecessor
	Period from April 23, 2016 through June 30, 2016			Period from January 1, 2016 through April 22, 2016			Six Months Ended June 30, 2015
Cash Flows from Operating Activities:
Net income (loss)	$	(149,601	)	$	851,611		$	(769,944	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities-
Depreciation, depletion, and amortization	13,334			20,439			102,786
Write-down of oil and gas properties	133,496			77,732			763,073
Accretion of asset retirement obligation	832			1,610			2,746
Deferred income taxes	—			—			(80,133		)
Share-based compensation expense	191			886			2,153
Loss (Gain) on derivatives	9,912			—			(251		)
Reorganization items (non-cash)	—			(977,696		)	—
Other	438			229			3,857
Change in operating assets and liabilities-
(Increase) decrease in accounts receivable and other current assets	13,379			(5,474		)	9,041
Increase (decrease) in accounts payable and accrued liabilities	(6,621		)	(10,495		)	(3,997		)
Increase (decrease) in accrued interest	573			(308		)	108
Net Cash Provided by (Used in) Operating Activities	15,933			(41,466		)	29,439

Cash Flows from Investing Activities:
Additions to property and equipment	(20,876		)	(24,530		)	(104,997		)
Proceeds from the sale of property and equipment	—			48,661			946
Net Cash Provided by (Used in) Investing Activities	(20,876		)	24,131			(104,051		)

Cash Flows from Financing Activities:
Proceeds from bank borrowings	21,000			328,000			180,500
Payments of bank borrowings	(20,000		)	(324,900		)	(105,800		)
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		)	74,281

Net increase (decrease) in Cash and Cash Equivalents	(4,445		)	(20,721		)	(331		)

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

Cash and Cash Equivalents at End of Period	$	4,294		$	8,739		$	75

Supplemental Disclosures of Cash Flows Information:

Cash paid during period for interest, net of amounts capitalized	$	3,246		$	10,367		$	35,488
Cash paid for reorganization items	$	4,080		$	15,643		$	—
Changes in capital accounts payable and capital accruals	$	(8,353	)	$	1,843		$	(46,843	)
See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements

Swift Energy Company and Subsidiaries

(1) General Information

The condensed consolidated financial statements included herein have been prepared by 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 is made up of seven directors consisting of the Chief Executive Officer of the post-emergence Company (Terry E. Swift), two directors appointed by Strategic Value Partners LLC ("SVP") (Peter Kirchof and David Geenberg), a former holder of the Company’s senior notes, two directors appointed by other former holders of the Company’s senior notes (Gabriel Ellisor and Charles Wampler), one independent director (Michael Duginski) and one vacancy (who will be designated the 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 terminated upon the Company’s exit from bankruptcy. For more information refer to Note 5 of the 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 FASB 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

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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.

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 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 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

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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 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 June 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	342			25,573
Fair value of equity issued to DIP lenders for backstop fee	—			16,082
Other reorganization items	(66		)	21,324
(Gain) Loss on Reorganization items, net	$	276		$	(956,142	)

(2) Summary of Significant Accounting Policies

Fresh Start Accounting. 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. 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 Company).

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 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. 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.

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

Subsequent Events. We have evaluated subsequent events of our condensed consolidated financial statements. On August 8, 2016, the Board of Directors delivered notices to the Company’s Chief Executive Officer and Chief Financial Officer concerning their retirement and termination from employment and all officer positions with the Company following a transition period, which is expected to be over the next several months. The Chief Executive Officer and Chief Financial Officer shall receive severance benefits, which include cash payments, accelerated vesting of their share-based compensation, and other benefits in accordance with their Third Amended and Restated Employment Agreements. The Board also approved that Mr. Swift shall remain on the Board until his departure as Chief Executive Officer. There were no material subsequent events requiring additional disclosure in these financial statements.

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


•	estimates in the calculation of share-based compensation expense,


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


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


•	estimates made in our income tax calculations,


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


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


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

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

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), such internal costs capitalized totaled $0.5 million, $1.5 million, and $3.3 million, respectively. For the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), such internal capitalized costs totaled $2.9 million and $7.0 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).

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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 June 30, 2016			Predecessor As of December 31, 2015
Property and Equipment
Proved oil and gas properties	$	510,819		$	5,972,666
Unproved oil and gas properties	47,603			18,839
Furniture, fixtures, and other equipment	3,701			44,252
Less – Accumulated depreciation, depletion, amortization & impairment	(146,830		)	(5,577,854		)
Property and Equipment, Net	$	415,293		$	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. This calculation is done on a country-by-country basis and the period over which we will amortize these properties is dependent on our production from these properties in future years. Furniture, fixtures, and other equipment are recorded at cost and are depreciated by the straight-line method at rates based on the estimated useful lives of the property, which range between two and 20 years. Repairs and maintenance are charged to expense as incurred.

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

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes) 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.

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of $133.5 million. 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 June 30, 2015 (predecessor), we reported a non-cash impairment write-down of $260.5 million on our oil and natural gas properties. For the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), we reported non-cash impairment write-downs of $77.7 million and $763.1 million, 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 or remain at levels prevalent in the current period, it is likely 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. However, due to current trends in commodity pricing it is possible that we will record additional ceiling test write-downs in future periods.

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 June 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 June 30, 2016 and December 31, 2015, we had an allowance for doubtful accounts of approximately $0.3 million and $0.1 million, respectively. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

At June 30, 2016, our “Accounts receivable” balance included $13.4 million for oil and gas sales, $4.5 million for joint interest owners, $1.5 million for severance tax credit receivables and $2.7 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 period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor), the three months ended June 30, 2015 (predecessor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor) did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $0.7 million, $1.3 million and $2.2 million for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively and were $2.7 million and $4.9 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), respectively.

