SILVERBOW RESOURCES, INC. - Quarter Report: 2016 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(X) Quarterly Report Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

For the quarterly period ended March 31, 2016

Commission File Number 1-8754

SWIFT ENERGY COMPANY

(Exact Name of Registrant as Specified in Its Charter)



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

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)	45,112,751 Shares outstanding prior to the Company's emergence from bankruptcy on April 22, 2016 10,000,001 Shares outstanding at April 29, 2016

SWIFT ENERGY COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 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	5

	Condensed Consolidated Statements of Cash Flows	6

	Notes to Condensed Consolidated Financial Statements	7

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

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	34

Part II	OTHER INFORMATION

Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.	Defaults Upon Senior Securities	37
Item 4.	Mine Safety Disclosures	37
Item 5.	Other Information	37
Item 6.	Exhibits	37

SIGNATURES		39
Exhibit Index		40

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Condensed Consolidated Balance Sheets

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



	March 31, 2016			December 31, 2015
	(Unaudited)
ASSETS
Current Assets:
Cash and cash equivalents	$	17,782		$	29,460
Accounts receivable	18,537			21,704
Other current assets	4,098			10,683
Total Current Assets	40,417			61,847

Property and Equipment:
Property and Equipment, including $18,839 of unproved property costs not being amortized at the end of each period	6,060,121			6,035,757
Less – Accumulated depreciation, depletion, and amortization	(5,673,015		)	(5,577,854		)
Property and Equipment, Net	387,106			457,903
Other Long-Term Assets	5,751			5,248
Total Assets	$	433,274		$	524,998
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts payable and accrued liabilities	$	60,626		$	7,663
Accrued capital costs	9,676			—
Accrued interest	475			490
Undistributed oil and gas revenues	6,444			—
Current portion of long-term debt	339,900			324,900
Total Current Liabilities	417,121			333,053

Asset Retirement Obligation	57,614			56,390
Other Long-Term Liabilities	685			3,891
Liabilities subject to compromise	917,972			984,388

Commitments and Contingencies	—			—

Stockholders' Equity:
Preferred stock, $.01 par value, 5,000,000 shares authorized, none outstanding	—			—
Common stock, $.01 par value, 150,000,000 shares authorized, 44,994,948 and 44,771,258 shares issued, and 44,752,342 and 44,591,863 shares outstanding, respectively	450			448
Additional paid-in capital	777,269			776,358
Treasury stock held, at cost, 242,606, and 179,395 shares, respectively	(2,495		)	(2,491		)
Retained earnings (Accumulated deficit)	(1,735,342		)	(1,627,039		)
Total Stockholders’ Equity (Deficit)	(960,118		)	(852,724		)
Total Liabilities and Stockholders’ Equity	$	433,274		$	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 through April 22, 2016) (in thousands, except per-share amounts)



	Three Months Ended March 31,
	2016			2015
Revenues:
Oil and gas sales	$	34,367		$	67,358
Price-risk management and other, net	(95		)	979
Total Revenues	34,272			68,337

Costs and Expenses:
General and administrative, net	8,118			12,556
Depreciation, depletion, and amortization	17,245			60,698
Accretion of asset retirement obligation	1,291			1,365
Lease operating cost	12,307			19,034
Transportation and gas processing	5,055			5,323
Severance and other taxes	2,332			5,132
Interest expense, net (excludes contractual interest expense of $17,320 on senior notes subject to compromise for the three months ended March 31, 2016)	8,066			18,228
Write-down of oil and gas properties	77,732			502,569
Reorganization items	10,429			—
Total Costs and Expenses	142,575			624,905

Income (Loss) Before Income Taxes	(108,303		)	(556,568		)

Provision (Benefit) for Income Taxes	—			(79,491		)

Net Income (Loss)	$	(108,303	)	$	(477,077	)

Per Share Amounts-

Basic: Net Income (Loss)	$	(2.42	)	$	(10.79	)

Diluted: Net Income (Loss)	$	(2.42	)	$	(10.79	)

Weighted Average Shares Outstanding - Basic	44,672			44,232

Weighted Average Shares Outstanding - Diluted	44,672			44,232

See accompanying Notes to Condensed Consolidated Financial Statements.

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Condensed Consolidated Statements of Stockholders’ Equity

Swift Energy Company and Subsidiaries (Debtor-in-Possession 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, 2014	$	444	$	771,972		$	(9,855	)	$	31,817		$	794,378
Stock issued for benefit plans (352,476 shares)	—		(1,714		)	7,518			(4,885		)	919
Purchase of treasury shares (70,437 shares)	—		—			(154		)	—			(154		)
Employee stock purchase plan (87,629 shares)	1		301			—			—			302
Issuance of restricted stock (304,166 shares)	3		(3		)	—			—			—
Amortization of share-based compensation	—		5,802			—			—			5,802
Net Income (Loss)	—		—			—			(1,653,971		)	(1,653,971		)
Balance, December 31, 2015	$	448	$	776,358		$	(2,491	)	$	(1,627,039	)	$	(852,724	)

Purchase of treasury shares (63,211 shares) ⁽¹⁾	—		—			(4		)	—			(4		)
Issuance of restricted stock (223,690 shares) ⁽¹⁾	2		(2		)	—			—			—
Amortization of share-based compensation ⁽¹⁾	—		913			—			—			913
Net Income (Loss) ⁽¹⁾	—		—			—			(108,303		)	(108,303		)
Balance, March 31, 2016 ⁽¹⁾	$	450	$	777,269		$	(2,495	)	$	(1,735,342	)	$	(960,118	)

(1) Unaudited

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 through April 22, 2016) (in thousands)



	Three Months Ended March 31,
	2016			2015
Cash Flows from Operating Activities:
Net income (loss)	$	(108,303	)	$	(477,077	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities-
Depreciation, depletion, and amortization	17,245			60,698
Write-down of oil and gas properties	77,732			502,569
Accretion of asset retirement obligation	1,291			1,365
Deferred income taxes	—			(79,491		)
Share-based compensation expense	770			879
Reorganization items (non-cash)	5,422			—
Other	2,551			373
Change in assets and liabilities-
(Increase) decrease in accounts receivable and other current assets	3,167			7,880
Increase (decrease) in accounts payable and accrued liabilities	5,185			(9,646		)
Increase (decrease) in accrued interest	(15		)	(8,320		)
Net Cash Provided by (Used in) Operating Activities	5,045			(770		)

Cash Flows from Investing Activities:
Additions to property and equipment	(36,595		)	(49,173		)
Proceeds from the sale of property and equipment	4,876			—
Net Cash Provided by (Used in) Investing Activities	(31,719		)	(49,173		)

Cash Flows from Financing Activities:
Proceeds from bank borrowings	15,000			103,400
Payments of bank borrowings	—			(53,700		)
Net proceeds from issuances of common stock	—			302
Purchase of treasury shares	(4		)	(154		)
Net Cash Provided by (Used in) Financing Activities	14,996			49,848

Net increase (decrease) in Cash and Cash Equivalents	(11,678		)	(95		)

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

Cash and Cash Equivalents at End of Period	$	17,782		$	311

Supplemental Disclosures of Cash Flows Information:

Cash paid during period for interest, net of amounts capitalized	$	4,793		$	25,979
Cash paid for reorganization items	$	5,007		$	—
See accompanying Notes to Condensed Consolidated Financial Statements.

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Notes to Condensed Consolidated Financial Statements

Swift Energy Company and Subsidiaries

(1A) 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 on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession for the entire quarter ended March 31, 2016. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented.

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 three months ended March 31, 2016. For that period, contractual interest on the senior notes totaled $17.3 million.

Plan of Reorganization. Pursuant to the plan of reorganization that the bankruptcy court confirmed, 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 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 under and more fully described below) received a backstop fee consisting of 7.5% of the post-emergence Company’s common stock;


•	the Company drew down the entire $75.0 million available under the DIP Credit Agreement, and the DIP Credit Agreement was converted into the Company’s post-emergence common stock;


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


•	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 that, 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 proceedings of approximately $46.9 million including deposits received prior to the closing date; and


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

In accordance with the plan of reorganization, 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 the new non-executive chairman of the Board). In addition, pursuant to the plan of reorganization, SVP and the other former holders of the Company’s senior notes were given certain continuing nomination rights subject to conditions on share ownership.

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bankruptcy, the Company had drawn down the entire $75.0 million available. Pursuant to the plan of reorganization, 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 current holders of the senior notes and certain unsecured creditors. As such, 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. For more information refer to Note 5 of these condensed consolidated financial statements.

Fresh Start Accounting. In connection with the Company’s emergence from bankruptcy, we will be required to apply fresh start accounting to our financial statements because (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the plan of reorganization was less than the post-petition liabilities and allowed claims. Fresh start accounting will be applied to the Company’s consolidated financial statements as of April 22, 2016, the date on which we emerged from bankruptcy. Under the principles of fresh start accounting, a new reporting entity was considered to be created, and, as a result, the Company will allocate the reorganization value of the Company to its individual assets based on their estimated fair values. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the financial statements on or after April 22, 2016 will not be comparable with the financial statements prior to that date.

Financial Statement Classification of Liabilities Subject to Compromise. Our financial statements include amounts classified as Liabilities subject to compromise, which represent liabilities that have been allowed, or that we anticipate will be allowed, as claims in our bankruptcy case. As previously referenced, resolution of certain of these claims have and will extend beyond the date we exited bankruptcy. These balances include amounts related to the anticipated rejection of various executory contracts and unexpired leases. Because the uncertain nature of many of the potential claims has not been determined at this time, the magnitude of such claims is not reasonably estimable at this time. Such claims may be material.

The following table summarizes the components of liabilities subject to compromise included on our condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015 (in thousands):



	March 31, 2016		December 31, 2015
Accounts payable and accrued liabilities	$	2,607	$	55,587
Accrued capital costs	1,611		7,225
Undistributed oil and gas revenues	1,881		11,989
Senior notes and accrued interest	905,629		905,629
Other long-term liabilities	6,244		3,958
Liabilities subject to compromise	$	917,972	$	984,388

Excluding the Senior notes and accrued interest on the Senior notes, Liabilities Subject to Compromise decreased during the first quarter of 2016 as payments were made during the quarter in accordance with orders issued by the bankruptcy court and also in connection with the Court's confirmation of the Company's joint plan of reorganization on March 31, 2016, which resulted in most creditors' claims being reclassified out of Liabilities subject to compromise.

Reorganization Items. The Company and the Chapter 11 Subsidiaries have incurred significant one-time costs associated with the reorganization, principally professional fees. The amount of these costs, which are being expensed as incurred, significantly affect our results of operations.

The following table summarizes the components included in Reorganization items in our condensed consolidated statements of operations for the three months ended March 31, 2016 (in thousands):



	March 31, 2016
Reorganization legal and professional fees and expenses	$	13,553
Reorganization pre-petition accounts payable settlements	(3,124		)
Reorganization items	$	10,429

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(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. Our independent registered public accounting firm expressed their audit opinion dated March 4, 2016 on such financial statements with a going concern uncertainty explanatory paragraph.

(2) Summary of Significant Accounting Policies

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

Subsequent Events. We have evaluated subsequent events of our condensed consolidated financial statements. 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 used primarily to reduce the amount of borrowings under the Company’s prior Second Amended and Restated Credit Agreement, dated as of September 21, 2010 (the “Existing First Lien Credit Agreement”), and for other general corporate purposes.

On April 22, 2016, the Effective Date, the company completed its financial restructuring and emerged from Chapter 11 bankruptcy proceedings after completing all required actions and satisfying the remaining conditions to its Plan of Reorganization, which was confirmed by the US Bankruptcy Court for the District of Delaware by order dated March 31, 2016. See Note 1A of these condensed consolidated financial statements for more information regarding the Company's emergence from bankruptcy. We cannot currently estimate the financial effect of the Company's emergence from bankruptcy on our financial statements, although we expect to record material adjustments related to our plan of reorganization and also due to the application of fresh start accounting guidance upon emergence.

There were no other material subsequent events requiring additional disclosure in these financial statements.

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


•	the estimated quantities of proved oil and natural gas reserves used to compute depletion of oil and natural gas properties, 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,

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•	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 will be recorded in the period during which the adjustments occur.

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

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized. Such costs may be incurred both prior to and after the acquisition of a property and include lease acquisitions, geological and geophysical services, drilling, completion, and equipment. Internal costs incurred that are directly identified with exploration, development, and acquisition activities undertaken by us for our own account, and which are not related to production, general corporate overhead, or similar activities, are also capitalized. For the three months ended March 31, 2016 and 2015, such internal costs capitalized totaled $2.5 million and $3.7 million, respectively. Interest costs are also capitalized to unproved oil and natural gas properties (refer to Note 5 of these condensed consolidated financial statements for further discussion on capitalized interest costs).

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



	March 31, 2016			December 31, 2015
Property and Equipment
Proved oil and gas properties	$	5,997,030		$	5,972,666
Unproved oil and gas properties	18,839			18,839
Furniture, fixtures, and other equipment	44,252			44,252
Less – Accumulated depreciation, depletion, and amortization	(5,673,015		)	(5,577,854		)
Property and Equipment, Net	$	387,106		$	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.

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.

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. 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.

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

Full-Cost Ceiling Test. At the end of each quarterly reporting period, the unamortized cost of oil and natural gas properties (including natural gas processing facilities, capitalized asset retirement obligations, net of related salvage values and deferred income taxes, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects (“Ceiling Test”).

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.

Principally due to the effects of pricing, and also due to the timing of projects and changes in our reserves product mix, for the three months ended March 31, 2016 and 2015, we reported a non-cash impairment write-down, on a before-tax basis, of $77.7 million and $502.6 million, respectively, on our oil and natural gas properties.

If future capital expenditures out pace future discounted net cash flows in our reserve calculations, if we have significant declines in our oil and natural gas reserves volumes (which also reduces our estimate of discounted future net cash flows from proved oil and natural gas reserves) or if oil or natural gas prices decline 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. Swift Energy uses the entitlement method of accounting in which we recognize our ownership interest in production as revenue. If our sales exceed our ownership share of production, the natural gas balancing payables are reported in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets. Natural gas balancing receivables are reported in “Other current assets” on the accompanying condensed consolidated balance sheets when our ownership share of production exceeds sales. As of March 31, 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 March 31, 2016 and December 31, 2015, we had an allowance for doubtful accounts of approximately $0.1 million. The allowance for doubtful accounts has been deducted from the total “Accounts receivable” balance on the accompanying condensed consolidated balance sheets.