Other Current Assets. Included in "Other current assets" on the accompanying condensed consolidated balance sheets are inventories which consist primarily of tubulars and other equipment and supplies that we expect to place in service in production operations. Our inventories are recorded at cost (weighted average method) and totaled $0.4 million at June 30, 2016 and $0.6 million at December 31, 2015.

Also included in "Other current assets" on the accompanying condensed consolidated balance sheets are prepaid expenses totaling $3.3 million and $4.4 million at June 30, 2016 and December 31, 2015, respectively. These prepaid amounts cover well insurance, drilling contracts and various other prepaid expenses.

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.

We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25. Under this guidance, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring

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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 June 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 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. No other jurisdiction returns are significant to our financial position.

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 June 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 these tax assets.

The Company is not recognizing any tax benefit from operating losses generated for the period of April 23, 2016 through June 30, 2016 (successor) or the period of January 1, 2016 through April 22, 2016 (predecessor).

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 June 30, 2016		Predecessor As of December 31, 2015
Trade accounts payable ⁽¹⁾	$	13,519	$	—
Accrued operating expenses ⁽¹⁾	3,441		—
Accrued compensation costs ⁽¹⁾	2,919		—
Asset retirement obligation – current portion	5,058		7,165
Accrued taxes ⁽¹⁾	4,028		—
Accrued price risk liabilities ⁽¹⁾	8,770		—
Accrued corporate and legal fees ⁽¹⁾	9,922		—
Other payables ⁽¹⁾⁽²⁾	1,039		498
Total accounts payable and accrued liabilities	$	48,696	$	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 June 30, 2016.

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

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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 27, 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 November 2015, the FASB issued ASU 2015-17, which requires companies to classify all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. The guidance is effective for fiscal years beginning after December 15, 2016, including interim periods thereafter, with early adoption permitted and either with prospective or retrospective application permitted. This standard was adopted prospectively as of the bankruptcy emergence date April 22, 2016 and therefore prior years are no longer comparable. This standard had no immediate impact due to the full valuation allowance.

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 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 as of the bankruptcy emergence date April 22, 2016 and had no immediate impact due to the cancellation of shares upon emergence.

(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 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 and stock options expected to generate future tax deductions by applying its effective tax rate to the expense recorded. For restricted stock the Company's actual tax deduction is based on the value of the shares at the time of vesting. For the period of April 23, 2016 through June 30, 2016 (successor) no shares 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 three and six months ended June 30, 2015 (predecessor), we did recognize an

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income tax shortfall in earnings of $0.2 million and $1.4 million, respectively, primarily related to restricted stock awards that vested at a price lower than the grant date fair value.

Share-based compensation expense for awards issued to both employees and non-employees, which was recorded in “General and administrative, net” in the accompanying condensed consolidated statements of operations, was $0.1 million, $0.2 million, $1.2 million, $0.9 million and $2.0 million for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor), the three months ended June 30, 2015 (predecessor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), respectively.

There was no Share-based compensation expense recorded in lease operating cost for the period of April 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor), while there was $0.1 million, less than $0.1 million and $0.1 million for the three months ended June 30, 2015 (predecessor), period of January 1, 2016 through April 22, 2016 (predecessor) and six months ended June 30, 2015 (predecessor), respectively.

There was no share-based compensation expense capitalized for the period of April 23, 2016 through June 30, 2016 (successor). We capitalized $0.1 million, $0.4 million, $0.2 million and $0.7 million of share-based compensation for the period of April 1, 2016 through April 22, 2016 (predecessor), the three months ended June 30, 2015 (predecessor), the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), respectively. We view stock option awards and restricted stock awards with graded vesting as single awards with an expected life equal to the average expected life of component awards, and 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 June 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)	5
Weighted average grant-date fair value	$	13.42

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 Awards

The 2016 equity incentive compensation plan allows for the issuance of restricted stock 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 and is value typically expensed over the requisite service period (generally one to three years).

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

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



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

(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 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 June 30, 2016 (successor) and the three and six months ended June 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 from April 23, 2016 through June 30, 2016							Predecessor from April 1, 2016 through April 22, 2016					Predecessor Three Months Ended June 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	$	(149,601	)	10,000	$	(14.96	)	$	959,913	44,754	$	21.45	$	(292,867	)	44,516	$	(6.58	)
Dilutive Securities:
Restricted Stock Awards				—						894						—
Restricted Stock Units				—						—						—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(149,601	)	10,000	$	(14.96	)	$	959,913	45,648	$	21.03	$	(292,867	)	44,516	$	(6.58	)

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	Predecessor from January 1, 2016 through April 22, 2016					Predecessor Six Months Ended June 30, 2015
	Net Income (Loss)		Shares	Per Share Amount		Net Income (Loss)			Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	851,611	44,692	$	19.06	$	(769,944	)	44,374	$	(17.35	)
Dilutive Securities:
Restricted Stock Awards			1,005						—
Restricted Stock Units			—						—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	851,611	45,697	$	18.64	$	(769,944	)	44,374	$	(17.35	)

Approximately1.2 million and 1.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the period of April 1, 2016 through April 22, 2016 (predecessor) and period of January 1, 2016 through April 22, 2016 (predecessor), because their 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 six months ended June 30, 2015 (predecessor) because these stock options were antidilutive.

Approximately 0.3 million restricted stock awards for the period of April 1, 2016 through April 22, 2016 (predecessor) and period of January 1, 2016 through April 22, 2016 (predecessor), respectively, and approximately 0.7 million restricted stock awards for the three and six months ended June 30, 2015 (predecessor) were not included in the computation of Diluted EPS because they were antidilutive.

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

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



	Successor As of June 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.

Reclassification of 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 sheets as of December 31, 2015. These notes were canceled upon emergence from bankruptcy.

Reclassification of 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 reclassified 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.

Under the DIP Credit Agreement, interest accrued at a rate per year equal to LIBOR plus 12.0% for Eurodollar Rate Loans or the alternative base rate plus 11.0%. 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 and was included in interest expense during the period of January 1, 2016 through April 22, 2016 (predecessor). We were also required to pay to the Backstop Lenders (as defined in the DIP Credit Agreement) a non-refundable backstop fee on the pro rata share of such Backstop Lender’s share of the loan commitments, payable in the form of 7.5% of the common stock issued by the Company upon emergence from the Chapter 11 cases. An original issue discount of 5% was paid and recorded as interest expense by the Company during the period of January 1, 2016 through April 22, 2016 (predecessor) at the time of the drawdowns against the DIP Credit Agreement, resulting in net proceeds to the Company of 95% of the gross drawdown amount.

Interest expense on the DIP Credit Agreement totaled $4.5 million and $6.4 million during the period of April 1, 2016 through April 22, 2016 (predecessor) and the period of January 1, 2016 through April 22, 2016 (predecessor), respectively.

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 vary 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 300 basis points for 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.

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Interest expense on the Prior First Lien Credit Facility, including commitment fees and amortization of debt issuance costs, totaled $0.7 million and $2.2 million for the period of April 1, 2016 through April 22, 2016 (predecessor) and the three months ended June 30, 2015 (predecessor), respectively, and $6.8 million and $4.0 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and six months ended June 30, 2015 (predecessor), respectively. The amount of commitment fees included in interest expense, net was not material for the period of April 1, 2016 through April 22, 2016 (predecessor) and period of January 1, 2016 through April 22, 2016 (predecessor), respectively, and $0.1 million and $0.4 million and three and six months ended June 30, 2015 (predecessor), respectively.

Additionally, we capitalized interest on our unproved properties in the amount $1.2 million and $2.4 million for the three and six months ended June 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 the period of April 23, 2016 through June 30, 2016 (successor), therefore we did not capitalize interest on our unproved properties for those periods.

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 redetermined 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 June 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 beginning on November 1, 2016 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.

•

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 June 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 $4.3 million for the period of April 23, 2016 through June 30, 2016 (successor). The amount of commitment fees included in interest expense, net was $0.1 million for the period of April 23, 2016 through June 30, 2016 (successor).

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.

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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 April 1, 2016 through April 22, 2016 (predecessor) and 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 April 1, 2016 through April 22, 2016 (predecessor) and the period of January 1, 2016 through April 22, 2016 (predecessor) totaled $4.2 million and $21.6 million, respectively. Interest expense on the senior notes totaled $17.7 million and $35.4 million for the three and six months ended June 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.

There were no other material acquisitions or dispositions during the period of April 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor).

(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 period of April 23, 2016 through June 30, 2016 (successor) there was a $9.9 million loss while during the three and six months ended June 30, 2015 (predecessor) there was a net loss and net gain of $0.1 million and $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 June 30, 2016, we had $0.3 million in receivables for settled derivatives which were recognized on the accompanying condensed consolidated balance sheet in “Accounts receivable” and were subsequently collected in July 2016. At June 30, 2016, we also had $0.7 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 July 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 $0.1 million in current unsettled derivative assets, $0.1 million in long-term

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unsettled derivative assets and $8.0 million and $1.7 million current and long-term unsettled derivative liabilities, respectively, as of June 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 $9.5 million in net fair value liability at June 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 range of minimum and maximum prices as well as future production volumes for our unsettled derivative contracts in place as of June 30, 2016:



Oil Derivative Swaps (NYMEX WTI Settlements)	Total Volumes (Bbls)	Minimum Price		Maximum Price
2016 Contracts
3Q16	172,497	$	46.00	$	49.48
4Q16	155,997	$	46.90	$	50.36

2017 Contracts
1Q17	106,245	$	47.25	$	50.55
2Q17	97,401	$	47.25	$	50.85
3Q17	90,000	$	47.25	$	51.02
4Q17	84,798	$	47.25	$	51.30



Natural Gas Derivative Swaps (NYMEX Henry Hub Settlements)	Total Volumes (MMBtu)	Minimum Price		Maximum Price
2016 Contracts
3Q16	3,980,002	$	2.30	$	2.80
4Q16	5,250,003	$	2.67	$	2.80

2017 Contracts
1Q17	3,975,000	$	2.77	$	3.09
2Q17	3,625,005	$	2.77	$	2.85
3Q17	3,339,999	$	2.77	$	2.91
4Q17	3,125,001	$	2.77	$	3.03



Natural Gas Basis Derivative Swap East Texas Houston Ship Channel Settlements)	Total Volumes (MMBtu)	Minimum Price			Maximum Price
2016 Contracts
3Q16	3,979,902	$	(0.05	)	$	(0.02	)
4Q16	5,250,003	$	(0.08	)	$	(0.05	)

2017 Contracts
1Q17	3,577,500	$	(0.10	)	$	(0.05	)
2Q17	3,262,506	$	(0.05	)	$	(0.02	)
3Q17	3,005,001	$	(0.05	)	$	(0.01	)
4Q17	2,812,503	$	(0.05	)	$	(0.04	)

(8) Fair Value Measurements

Fair Value on a Recurring Basis. Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments. In connection with fresh start accounting, the Company incurred various other non-recurring fair value adjustments to our oil and gas properties, asset retirement obligation, other long-term liabilities and stockholder's equity of approximately $227 million as of April 22, 2016. See Note 1B of these condensed consolidated financial statements for more information.

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 ⁽¹⁾	$	21.4	$	225.0
7.875% senior notes due 2022 ⁽¹⁾	$	34.5	$	400.0
(1) Includes write-off of discount associated with the 2020 notes and premium associated with the 2022 notes due to the Company's bankruptcy proceedings.

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 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.

The following table presents our assets and liabilities that are measured on a recurring basis at fair value as of June 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. The fair value hierarchy has three levels based on the reliability of the inputs used to determine the fair value (in millions):



	Fair Value Measurements at
	Total		Quoted Prices in Active markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
June 30, 2016
Assets
Natural Gas Basis Derivatives	$	0.2	$	—	$	0.2	$	—
Liabilities
Natural Gas Derivatives	7.5		—		7.5		—
Natural Gas Basis Derivatives	0.2		—		0.2		—
Oil Derivatives	$	2.0	$	—	$	2.0	$	—

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.