At March 31, 2016, our “Accounts receivable” balance included $11.6 million for oil and gas sales, $2.9 million for joint interest owners, $1.9 million for severance tax credit receivables and $2.1 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

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three months ended March 31, 2016 and 2015 did not exceed our actual costs incurred. The total amount of supervision fees charged to the wells we operated were $2.0 million and $2.7 million for the three months ended March 31, 2016 and 2015.

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 March 31, 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 $3.5 million and $4.4 million at March 31, 2016 and December 31, 2015, respectively. These prepaid amounts cover well insurance, drilling contracts and various other prepaid expenses.

Income Taxes. Under guidance contained in FASB ASC 740-10, deferred taxes are determined based on the estimated future tax effects of differences between the financial statement and tax basis of assets and liabilities, given the provisions of the enacted tax laws.

We follow the recognition and disclosure provisions under guidance contained in FASB ASC 740-10-25. Under this guidance, tax positions are evaluated for recognition using a more-likely-than-not threshold, and those tax positions requiring recognition are measured as the largest amount of tax benefit that is greater than fifty percent likely of being realized upon ultimate settlement with a taxing authority that has full knowledge of all relevant information. Our policy is to record interest and penalties relating to uncertain tax positions in income tax expense. At March 31, 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 income tax returns for 2007 forward, our Louisiana income tax returns from 2000 forward and our Texas franchise tax returns after 2010 remain subject to examination by the taxing authorities. There are no material unresolved items related to periods previously audited by these taxing authorities. No other jurisdiction returns are significant to our financial position.

For the three months ended March 31, 2016, the tax benefit for the book loss was offset by an increase in our valuation allowance against our deferred tax assets.

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



	March 31, 2016		December 31, 2015
Trade accounts payable ⁽¹⁾⁽²⁾	$	24,731	$	—
Accrued operating expenses ⁽¹⁾	3,775		—
Accrued compensation costs ⁽¹⁾	4,059		—
Asset retirement obligation – current portion	7,719		7,165
Accrued taxes ⁽¹⁾	3,022		—
Other payables ⁽³⁾⁽⁴⁾	17,320		498
Total accounts payable and accrued liabilities	$	60,626	$	7,663

(1) Total balance classified as Liabilities subject to compromise as of December 31, 2015.

(2) Total balance at March 31, 2016 was $26.3 million, of which $1.6 million was classified as Liabilities subject to compromise with the remaining portion classified as "Trade accounts payable".

(3) Total balance at March 31, 2016 and December 31, 2015 was $18.3 million and $5.3 million, respectively, of which $1.0 million and $4.8 million were classified as Liabilities subject to compromise with the remaining portion classified as "Other payables".

(4) Total balance at March 31, 2016 includes $7.1 million in accrued legal and professional fees primarily related to the company's bankruptcy proceedings.

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.

Long-term Restricted Cash. Long-term restricted cash includes amounts held in escrow accounts to satisfy plugging and abandonment obligations. As of March 31, 2016 and December 31, 2015, these assets were approximately $1.0 million. These

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amounts are restricted as to their current use and will be released when we have satisfied all plugging and abandonment obligations in certain fields. These restricted cash balances are reported in “Other Long-Term Assets” on the accompanying condensed consolidated balance sheets.

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. When the Company reissues treasury stock the gains are recorded in "Additional paid-in capital" ("APIC") on the accompanying condensed consolidated balance sheets, while the losses are recorded to APIC to the extent that previous net gains on the reissuance of treasury stock are available to offset the losses. If the loss is larger than the previous gains available then the loss is recorded to "Retained earnings (Accumulated deficit)" on the accompanying condensed consolidated balance sheets.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09, providing a comprehensive revenue recognition standard for contracts with customers that supersedes current revenue recognition guidance. The guidance 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. The guidance is effective for annual and interim reporting periods beginning after December 15, 2017. We are currently reviewing the new requirements to determine the impact of this guidance on our financial statements.

In July 2015, the FASB issued ASU 2015-11, which changes the measurement principle for inventory from the lower of cost or market to “lower of cost and net realizable value.” The standard simplifies the current guidance under which an entity must measure inventory at the lower of cost or market (market in this context is defined as one of three different measures, one of which is net realizable value). Net realizable value is defined as the “estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” The guidance is effective for fiscal years beginning after December 15, 2016, including interim periods thereafter, and must be applied prospectively after the date of adoption. We do not expect this new guidance to have a material impact on our financial statements.

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. If applied prospectively, the guidance requires we disclose the nature of and reason for the change in accounting principle as well as a statement that prior periods were not retrospectively adjusted. We do not expect this new guidance to have a material impact on our financial statements.

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

(3) Share-Based Compensation

Bankruptcy Proceedings

Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company’s current common stock was canceled and new common stock was issued. The Company's currently existing share-based compensation awards were also either vested or canceled upon the Company's emergence from bankruptcy. Accelerated vesting and cancellation of these share-based compensation awards will result in the recognition of expense, on the date of vesting or cancellation, to record any previously unamortized expense related to the awards.

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Share-Based Compensation Plans

We have various types of share-based compensation plans. Refer to Part III, as well as Note 7 in our Annual Report on Form 10-K, for the fiscal year ended December 31, 2015 for additional information related to these share-based compensation plans. We follow guidance contained in FASB ASC 718 to account for share-based compensation.

We receive a tax deduction for certain stock option exercises during the period the stock options are exercised, generally for the excess of the market value on the exercise date over the exercise price of the stock option awards. We receive an additional tax deduction when restricted stock awards vest at a higher value than the value used to recognize compensation expense at the date of grant. We are required to report excess tax benefits from the award of equity instruments as financing cash flows. For the three months ended March 31, 2016, there was no income tax benefit or shortfall in earnings, while for the three months ended March 31, 2015 we did recognize an income tax shortfall in earnings of $1.2 million, 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 $0.7 million and $0.8 million for the three months ended March 31, 2016 and 2015. Share-based compensation expense recorded in lease operating cost was less than $0.1 million for the three months ended March 31, 2016 and 2015, respectively. We also capitalized $0.2 million and $0.3 million of share-based compensation for the three months ended March 31, 2016 and 2015, 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

We use the Black-Scholes-Merton option pricing model to estimate the fair value of stock option awards. During the three months ended March 31, 2016, 111,984 stock option awards expired leaving 1,218,406 stock option awards outstanding at March 31, 2016. There was no other activity relating to our stock option awards during the three months ended March 31, 2016.

As of March 31, 2016, our stock option awards outstanding and exercisable had no aggregate intrinsic value since all outstanding stock option awards were out of the money, and we did not have any remaining unrecognized compensation cost related to stock option awards. At March 31, 2016, the weighted average contract life of stock option awards outstanding and exercisable was 3.8 years. Upon the Company's emergence from bankruptcy on April 22, 2016, these outstanding awards were canceled.

Restricted Stock Awards

The plans, as described in Note 7 of our consolidated financial statements in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, allow for the issuance of restricted stock awards that generally may not be sold or otherwise transferred until certain restrictions have lapsed. The unrecognized compensation cost related to these awards is typically expensed over the period the restrictions lapse (generally one to three years). Upon the Company's emergence from bankruptcy on April 22, 2016, the outstanding restricted stock awards for most employees vested on an accelerated basis while awards issued to certain members of management of the Company and the Board of Directors were canceled.

The compensation expense for these awards was determined based on the closing market price of our stock at the date of grant applied to the total number of shares that were anticipated to fully vest. As of March 31, 2016, we had unrecognized compensation expense of $2.3 million related to restricted stock awards which was expected to be recognized over a weighted-average period of 1.2 years. The grant date fair value of shares vested during the three months ended March 31, 2016 was $3.4 million.

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The following table represents restricted stock award activity for the three months ended March 31, 2016:



	Shares		Wtd. Avg. Grant Price
Restricted shares outstanding, beginning of period	1,487,076		$	8.94
Restricted shares granted	—		$	—
Restricted shares canceled	(57,077	)	$	9.21
Restricted shares vested	(223,690	)	$	15.35
Restricted shares outstanding, end of period	1,206,309		$	7.73

Performance-Based Restricted Stock Units

For the three months ended March 31, 2015, the Company granted 216,450 units of performance-based restricted stock units containing market conditions that require the price of our common stock to increase to $5.22 per share by December 31, 2017, the end of the performance period, before any payout is achieved. These units were granted at 100% of the target payout level with conditions of the grants allowing for a payout ranging between no payout and 200% of target. The compensation expense for these awards is based on the per unit grant date valuation using a Monte-Carlo simulation multiplied by the target payout level. The payout level is calculated based on actual stock price performance achieved during the performance period. The awards have a cliff vesting period of 3.0 years. Upon the Company's emergence from bankruptcy on April 22, 2016, these outstanding awards were canceled.

As of March 31, 2016, we had unrecognized compensation expense of $0.6 million related to our restricted stock units, which was expected to be recognized over a weighted-average period of 1.4 years. During the three months ended March 31, 2016, 189,700 shares vested, with no payout as they were out of the money. The weighted average grant date fair value for the restricted stock units granted during the three months ended March 31, 2015 was $1.98 per unit.

The following table represents restricted stock unit activity for the three months ended March 31, 2016:



	Shares		Wtd. Avg. Grant Price
Restricted stock units outstanding, beginning of period	591,400		$	9.20
Restricted stock units granted	—		$	—
Restricted stock units canceled	—		$	—
Restricted stock units vested	(189,700	)	$	15.01
Restricted stock units outstanding, end of period	401,700		$	6.45

Cash-Settled Restricted Stock Units (Liability Awards)

During the three months ended March 31, 2015, the Company granted 147,812 units of cash-settled restricted stock units. These grants originally required a cash payout based on the fair value of the stock price on the date of the next Annual Shareholder Meeting, which was originally expected to be held during May of 2016. The grants had cliff vesting period of approximately 1.0 year while the compensation expense and corresponding liability are remeasured quarterly over the corresponding service period. The Company recorded a liability of less than $0.1 million for these awards in "Accounts Payable and accrued liabilities” on the accompanying condensed consolidated balance sheet as of March 31, 2016. Upon the Company's emergence from bankruptcy on April 22, 2016, these outstanding awards were canceled.

(4) Earnings Per Share

Upon the Company's emergence from bankruptcy on April 22, 2016, as discussed in Note 1A, the Company’s then current common stock was canceled and new common stock and warrants were issued. The earnings per share amounts disclosed below would have been materially different if the emergence from bankruptcy had occurred before the end of the current period.

The Company computes earnings per share in accordance with FASB ASC 260-10. Basic earnings per share (“Basic EPS”) has been computed using the weighted average number of common shares outstanding during each period. Diluted earnings

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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 three months ended March 31, 2016, the unvested share-based payments and stock options were not recognized in diluted earnings per share (“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 three months ended March 31, 2015, and are discussed below.

The following is a reconciliation of the numerators and denominators used in the calculation of Basic and Diluted EPS for the three months ended March 31, 2016 and 2015 (in thousands, except per share amounts):



	Three Months Ended March 31, 2016							Three Months Ended March 31, 2015
	Net Income (Loss)			Shares	Per Share Amount			Net Income (Loss)			Shares	Per Share Amount
Basic EPS:
Net Income (Loss) and Share Amounts	$	(108,303	)	44,672	$	(2.42	)	$	(477,077	)	44,232	$	(10.79	)
Dilutive Securities:
Restricted Stock Awards				—							—
Restricted Stock Units				—							—
Diluted EPS:
Net Income (Loss) and Assumed Share Conversions	$	(108,303	)	44,672	$	(2.42	)	$	(477,077	)	44,232	$	(10.79	)

Approximately 1.3 million stock options to purchase shares were not included in the computation of Diluted EPS for the three months ended March 31, 2016 and 2015, respectively, because they were antidilutive.

Approximately 0.3 million and 0.7 million restricted stock awards for the three months ended March 31, 2016 and 2015, respectively, were not included in the computation of Diluted EPS because they were antidilutive given the net loss.

Approximately 0.8 million and 1.2 million shares for the three months ended March 31, 2016 and 2015, respectively, related to performance-based restricted stock units that could be converted to common shares based on predetermined performance and market goals were not included in the computation of Diluted EPS because the performance and market conditions had not been met, assuming the end of the reporting period was the end of the performance period.

(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 existing debt obligations. As a result, the Company's pre-petition unsecured senior notes and secured debt under the Existing First Lien Credit Agreement 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 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 March 31, 2016 and December 31, 2015, were as follows (in thousands):



	March 31, 2016			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	339,900			324,900
Total Debt	$	339,900		$	324,900
Less: Current portion of long-term debt ⁽²⁾	$	(339,900	)	$	(324,900	)
Long-Term Debt	$	—		$	—
(1) Classified as Liabilities subject to compromise as of March 31, 2016 and December 31, 2015.
(2) As a result of our Chapter 11 filing, we have classified our Existing First Lien Credit Agreement borrowings and DIP Credit Agreement borrowings as current as of March 31, 2016 and 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 March 31, 2016 and December 31, 2015.

Reclassification of Existing First Lien Credit Agreement Liabilities. Amounts outstanding under our pre-petition Existing First Lien Credit Agreement due in 2017 of $324.9 million were reclassified as a current liability in the condensed consolidated balance sheet dated as of March 31, 2016 and December 31, 2015 due to cross-default provisions as a result of the bankruptcy filings. The associated remaining unamortized debt issuance costs of $2.4 million on the Existing First Lien Credit Agreement were written-off in "Interest expense, net" on the Company's condensed consolidated statement of operations as of March 31, 2016.

Debtor-In-Possession Financing. As part of the Chapter 11 filings, we entered into the DIP Credit Agreement. As of March 31, 2016, the total amount available for borrowing under our DIP Credit Agreement was $30.0 million, of which $15.0 million was outstanding. The remaining $45.0 million under the DIP Credit Agreement became available to the Company upon emergence from bankruptcy. The proceeds of the DIP Credit Agreement were primarily used to pay down the pre-petition Existing First Lien Credit Agreement 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 of reorganization, 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 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 during the first quarter of 2016. We were also required to pay to each Backstop Lender (as defined in the DIP Credit Agreement) a non-refundable backstop fee of 7.5% on the pro rata share of such Backstop Lender’s share of the loan commitments, payable in the form of common stock issued by the Company upon emergence from the Chapter 11 cases. An original issue discount of 5% was paid by the Company at the time of any drawdowns against the DIP Credit Agreement, resulting in net proceeds to the Company of 95% of the gross drawdown amount.