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.

Fair Value on a Non-Recurring Basis. The Company discloses or recognizes its nonfinancial assets and liabilities, such as the fresh start valuation of oil and natural gas properties and the initial recognition of asset retirement obligations, at fair value on a non-recurring basis. The fresh start valuation of oil and natural gas properties is described further in Note 1B and includes significant unobservable inputs and therefore the Company has designated these assets as Level 3.

Estimates for the initial recognition of asset retirement obligations are derived from historical costs as well as management’s expectation of future cost environments. As there is no corroborating market activity to support the assumptions used, the Company has designated these liabilities as Level 3. A reconciliation of the beginning and ending balances of the Company’s asset retirement obligation is presented in Note 9 of these condensed consolidated financial statements.

(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 long-lived asset is increased. The liability is discounted from the expected date of abandonment. Over time, accretion of the liability is recognized each period, and the capitalized cost is depreciated on a unit-of-production basis as part of depreciation, depletion, and amortization expense for our oil and gas properties. Upon settlement of the liability, the Company either settles the obligation for its recorded amount or incurs a gain or loss upon settlement which is included in the “Property and Equipment” balance on our accompanying condensed consolidated balance sheets. This guidance requires us to record a liability for the fair value of our dismantlement and abandonment costs, excluding salvage values.

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	832
Liabilities incurred for new wells and facilities construction	15
Reductions due to sold wells and facilities	(8,123		)
Reductions due to plugged wells and facilities	(857		)
Revisions in estimates	(2		)
Asset Retirement Obligations as of June 30 (Successor)	$	56,105

At June 30, 2016 and December 31, 2015, approximately $5.1 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.

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(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.

Through April 22, 2016, most of our pending legal proceedings were stayed by virtue of our voluntary petition filed on December 31, 2015 seeking relief under Chapter 11 of the Bankruptcy Code.

During the second quarter of 2016, in connection with the bankruptcy, the Company rejected the lease for office space in Houston, Texas and entered into an agreement on May 15, 2016 to reduce our existing Houston office space. The agreement is on a month-to-month basis through December 31, 2016 and the minimum annual obligation under non-cancelable lease commitments is $2.1 million for 2016.

In connection with the bankruptcy, our previous gas transportation and processing minimum obligations were adjusted and are now $7.7 million for 2016, $9.3 million for 2017, $8.7 million for 2018, $8.3 million for 2019, $7.9 million for 2020 and $41.9 million in the aggregate.

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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 47 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 Company). 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 73% of our volumetric production and 52% of our sales revenue for our initial successor reporting period of April 23, 2016 to June 30, 2016.

Emergence from Voluntary Reorganization under Chapter 11 Proceedings

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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:



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.

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 the 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 Company).

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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 Second Quarter of 2016

•

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. However, if oil and natural gas prices do not improve from current levels, our future cash flows and financial condition will be negatively impacted.

•

2016 cost reduction initiatives: We are continuing the cost reduction efforts initiated in 2015, and have taken additional actions during the first half 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: In addition to the recently completed sale of assets in Central Louisiana, we are continuing to evaluate dispositions of properties outside of our core Eagle Ford assets.


•	Operational Activity: At our Fasken field in the Eagle Ford play, seven wells were placed into the system during the first half of 2016 at rates between 15 - 20 MMcf per day of natural gas. One well, the Fasken 46H, had mechanical issues and was placed into the system at a restricted rate of nine MMcf per day of natural gas.

•

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. Currently, the Company’s common stock is not available for trading on any national securities exchange. The Company currently expects to be traded on a quoted over-the-counter market during the third quarter of 2016 and on a nationally recognized exchange when reasonably practicable pursuant to the joint plan of reorganization.

•

Effects of Bankruptcy: The bankruptcy, and the Company’s emergence therefrom, had significant effects on the Company’s financial condition and results of operations, including the cancellation of approximately $906 million of indebtedness related to the cancellation of the Company’s senior notes and certain other unsecured claims. As a result, the interest expense associated with the senior notes and certain other unsecured claims will not recur. In addition, the Company received approval to sell a portion of its interest in the Central Louisiana fields known as Burr Ferry and South Bearhead Creek to Texegy LLC, recording net proceeds of approximately $47 million including deposits received prior to the closing date. The Company also incurred significant one-time costs associated with the reorganization, principally professional fees, that significantly affected our results of operations (see “Reorganization Items” in Note 1A of the accompanying condensed consolidated financial statements). Finally, the Company terminated its Prior First Lien Credit Facility, converted the DIP Credit Agreement into post-emergence common stock and entered the New Credit Facility.

•

Subsequent Events: On August 8, 2016, the Board of Directors delivered notices to the Company’s Chief Executive Officer and Chief Financial Officer concerning their retirement and termination from employment and all officer positions with the Company following a transition period, which is expected to be over the next several months. The Chief Executive Officer and Chief Financial Officer shall receive severance benefits, which include cash payments, accelerated vesting of their share-based compensation, and other benefits in accordance with their Third Amended and Restated Employment Agreements. The Board also approved that Mr. Swift shall remain on the Board until his departure as Chief Executive Officer.

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Summary of 2016 Financial Results

•

Second quarter 2016 revenues and net income (loss): Our oil and gas revenues were $43.0 million and $30.6 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor), respectively, compared to $135.6 million in the first six months of 2015. Revenues were lower primarily due to overall lower commodity pricing as well as lower oil and natural gas production. Our 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 $149.6 million in the period of April 23, 2016 through June 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: Our capital expenditures on a cash flow basis were $24.5 million and $20.9 million in the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor), respectively, compared to $105.0 million in the first six months of 2015. The expenditures 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.

Based on the 2016 development plans the Company expects production in the range of 9.25 to 9.42 MBoe with full year lease operating costs in the range of $42 to $43 million.

The Company’s focus for 2016 is to balance capital expenditure with cash flows. For 2016 we have a very limited capital budget which is focused on completion activities in our south Texas fields, with additional drilling in this area later in the year.

•

Net cash (used in) provided by operating activities: For the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor) our net cash provided by (used in) operating activities was $(41.5) million and $15.9 million, respectively, compared to $29.4 million generated during the first six months of 2015, the decrease was primarily due to the impact of decreased revenues which were partially offset by working capital changes.

•

Working capital and debt to capitalization ratio: Our working capital increased from a deficit of $271.2 million at December 31, 2015, to a deficit of $37.4 million at June 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. The Company uses this measure to track its short-term financial position. Our working capital ratio does not include available liquidity through our credit facility.

•

Cash Flows: For the period of April 23, 2016 through June 30, 2016 (successor) the Company had a net increase in cash from Operating Activities of $15.9 million, of which $7.3 million was attributable to changes in working capital. Cash used for property additions was $20.9 million. This included $8.4 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 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 for this period 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 activities, 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 six months ended June 30, 2015 the company generated $29.4 million from operating activities but paid out $105.0 million for capital expenditures, including a net pay down of $46.8 million in payables and accrued capital for 2014 activity. The Company drew a net $74.7 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. As of June 30, 2016, the Company’s liquidity consisted of approximately $4 million of cash-on-hand and $66 million in available borrowings ($51 million after excluding $5.1 million in letters of credit and $10 million in minimum liquidly requirements) on the $320 million borrowing base.

Disposition of Assets. 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. We received net proceeds of approximately $42 million in this transaction at closing (excluding previous deposits received) of which approximately $35 million was used to reduce the amount of borrowings under the Prior First Lien Credit Agreement prior to emergence from bankruptcy, with the remainder used for other corporate purposes.

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 next semi-annual borrowing base redetermination will occur November 1, 2016. As of July 31, 2016, we had $262 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 redetermined 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 June 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 beginning on November 1, 2016 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.

•

We expect to be in compliance with the covenants under this agreement during the next twelve months.

2016 Capital Budget. The Company’s current capital budget for 2016 is between $60 to $70 million, which is significantly reduced from 2015 levels, and includes completion costs for 12 South Texas Eagle Ford wells that were drilled in late 2015 and completed in the first half of 2016. Approximately $38 million of the capital budget has been incurred primarily related to the completions performed in the first half of 2016. The Company plans to drill four additional South Texas Eagle Ford wells later in

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2016 that it expects to complete in early 2017. The capital budget 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 dry gas Fasken area in Webb County. A portion of our capital expenditure program is discretionary and may be further deferred, if necessary. We expect to fund our capital program using cash flows from operations and, if necessary, borrowing availability under our credit facility.

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.

Our contractual commitments for the next five years and thereafter as of June 30, 2016 were as follows (in thousands):



	2016		2017		2018		2019		2020		Thereafter		Total
Credit facility ⁽¹⁾	$	—	$	4,000	$	—	$	250,000	$	—	$	—	$	254,000
Interest on credit facility ⁽²⁾	8,890		17,733		17,500		5,440		—		—		49,563
Gas transportation and processing ⁽³⁾	7,661		9,335		8,732		8,283		7,855		—		41,866
Asset retirement obligation ⁽⁴⁾	5,088		1,569		1,486		129		67		47,767		56,106
Total	$	21,639	$	32,637	$	27,718	$	263,852	$	7,922	$	47,767	$	401,535

(1) Amounts drawn above the conforming amount are due November 1, 2017. Amounts drawn up-to the conforming amount are due on April 22, 2019 which is the maturity date of the agreement. Above amounts do not include interest on the credit facility which is computed at variable rates.

(2) Interest is estimated using 7% APR, the rate in effect at June 30, 2016. Actual interest rate is variable over the term of the facility.

(3) Amounts shown represent fees for the minimum delivery obligations. Any amount of transportation utilized in excess of the minimum will reduce future year obligations.

(4) Amounts shown by year are the net present value at June 30, 2016.

As of June 30, 2016, we had no off-balance sheet arrangements requiring disclosure pursuant to article 303(a) of Regulation S-K.

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Results of Operations

Revenues — Three Months Ended June 30, 2016 and 2015

The tables included below set forth financial information for the periods of April 23, 2016 through June 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.

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 18%, 14% and 23% of our production volumes for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. Crude oil sales were 41%, 37% and 52% of oil and gas sales for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively.

Natural gas production was 69%, 73% and 63% of our production volumes for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. Natural gas sales were 49%, 52% and 40% of oil and gas sales for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 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 period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor):



Core Regions	Oil and Gas Sales (In Millions)
	April 23 - June 30, 2016 (Successor)		April 1 - April 22, 2016 (Predecessor)		Three Months Ended June 30, 2015 (Predecessor)
Artesia Wells	$	2.5	$	0.7	$	5.5
AWP	11.4		3.4		25.5
Fasken	10.9		2.4		16.9
Other South Texas	0.4		0.2		0.9
Total South Texas	25.2		6.7		48.8

Southeast Louisiana	4.8		1.6		14.0

Central Louisiana	0.5		0.3		5.2

Other	0.1		0.1		0.3

Total	$	30.6	$	8.7	$	68.3

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Core Regions	Net Oil and Gas Production Volumes (MBoe)
	(a)	(b)	(a) + (b)	(c)	(a) + (b) - (c)
	April 23 - June 30, 2016 (Successor)	April 1 - April 22, 2016 (Predecessor)	Three Months Ended June 30, 2016	Three Months Ended June 30, 2015 (Predecessor)	Change		% Change
Artesia Wells	140	46	186	275	(89	)	(32	)%
AWP	626	203	829	923	(94	)	(10	)%
Fasken	930	224	1,154	1,093	61		6	%
Other South Texas	30	10	40	44	(4	)	(9	)%
Total South Texas	1,726	483	2,209	2,335	(126	)	(5	)%

Southeast Louisiana	100	38	138	240	(102	)	(43	)%

Central Louisiana	13	15	28	137	(109	)	(80	)%

Other	5	2	7	13	(6	)	(46	)%

Total	1,844	538	2,382	2,725	(343	)	(13	)%

The sales volumes decrease from 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 and our Louisiana fields. In additional 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.