The DIP Credit Agreement was secured by security interests in substantially all of the Company’s assets, which were (1) second priority to the existing pre-petition liens of the lenders and JPMorgan Chase Bank, N.A., as administrative agent with respect to the collateral (generally required to be at least 95% of our oil and gas properties) set forth in the Second Amended and Restated Credit Agreement, dated as of September 21, 2010 (the “Existing First Lien Credit Agreement”), and (2) first priority with respect to all other property of the Company. These security interests were subject to certain carve-outs (such as bankruptcy court costs and professional fees), and permitted liens under the DIP Credit Agreement. The DIP Credit Agreement was subject to customary covenants, prepayment events, events of default and other provisions.

Interest expense on the DIP Credit Agreement totaled $1.9 million during the three months ended March 31, 2016.

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Bank Borrowings. Effective November 2, 2015, we executed an amendment to our Existing First Lien Credit Agreement lowering our borrowing base and commitment amount from $375.0 million to $330.0 million.

We had $324.9 million in outstanding borrowings under our Existing First Lien Credit Agreement at March 31, 2016 and December 31, 2015, respectively. As of March 31, 2016, the interest rate on our Existing First Lien Credit Agreement 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. At March 31, 2016, the lead bank's prime rate was 3.5%. The commitment fee terms associated with the Existing First Lien Credit Agreement were 0.50% for the three months ended March 31, 2016. During the bankruptcy proceedings we paid interest on our Existing First Lien Credit Agreement in the normal course.

Interest expense on the Existing First Lien Credit Agreement, including commitment fees and amortization of debt issuance costs, totaled $6.1 million and $1.7 million for the three months ended March 31, 2016 and 2015, respectively. The amount of commitment fees included in interest expense, net was immaterial for the three months ended March 31, 2016 and $0.2 million for the three months ended March 31, 2015.

Additionally, we capitalized interest on our unproved properties in the amount $1.2 million for the three months ended March 31, 2015. We did not capitalize interest on our unproved properties for the three months ended March 31, 2016.

Due to the bankruptcy proceedings, most acts to exercise remedies under our Existing First Lien Credit Agreement, including those related to defaults of various financial covenants and ratios, were stayed as of December 31, 2015 and continued to be stayed during the bankruptcy proceedings. No further funds were available to us under the Existing First Lien Credit Agreement. The terms of our Existing First Lien Credit Agreement included, among other restrictions, a limitation on the level of cash dividends (not to exceed $15.0 million in any fiscal year), a remaining aggregate limitation on purchases of our stock of $50.0 million, and limitations on incurring other debt.

At March 31, 2016, our Existing First Lien Credit Agreement contained financial covenants detailing certain minimum financial ratios that must be maintained. The first was an adjusted working capital ratio of adjusted current assets to current liabilities (as defined in the Existing First Lien Credit Agreement) of not less than 0.5 to 1.0 for each of the quarters up to and ending on December 31, 2016, returning to a ratio of not less than 1.0 to 1.0 at any time thereafter. The second ratio was the interest coverage ratio, calculated on a trailing twelve month basis of EBITDAX to interest expense (as defined in the Existing First Lien Credit Agreement), of not less than 1.15 to 1.0 for the quarters ending on December 31, 2015 through June 30, 2016, 1.3 to 1.0 for the quarters ending September 30, 2016 through December 31, 2016, and 2.0 to 1.0 any time thereafter. The third ratio was the senior secured leverage ratio (as defined in the Existing First Lien Credit Agreement), requiring that the ratio of senior secured liabilities on the last day of the quarter to EBITDAX, calculated on a trailing twelve month basis, not be greater than 3.5 to 1.0 for the quarters ending December 31, 2015 through June 30, 2016, 3.0 to 1.0 for the quarters ending September 30, 2016 through December 31, 2016, and 2.5 to 1.0 any time thereafter.

Since inception, no cash dividends have been declared on our common stock. As of March 31, 2016, the terms of the Existing First Lien Credit Agreement required us to secure the facility with collateral equal to at least 95% of our oil and natural gas properties. Under the terms of the Existing First Lien Credit Agreement, the commitment amount can be less than or equal to the total amount of the borrowing base with unanimous consent of the bank group as it might change from time to time.

New Credit Facility. As discussed in Note 1A of these condensed consolidated financial statements, on the Effective Date, April 22, 2016, the Existing First Lien Credit Agreement 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 three years after the Effective Date 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 being secured, subject to certain exceptions, by a first priority lien on substantially all assets of the Company and certain of its subsidiaries. The terms of the New Credit Facility also include the following, based on terms as defined in the New Credit Facility agreement:


•	A non-conforming borrowing base of $70 million, which terminates on November 1, 2017, and a conforming borrowing base of $250 million.

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

•

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


•	Certain covenants, including (a) a ratio of total debt to EBITDA (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), 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.

Senior Notes Due In 2022. These notes consisted of $400.0 million of 7.875% senior notes due 2022 that were scheduled to mature on March 1, 2022. On November 30, 2011, we issued $250.0 million of these senior notes at a discount of $2.1 million or 99.156% of par, which equated to an effective yield to maturity of 8%. On October 3, 2012, we issued an additional $150.0 million of these senior notes at 105% of par, which equated to a yield to worst of 6.993%. As of March 31, 2016, these senior notes were senior unsecured obligations that ranked equally with all of our existing and future senior unsecured indebtedness, were effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank Existing First Lien Credit Agreement, and ranked senior to any future subordinated indebtedness of Swift Energy. Interest on these notes was payable semi-annually on March 1 and September 1 and commenced on March 1, 2012. 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.

Senior Notes Due In 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 notes were issued on November 25, 2009 with an original discount of $3.6 million and were scheduled to mature on January 15, 2020. As of March 31, 2016, these senior notes were senior unsecured obligations that ranked equally with all of our existing and future senior unsecured indebtedness, were effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank Existing First Lien Credit Agreement, and ranked senior to any future subordinated indebtedness of Swift Energy. Interest on these notes was payable semi-annually on January 15 and July 15 and commenced on January 15, 2010. 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.

Senior Notes Due In 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. As of March 31, 2016, the notes were senior unsecured obligations that ranked equally with all of our existing and future senior unsecured indebtedness, were effectively subordinated to all our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowing under our bank Existing First Lien Credit Agreement, and ranked senior to any future subordinated indebtedness of Swift Energy. Interest on these notes was payable semi-annually on June 1 and December 1, and commenced on December 1, 2007. Prior to the Chapter 11 filing, the Company elected not to make the $8.9 million semi-annual interest payment due December 1, 2015, on its outstanding $250.0 million principal amount of 7.125% Senior Notes due 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.

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.

In April 2015, the FASB issued ASU 2015-03, which requires debt issuance costs related to our debt to be presented on the balance sheet as a reduction of the carrying amount of the long-term debt. We implemented this guidance during the first quarter of 2016 on a retrospective basis, with no material impact to our financial statements as of March 31, 2016, and December 31, 2015, respectively, since we wrote off the debt issuance costs related to our senior notes as of December 31, 2015, as a result of our bankruptcy proceedings. In August 2015, the FASB issued ASU 2015-15, which allows for debt issuance costs related to line

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of credit arrangements to continue to be presented as assets, regardless of whether there are any outstanding borrowings. Debt issuance costs related to line of credit arrangements continue to be presented as an asset on our condensed consolidated balance sheets.

Interest Expense on Senior Notes. There was no interest expense on the senior notes, for the three months ended March 31, 2016 due to our bankruptcy proceedings. Interest expense on the senior notes totaled $17.7 million for the three months ended March 31, 2015

(6) Acquisitions and Dispositions

On April 15, 2016, we closed our transaction with Texegy LLC for the sale a working interest share of the Company's holdings in the South Bearhead Creek and Burr Ferry field areas located in Central Louisiana. Refer to Note 2 of these condensed consolidated financial statements for more information.

There were no material acquisitions or dispositions in the three months ended March 31, 2016 or 2015.

(7) Price-Risk Management Activities

The Company follows FASB ASC 815-10, which requires that changes in the derivative’s fair value are recognized in earnings. The changes in the fair value of our derivatives are recognized in "Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. We have a price-risk management policy to use derivative instruments to protect against declines in oil and natural gas prices, mainly through the purchase of price swaps, floors, calls, collars and participating collars.

During the three months ended March 31, 2016 there were no gains or losses, while during the three months ended March 31, 2015 there was a net gain of $0.3 million, related to our derivative activities. The effects of our derivatives are included in the "Other" section of our operating activities on the accompanying condensed consolidated statements of cash flows.

The fair values of our derivatives are computed using commonly accepted industry-standard models and are periodically verified against quotes from brokers. There were no unsettled derivative assets and no unsettled derivative liabilities as of March 31, 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. All our outstanding hedge agreements had settled as of March 31, 2016, under the right of set-off, there was no net fair value at March 31, 2016. For further discussion related to the fair value of the Company's derivatives, refer to Note 8 of these condensed consolidated financial statements.

(8) Fair Value Measurements

FASB ASC 820-10 defines fair value, establishes guidelines for measuring fair value and expands disclosure about fair value measurements. Our financial instruments consist of cash and cash equivalents, restricted cash, accounts receivable, accounts payable, bank borrowings, and senior notes. The carrying amounts of cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

Based upon quoted market prices as of March 31, 2016 and December 31, 2015, the fair value and carrying value of our senior notes was as follows (in millions):



	March 31, 2016				December 31, 2015
	Fair Value		Carrying Value		Fair Value		Carrying Value
7.125% senior notes due 2017	$	13.4	$	250.0	$	23.0	$	250.0
8.875% senior notes due 2020 ⁽¹⁾	$	9.9	$	225.0	$	21.4	$	225.0
7.875% senior notes due 2022 ⁽¹⁾	$	20.9	$	400.0	$	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 are stated at carrying value on our accompanying condensed consolidated balance sheets. If we recorded these notes at fair value they would be Level 1 in our fair value hierarchy as they are traded in an active market with quoted prices for identical instruments.

As of March 31, 2016 and December 31, 2015 all of the Company's hedging agreements had settled.

(9) Asset Retirement Obligations

We record these obligations in accordance with the guidance contained in FASB ASC 410-20. This guidance requires entities to record the fair value of liabilities for legal obligations associated with the retirement obligations of tangible long-lived assets 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.

The following provides a roll-forward of our asset retirement obligations (in thousands):



	2016
Asset Retirement Obligations recorded as of January 1	$	63,555
Accretion expense	1,291
Liabilities incurred for new wells and facilities construction	—
Reductions due to sold and abandoned wells and facilities	(1		)
Revisions in estimates	488
Asset Retirement Obligations as of March 31	$	65,333

At March 31, 2016 and December 31, 2015, approximately $7.7 million and $7.2 million of our asset retirement obligations were classified as a current liability in “Accounts payable and accrued liabilities” on the accompanying condensed consolidated balance sheets.

(10) Condensed Consolidating Financial Information

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

The Chapter 11 bankruptcy proceedings, as discussed in Note 1A of the consolidated financial statements, include all of our domestic subsidiaries but do not include our international subsidiaries, which are 100% owned by our domestic subsidiary Swift Energy International, Inc. These international subsidiaries primarily consist of our New Zealand subsidiaries, which liquidated their assets in 2007 and 2008. These subsidiaries have had no activity since 2008, except for the recognition of gains in 2011 upon the settlement of legal claims related to the 2007 and 2008 divestitures, and have no debt obligations. We do not have any material intercompany balances between our entities in bankruptcy proceedings and our entities not in bankruptcy proceedings.

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Intercompany balances for our entities in bankruptcy proceedings, which have been eliminated within our consolidated balance sheets, include payables due from Swift Energy Operating, LLC to Swift Energy Company (the parent) in the amount of $416.4 million and to Swift Energy International, Inc. in the amount of $85.4 million, and receivables due to Swift Energy Operating, LLC from Swift Energy Alaska, Inc. in the amount of approximately $6.1 million and from Swift Energy Exploration Services, Inc. in the amount of $0.1 million.

(11) 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. As of March 31, 2016, most of our pending legal proceedings have been stayed by virtue of our voluntary petition filed on December 31, 2015 seeking relief under Chapter 11 of the Bankruptcy Code.

As noted in Note 1A and Note 5, during the bankruptcy proceedings we obtained financing through the DIP Credit Agreement, from which we had outstanding borrowings of $15.0 million as of March 31, 2016.

We had no other material changes from amounts referenced under Note 5 in our Notes to consolidated financial statements from our Annual Report on Form 10-K for the year ending December 31, 2015.

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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 31 of this report.

Company Overview

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 69% of our first quarter of 2016 production and 53% of our oil and gas sales while oil constituted 18% of our first quarter of 2016 production and 37% of our oil and gas sales.

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 on March 31, 2016, and subsequently emerged from bankruptcy on April 22, 2016. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession for the entire quarter ended March 31, 2016. As such, certain aspects of the bankruptcy proceedings of the Company and related matters are described below in order to provide context and explain part of our financial condition and results of operations for the period presented.

Plan of Reorganization. Pursuant to the plan of reorganization that the bankruptcy court confirmed, 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 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 under and more fully described below) received a backstop fee consisting of 7.5% of the post-emergence Company’s common stock;


•	the Company drew down the entire $75 million available under the DIP Credit Agreement, and the DIP Credit Agreement was converted into the Company’s post-emergence common stock;


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


•	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 that, 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 proceedings of approximately $46.9 million including deposits received prior to the closing date; and


•	the Company's previous credit facility (the "Existing First Lien Credit Facility") was terminated and a new $320 million senior secured credit facility (the “New Credit Facility”) was established, as discussed in more detail in Note 5 of the accompanying condensed consolidated financial statements.

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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 of reorganization, 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 current holders of the senior notes and certain unsecured creditors. As such, 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. For more information refer to Note 5 of the accompanying condensed consolidated financial statements.