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 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor):



	Sales Volume				Average Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
April 23 - June 30, 2016 (Successor)	254	246	8.1	1,844	$	44.35	$	14.15	$	1.97
April 1 - April 22, 2016 (Predecessor)	95	70	2.2	538	$	37.49	$	11.96	$	1.90
Three Months Ended June 30, 2015 (Predecessor)	628	366	10.4	2,725	$	56.65	$	15.18	$	2.61

For the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015, there was a $9.9 million and $0.1 million loss related to our derivative activities, respectively. There was no hedging program in place for the period of April 1, 2016 through April 22, 2016 (predecessor). Hedging activity is recorded in “Price-risk management and other, net” on the accompanying condensed consolidated statements of operations.

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

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



Costs and Expenses	April 23 - June 30, 2016 (Successor)		April 1 - April 22, 2016 (Predecessor)			Three Months Ended June 30, 2015 (Predecessor)
General and administrative, net	$	4,228	$	1,127		$	10,290
Depreciation, depletion, and amortization	13,334		3,194			42,088
Accretion of asset retirement obligation	832		319			1,381
Lease operating cost	7,781		2,627			17,164
Transportation and gas processing	4,186		1,035			5,086
Severance and other taxes	1,864		1,585			4,424
Interest expense, net	4,257		5,281			18,741
Write-down of oil and gas properties	133,496		—			260,504
Reorganization items	276		(966,571		)	—
Total Costs and Expenses	$	170,254	$	(951,403	)	$	359,678

Lease operating cost. These expenses on a per Boe basis were $4.88, $4.22 and $6.30 for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. The decrease per Boe was primarily due to a concentrated effort to reduce operating costs and included a decrease in chemical costs, lower compression costs, lower maintenance costs and lower labor costs.

Transportation and gas processing. These expenses on a per Boe basis were $1.92, $2.27 and $1.87 for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Boe basis were $5.94, $7.23 and $15.45 for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. The depletion expense recorded in the period of April 23, 2016 through June 30, 2016 (successor) is not comparable other periods due to the restatement of assets at their fair value upon emergence from bankruptcy. The lower depletion rate for the period of April 1, 2016 through April 22, 2016 (predecessor) is lower than the second quarter of 2015 due to ceiling test write-downs during 2015 and the first quarter of 2016 which lowered the depletable base.

General and Administrative Expenses, Net. These expenses on a per Boe basis were $2.09, $2.29 and $3.78 for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. The decrease per Boe was primarily due to lower salaries and burdens, a lower corporate benefit accrual and lower share-based compensation expense, partially offset by lower capitalized amounts.

Severance and Other Taxes. These expenses on a per Boe basis were $2.95, $1.01 and $1.62 for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively. Severance tax expense for the period of April 1, 2016 through April 22, 2016 (predecessor) includes a regulatory audit adjustment of $1.1 million. Severance and other taxes, as a percentage of oil and gas sales, were approximately 18.3%, 6.1% and 6.5% for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively.

Interest. Our gross interest cost was $5.3 million, $4.3 million and $19.9 million for the period of April 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the three months ended June 30, 2015 (predecessor), respectively, of which $1.2 million was capitalized in 2015, while no interest was capitalized in 2016. The decrease in gross interest was primarily due to the discontinuance of interest on our senior notes due to our bankruptcy proceedings,

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partially offset by interest expense related to the DIP Credit Agreement. Upon emergence from bankruptcy our only interest bearing debt is our credit facility.

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 June 30, 2016 (successor). Due to changes in pricing, timing of projects and changes in our reserves product mix we incurred a write-down of $260.5 million in the second quarter of 2015. There was no write-down for the period of April 1, 2016 through April 22, 2016 (predecessor).

Reorganization Items. We incurred a net gain of $966.6 million and expenses of $0.3 million for the period of April 1, 2016 through April 22, 2016 (predecessor) and period of April 23, 2016 through June 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 second quarter 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 its recent history of incurring tax losses and economic uncertainty it 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. It will be able to fully offset this gain with its 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 April 1, 2016 through April 22, 2016 (predecessor). The tax benefit for all loss periods is also offset with valuation allowances.

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Revenues — Six Months Ended June 30, 2016 and 2015

Crude oil production was 19%, 14% and 23% of our production volumes for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively. Crude oil sales were 38%, 37% and 49% of oil and gas sales for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively.

Natural gas production was 68%, 73% and 63% of our production volumes in the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively. Natural gas sales were 52% of oil and gas sales for the period of January 1, 2016 through April 22, 2016 (predecessor) and the period of April 23, 2016 through June 30, 2016 (successor), respectively, and 42% of oil and gas sales for the six months ended June 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 January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor):



Core Regions	Oil and Gas Sales (In Millions)
	April 23 - June 30, 2016 (Successor)		January 1 - April 22, 2016 (Predecessor)		Six Months Ended June 30, 2015 (Predecessor)
Artesia Wells	$	2.5	$	3.5	$	11.0
AWP	11.4		14.7		52.4
Fasken	10.9		14.3		33.5
Other South Texas	0.4		0.9		1.9
Total South Texas	25.2		33.4		98.8