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Significant Developments During Our First Quarter of 2016

•

Weak crude oil and natural gas prices continues to affect our business: Oil and gas prices continued to decline in the first quarter of 2016 compared to 2015 prices. While the markets have shown recent improvements, prices for all products 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 continue to decline 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 quarter 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 we are reconfiguring our gathering system 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 and are taking additional steps to further reduce overhead costs.


•	Strategic Dispositions: In addition to the recently announced sale of assets in Central Louisiana, we are continuing to evaluate dispositions of properties outside of our core Eagleford assets base.

•

Operational Activity: During the first quarter, four new wells were brought online in the South AWP area. These wells, the Bracken 19H, 20H, 23H and 24H were tested at rates ranging from approximately 21 - 26 MMcF per day of natural gas with approximately 1,200 to 1,500 barrels per day of condensate and natural gas liquids. After testing, these wells were placed on restricted chokes and we are monitoring well performance to evaluate the long-term benefits of a restricted choke management program. While we are still in the early evaluation phase of these wells, we are pleased with the results and it appears that restricted chokes on wells in this area will provide optimal recoveries and economic performance. During the month of April, four new wells were brought online in the Fasken area. These wells, the Fasken State 48H, 49H, 50H and 51H were placed into the system at rates ranging from approximately 15 -20 MMcf per day of natural gas. We are also currently completing four additional wells in the Fasken field that are scheduled to come online in June of 2016. These wells will be the last wells completed in the Fasken field this year and should be sufficient to keep our productive capacity at or near our throughput capacity of 190 MMcf per day at the Fasken field.

•

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 or quoted on any over-the-counter market. The Company can provide no assurance that the newly issued common stock of the reorganized entity will trade on a nationally recognized market or an over-the-counter market, whether broker-dealers will provide public quotes of the reorganized Company’s common stock on an over-the-counter market, whether the trading volume on an over-the-counter market of the Company’s common stock will be sufficient to provide for an efficient trading market or whether quotes for the Company’s common stock may be blocked by OTC Markets Group in the future.

•

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 Existing First Lien Credit Facility, converted the DIP Credit Agreement into post-emergence common stock and entered the New Credit Agreement.

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Summary of 2016 Financial Results

•

First quarter 2016 revenues and net loss: Our first quarter oil and gas revenues decreased 49%, or $33.0 million, when compared to first quarter of 2015 revenues, primarily due to overall lower commodity pricing as well as lower oil and natural gas production. Our net loss of $108.3 million for the first quarter of 2016 is primarily due to decreased commodity pricing and production along with the $77.7 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 $36.6 million in the first three months of 2016, compared to $49.2 million in the first three months of 2015. The expenditures during the current period, which were $24.4 million on an accrual basis, 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 $15.0 million of net borrowings under our DIP Credit Agreement along with operating cash flows.

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. Based on this limited budget and current expectations, we expect production levels for 2016 to be either unchanged or lower than 2015 production levels. We have the flexibility to add additional projects if market conditions improve.


•	Net cash provided by operating activities: For the first three months of 2016, our net cash provided by operating activities was $5.0 million, representing a $5.8 million increase, compared to $(0.8) million generated during the same period of 2015, primarily due to the impact of decreased revenues which were partially offset by working capital changes.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash flows from operations, borrowings under our Existing 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. We summarize below net cash provided by operating activities for the first three months of 2016, our entry into the New Credit Facility and 2016 capital expenditures. For the quarterly period ended March 31, 2016, the Company’s liquidity consisted of approximately $18 million of cash-on-hand, plus $15 million of availability under the DIP Credit Agreement financing provided by certain of the Company’s senior note holders. As of March 31, 2016, we had approximately $324.9 million in outstanding borrowings under our Existing First Lien Credit Agreement (excluding $5.1 million in letters of credit), with no availability for further borrowings under the facility.

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 Existing First Lien Credit Agreement prior to emergence from bankruptcy, with the remainder used for other corporate purposes.

Debtor-In-Possession Financing. As summarized in the "Chapter 11 Proceedings" section above, the DIP Credit Agreement provided for a multi-draw term loan of up to $75 million, of which we had borrowed $15 million out of the $30 million available to us as of March 31, 2016. In early April and in conjunction with our emergence from bankruptcy, the remaining undrawn amount available was drawn down with most of the borrowings being used by the Company to pay down the Existing First Lien Credit Agreement.

New Credit Facility and Existing First Lien Credit Agreement. On our emergence from bankruptcy, the Existing 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. As of April 29, 2016, we had approximately $253 million (excluding $5.1 million in letters of credit) in outstanding borrowings under the New Credit Facility. The terms of the New Credit Facility are summarized in Note 5 of the accompanying consolidated financial statements. We expect to be in compliance with the covenants under this agreement during the next twelve months.

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2016 Capital Budget. The Company’s current capital budget for 2016 is significantly reduced from 2015 levels, and includes completion costs for 12 previously drilled but not completed South Texas Eagle Ford wells, the drilling but not completion of 4 additional South Texas Eagle Ford wells, 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.

Contractual Commitments and Obligations

As noted in Note 1A and Note 5 on the accompanying condensed consolidated financial statements, during the bankruptcy proceedings we obtained financing through a DIP Credit Agreement, from which we had outstanding borrowings of $15.0 million at March 31, 2016.

We had no other material changes in our contractual commitments and obligations from amounts referenced under “Contractual Commitments and Obligations” in Management's Discussion and Analysis in our Annual Report on Form 10-K for the year ending December 31, 2015.

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Results of Operations

Revenues — Three Months Ended March 31, 2016 and 2015

Our oil and gas sales in the first quarter of 2016 decreased by 49% compared to oil and gas sales in the first quarter of 2015, primarily due to overall lower commodity pricing as well as overall lower volumes. Average oil prices we received were 33% lower than those received during the first quarter of 2015, while natural gas prices were 28% lower and NGL prices were 33% lower.

Crude oil production was 18% and 22% of our production volumes in the first quarters of 2016 and 2015, respectively. Crude oil sales were 37% and 46% of oil and gas sales in the first quarters of 2016 and 2015, respectively. Natural gas production was 69% and 64% of our production volumes in the first quarters of 2016 and 2015, respectively. Natural gas sales were 53% and 44% of oil and gas sales in the first quarters of 2016 and 2015, respectively. The remaining production and sales in each period came from NGLs.

The following table provides additional information regarding our oil and gas sales, excluding any effects of our hedging activities, for the three months ended March 31, 2016 and 2015:



Core Regions	Oil and Gas Sales (In Millions)				Net Oil and Gas Production Volumes (MBoe)
	2016		2015		2016	2015
Artesia Wells	$	2.8	$	5.5	224	306
AWP	11.3		26.9		806	1,224
Fasken	11.9		16.6		1,005	1,014
Other South Texas	0.7		1.0		49	55
Total South Texas	26.7		50.0		2,084	2,599

Southeast Louisiana	5.6		12.1		203	293

Central Louisiana	2.0		5.0		101	161

Other	0.1		0.3		6	11

Total	$	34.4	$	67.4	2,394	3,064

Our production decrease from 2015 to 2016 was primarily due to a decrease in oil production from our AWP and Lake Washington fields, while the decrease in NGL and natural gas production both came from our AWP and Artesia fields.

In the first quarter of 2016, our $33.0 million, or 49% decrease in oil, NGL, and natural gas sales from the prior year period resulted from:


•	Price variances that had an approximate $15.0 million unfavorable impact on sales due to overall lower commodity pricing; and


•	Volume variances that had an $18.0 million unfavorable impact on sales due to overall lower volumes.