Southeast Louisiana	4.8		7.2		26.2

Central Louisiana	0.5		2.3		10.2

Other	0.1		0.1		0.4

Total	$	30.6	$	43.0	$	135.6



Core Regions	Net Oil and Gas Production Volumes (MBoe)
	(a)	(b)	(a) + (b)	(c)	(a) + (b) - (c)
	April 23 - June 30, 2016 (Successor)	January 1 - April 22, 2016 (Predecessor)	Six Months Ended June 30, 2016	Six Months Ended June 30, 2015 (Predecessor)	Change		% Change
Artesia Wells	140	257	397	563	(166	)	(29	)%
AWP	626	951	1,577	2,075	(498	)	(24	)%
Fasken	930	1,213	2,143	2,086	57		3	%
Other South Texas	30	56	86	95	(9	)	(9	)%
Total South Texas	1,726	2,477	4,203	4,819	(616	)	(13	)%

Southeast Louisiana	100	216	316	496	(180	)	(36	)%

Central Louisiana	13	107	120	287	(167	)	(58	)%

Other	5	7	12	25	(13	)	(52	)%

Total	1,844	2,807	4,651	5,627	(976	)	(17	)%

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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 six months ended June 30, 2016 and 2015:



	Sales Volume				Average Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
April 23 - June 30, 2016 (Successor)	254	246	8.1	1,844	$	44.35	$	14.15	$	1.97
January 1 - April 22, 2016 (Predecessor)	522	380	11.4	2,807	$	31.43	$	11.04	$	1.96
Six Months Ended June 30, 2015	1,314	793	21.1	5,627	$	50.62	$	15.67	$	2.69

For the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015, we recorded total net gains (losses) of $(9.9) million and $0.3 million, respectively, related to our derivative activities. There was no hedging program in place for the period of January 1, 2016 through April 22, 2016 (predecessor).

Costs and Expenses — Six Months Ended June 30, 2016 and 2015

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



Costs and Expenses	April 23 - June 30, 2016 (Successor)		January 1 - April 22, 2016 (Predecessor)			Six Months Ended June 30, 2015 (Predecessor)
General and administrative, net	$	4,228	$	9,245		$	22,846
Depreciation, depletion, and amortization	13,334		20,439			102,786
Accretion of asset retirement obligation	832		1,610			2,746
Lease operating cost	7,781		14,933			36,198
Transportation and gas processing	4,186		6,090			10,409
Severance and other taxes	1,864		3,917			9,556
Interest expense, net	4,257		13,347			36,969
Write-down of oil and gas properties	133,496		77,732			763,073
Reorganization items	276		(956,142		)	—
Total Costs and Expenses	$	170,254	$	(808,829	)	$	984,583

Lease operating cost. These expenses on a per Boe basis were $5.32, $4.22 and $6.43 for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively. The decrease was due to lower workover, insurance, labor, compression, maintenance, chemicals and salt water disposal costs primarily driven by concentrated efforts to reduce operating costs.

Transportation and gas processing. These expenses on a per Boe basis were $2.17, $2.27 and $1.85 for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively.

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Depreciation, Depletion and Amortization (“DD&A”). These expenses on a per Boe basis were $7.28, $7.23 and $18.27 for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively. The depletion expense recorded subsequent to April 22, 2016 is not comparable to the second quarter of 2015 due to the restatement of assets at their fair value upon emergence from bankruptcy. The decreased rate from the six months ended June 30, 2015 (predecessor) to 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 $3.29, $2.29 and $4.06 for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively. The decrease was primarily due to lower salaries and burdens, a lower corporate benefit accrual and lower share-based compensation expense, partially offset by lower capitalized amounts.

Severance and Other Taxes. These expenses on a per Boe basis were $1.40, $1.01 and $1.70 for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 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 9.1%, 6.1% and 7.0% for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively

Interest. Our gross interest cost was $13.3 million, $4.3 million and $39.4 million for the period of January 1, 2016 through April 22, 2016 (predecessor), the period of April 23, 2016 through June 30, 2016 (successor) and the six months ended June 30, 2015 (predecessor), respectively, of which $2.4 million was capitalized in 2015, while no interest was capitalized in 2016. 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 June 30, 2016 (successor). 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 $763.1 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), respectively.

Reorganization Items. We incurred a net gain of $956.1 million and expenses of $0.3 million for the period of January 1, 2016 through April 22, 2016 (predecessor) and period of April 23, 2016 through June 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 six 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 its recent history of incurring tax losses and economic uncertainty it 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. It will be able to fully offset this gain with its 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). The tax benefit for all loss periods is also offset with valuation allowances. The tax benefit of $80.1 million for the first six 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 are reflected in our condensed consolidated balance sheet as of June 30, 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.

The costs of unproved properties not being amortized are assessed quarterly, on a property-by-property basis, to determine whether such properties have been impaired. In determining whether such costs should be impaired, we evaluate current drilling results, lease expiration dates, current oil and gas industry conditions, international economic conditions, capital availability, and available geological and geophysical information. As these factors may change from period to period, our evaluation of these factors will change. Any impairment assessed is added to the cost of proved properties being amortized.

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of unproved properties. The estimation process for both reserves and the impairment of unproved properties is subjective, and results may change over time based on current information and industry conditions. We believe our estimates and assumptions are reasonable; however, such estimates and assumptions are subject to a number of risks and uncertainties that may cause actual results to differ materially from such estimates.

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations and deferred income taxes) 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").

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 June 30, 2016 (successor) of $133.5 million. 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 June 30, 2015 (predecessor), we reported a non-cash impairment write-down of $260.5 million on our oil and natural gas properties. For the period of January 1, 2016 through April 22, 2016 (predecessor) and the six months ended June 30, 2015 (predecessor), we reported a non-cash impairment write-down of $77.7 million and $763.1 million, respectively, on our oil and natural gas properties.

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 remain low or decline from the prices used in the Ceiling Test, it is likely 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 would 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. However, due to current trends in commodity pricing it is possible that we will record additional ceiling test write-downs in future periods.

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

Interest Rate Risk. At June 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 June 30, 2016 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 First Quarter 2016 Report Form 10-Q.

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

The following table summarizes repurchases of our common stock occurring during the period of January 1, 2016 through April 22, 2016 (predecessor). In connection with the Company's emergence from Chapter 11 bankruptcy, all common stock was canceled:



Period	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (in thousands)
April 1 – 22, 2016 ⁽¹⁾	1,959	$	0.18	—	$	—
(1) These shares were withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares.

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.



2.1	Second Amended Joint Plan of Reorganization of the Debtors and Debtors in Possession dated March 28, 2016 (incorporated by reference as Exhibit 2.1 to Swift Energy Company’s Form 8-K filed April 6, 2016, File No. 001-08754).
3.1	Certificate of Incorporation of Swift Energy Company (incorporated by reference as Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2	Bylaws of Swift Energy Company (incorporated by reference as Exhibit 3.2 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
4.1	Form of stock certificate for common stock, $0.01 par value per share (incorporated by reference as Exhibit 4.6 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
4.2	Registration Rights Agreement, dated as of April 22, 2016, by and among Swift Energy Company and the stockholders party thereto (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
4.3	Director Nomination Agreement, dated as of April 22, 2016, by and among Swift Energy Company and the stockholders party thereto (incorporated by reference as Exhibit 4.7 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.1	Senior Secured Revolving Credit Agreement, dated April 22, 2016, among Swift Energy Company, JPMorgan Chase Bank, National Association and the Lenders party thereto (incorporated by reference as Exhibit 10.3 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.2	Warrant Agreement, dated as of April 22, 2016, between Swift Energy Company and American Stock Transfer & Trust Company, LLC (incorporated by reference as Exhibit 10.4 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.3+	Employment Agreement of Terry E. Swift dated April 22, 2016 (incorporated by reference as Exhibit 10.5 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.4+	Employment Agreement of Robert J. Banks dated April 22, 2016 (incorporated by reference as Exhibit 10.6 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.5+	Employment Agreement of Alton D. Heckaman, Jr. dated April 22, 2016 (incorporated by reference as Exhibit 10.7 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.6+	Swift Energy Company 2016 Equity Incentive Plan (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.7+	Form of Stock Option Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.2 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.8+	Form of Stock Option Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.3 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.9+	Form of Restricted Stock Unit Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.4 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.10+	Form of Restricted Stock Unit Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.5 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.11	Form of Stock Option Award Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed June 14, 2016, File No. 001-08754).
10.12	Form of Restricted Stock Unit Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Form 8-K filed June 14, 2016, File No. 001-08754).
99.1	Findings of Fact, Conclusions of Law and Order Confirming Pursuant to Section 1129(a) and (b) of the Bankruptcy Code the Joint Plan of Reorganization of the Debtors and Debtors in Possession, as entered by the Bankruptcy Court on March 31, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed April 6, 2016, File No. 001-08754).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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

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+Indicates Management Compensatory Plan, Contract or Arrangement

*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:	August 9, 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



2.1	Second Amended Joint Plan of Reorganization of the Debtors and Debtors in Possession dated March 28, 2016 (incorporated by reference as Exhibit 2.1 to Swift Energy Company’s Form 8-K filed April 6, 2016, File No. 001-08754).
3.1	Certificate of Incorporation of Swift Energy Company (incorporated by reference as Exhibit 3.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
3.2	Bylaws of Swift Energy Company (incorporated by reference as Exhibit 3.2 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
4.1	Form of stock certificate for common stock, $0.01 par value per share (incorporated by reference as Exhibit 4.6 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
4.2	Registration Rights Agreement, dated as of April 22, 2016, by and among Swift Energy Company and the stockholders party thereto (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
4.3	Director Nomination Agreement, dated as of April 22, 2016, by and among Swift Energy Company and the stockholders party thereto (incorporated by reference as Exhibit 4.7 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.1	Senior Secured Revolving Credit Agreement, dated April 22, 2016, among Swift Energy Company, JPMorgan Chase Bank, National Association and the Lenders party thereto (incorporated by reference as Exhibit 10.3 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.2	Warrant Agreement, dated as of April 22, 2016, between Swift Energy Company and American Stock Transfer & Trust Company, LLC (incorporated by reference as Exhibit 10.4 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.3+	Employment Agreement of Terry E. Swift dated April 22, 2016 (incorporated by reference as Exhibit 10.5 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.4+	Employment Agreement of Robert J. Banks dated April 22, 2016 (incorporated by reference as Exhibit 10.6 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.5+	Employment Agreement of Alton D. Heckaman, Jr. dated April 22, 2016 (incorporated by reference as Exhibit 10.7 to Swift Energy Company’s Form 8-K filed April 28, 2016, File No. 001-08754).
10.6+	Swift Energy Company 2016 Equity Incentive Plan (incorporated by reference as Exhibit 4.1 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.7+	Form of Stock Option Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.2 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.8+	Form of Stock Option Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.3 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.9+	Form of Restricted Stock Unit Agreement - Emergence Grant (Type I) (incorporated by reference as Exhibit 4.4 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.10+	Form of Restricted Stock Unit Agreement - Emergence Grant (Type II) (incorporated by reference as Exhibit 4.5 to Swift Energy Company’s Form S-8 filed April 27, 2016, File No. 333-210936).
10.11	Form of Stock Option Award Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed June 14, 2016, File No. 001-08754).
10.12	Form of Restricted Stock Unit Agreement - Non Employee Directors (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Form 8-K filed June 14, 2016, File No. 001-08754).
99.1	Findings of Fact, Conclusions of Law and Order Confirming Pursuant to Section 1129(a) and (b) of the Bankruptcy Code the Joint Plan of Reorganization of the Debtors and Debtors in Possession, as entered by the Bankruptcy Court on March 31, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed April 6, 2016, File No. 001-08754).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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

Table of Contents

+Indicates Management Compensatory Plan, Contract or Arrangement

*Filed herewith