The following table provides additional information regarding our quarterly oil and gas sales, excluding any effects of our hedging activities, for the three months ended March 31, 2016 and 2015:



	Production Volume				Average Price
	Oil (MBbl)	NGL (MBbl)	Gas (Bcf)	Combined (MBoe)	Oil (Bbl)		NGL (Bbl)		Natural Gas (Mcf)
Three Months Ended March 31, 2016	427	310	9.9	2,394	$	30.07	$	10.83	$	1.83
Three Months Ended March 31, 2015	685	426	11.7	3,064	$	45.10	$	16.09	$	2.53

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For the three months ended March 31, 2016, there were no net gains or losses from hedging activities as all hedges had settled as of December 31, 2015. For the three months ended March 31, 2015 we recorded and a net gain of $0.3 million related to our derivative activities. This activity is recorded in “Price-risk management and other, net” on the accompanying condensed consolidated statements of operations. Had these amounts been recognized in the oil and gas sales account, our average oil price and natural gas price would have been $45.10 and $2.56, respectively, for the first quarter of 2015.

Costs and Expenses — Three Months Ended March 31, 2016 and 2015

Our expenses in the first quarter of 2016 decreased $482.3 million, compared to those in the first quarter of 2015, for the reasons noted below.

Lease operating cost. These expenses decreased $6.7 million, or 35%, compared to the level of such expenses in the first quarter of 2015. The decrease was primarily due to a concentrated effort to reduce costs during the year and included a decrease in supervision fees (i.e. overhead rates) charged to LOE, lower chemical costs, lower salt water disposal costs, lower utility, fuel and power costs, lower maintenance costs and lower labor costs. Our lease operating costs per Boe produced were $5.14 and $6.21 for the three months ended March 31, 2016 and 2015, respectively.

Transportation and gas processing. These expenses decreased $0.3 million, or 5% compared to the level of such expenses in the first quarter of 2015. Our transportation and gas processing costs per Boe produced were $2.11 and $1.74 for the first quarters of 2016 and 2015, respectively.

Depreciation, Depletion and Amortization (“DD&A”). These expenses decreased $43.5 million, or 72% from those in the first quarter of 2015. The decrease was primarily due to a lower depletable base, partially offset by lower reserves volumes. Our DD&A rate per Boe of production was $7.20 and $19.81 in the first quarters of 2016 and 2015, respectively.

General and Administrative Expenses, Net. These expenses decreased $4.4 million, or 35%, from the level of such expenses in the first quarter of 2015. The decrease was primarily due to lower salaries and burdens, lower legal and professional fees and lower office rent, partially offset by lower capitalized amounts. Our net general and administrative expenses per Boe produced decreased to $3.39 per Boe in the first quarter of 2016 from $4.10 per Boe in the first quarter of 2015.

Severance and Other Taxes. These expenses decreased $2.8 million, or 55%, from first quarter of 2015 levels while oil and gas revenues decreased 49% and equivalent production volumes decreased 22%. The decrease in severance taxes, excluding ad valorem taxes, was primarily driven by lower revenues. Severance and other taxes, as a percentage of oil and gas sales, were approximately 6.8% and 7.6% in the first quarters of 2016 and 2015, respectively.

Interest. Our gross interest cost in the first quarters of 2016 and 2015 was $8.1 million and $19.4 million, 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, partially offset by interest expense related to the DIP Credit Agreement.

Write-down of oil and gas properties. Principally due to the effects of pricing, and also due to the timing of projects and changes in our reserves product mix, we recorded a non-cash write-down on a before-tax basis of $77.7 million in the first quarter of 2016 and $502.6 million in the first quarter of 2015.

Reorganization Items. We incurred $10.4 million in expenses in the first quarter of 2016 primarily due to professional and legal fees incurred as a result of our bankruptcy proceedings, partially offset by gains recognized as pre-petition liabilities were settled or adjusted during the bankruptcy process. There were no reorganization expenses in the first quarter of 2015.

Income Taxes. There was no benefit for income taxes in the first quarter of 2016. The benefit for income taxes in the first quarter of 2015 was $79.5 million. The benefit recognized during the first quarter of 2015 was due to the write-down of oil and gas properties due to the decline in overall commodity prices but was limited to the net liability at the beginning of the period. Our effective income tax rate was 14.3% for the first quarter of 2015.

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Critical Accounting Policies and New Accounting Pronouncements

Property and Equipment. We follow the “full-cost” method of accounting for oil and natural gas property and equipment costs. Under this method of accounting, all productive and nonproductive costs incurred in the exploration, development, and acquisition of oil and natural gas reserves are capitalized including internal costs incurred that are directly related to these activities and which are not related to production, general corporate overhead, or similar activities. Future development costs are estimated on a property-by-property basis based on current economic conditions and are amortized to expense as our capitalized oil and natural gas property costs are amortized. We compute the provision for depreciation, depletion, and amortization (“DD&A”) of oil and natural gas properties using the unit-of-production method.

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

The calculation of the provision for DD&A requires us to use estimates related to quantities of proved oil and natural gas reserves and estimates of unproved properties. 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, and excluding the recognized asset retirement obligation liability) is limited to the sum of the estimated future net revenues from proved properties (excluding cash outflows from recognized asset retirement obligations, including future development and abandonment costs of wells to be drilled, using the preceding 12-months’ average price based on closing prices on the first day of each month, adjusted for price differentials, discounted at 10%, and the lower of cost or fair value of unproved properties) adjusted for related income tax effects ("Ceiling Test").

Principally due to the effects of pricing, and also due to the timing of projects and changes in our reserves product mix, we reported a non-cash write-down on a before-tax basis of $77.7 million and $502.6 million on our oil and natural gas properties for the three months ended March 31, 2016 and 2015, respectively.

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.

New Accounting Pronouncements. In May 2014, the FASB issued ASU 2014-09, which provides a single, comprehensive revenue recognition model for all contracts with customers across various industries. The guidance is effective for annual and interim reporting periods beginning after until December 15, 2017. We are currently reviewing the new requirements to determine the impact of this guidance on our financial statements.

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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. We do not expect this new guidance to have a material impact on our financial statements.

In February 2016, the FASB issued ASU 2016-02, which requires lessees to record most leases on the balance sheet, while expense recognition on the income statement remains similar to current lease accounting guidance. 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.

Forward-Looking Statements

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

Forward-looking statements may include statements about our:

• 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;

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• 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 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 Existing 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. Our senior notes due in 2017, 2020 and 2022 had fixed interest rates, so consequently we were not exposed to cash flow risk from market interest rate changes on these notes. At March 31, 2016, we had $324.9 million drawn under our Existing First Lien Credit Agreement and $15 million under our DIP Credit Agreement, which had a floating rate of interest and therefore was susceptible to interest rate fluctuations. The result of a 10% fluctuation in the bank’s base rate would constitute 35 basis points for borrowings under the Existing First Lien Credit Agreement, and would constitute 124 basis points under the DIP Credit Agreement, either of which would have had a material adverse effect on our future cash flows.

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

Internal Control Over Financial Reporting

There was no change in our internal control over financial reporting during the first three months of 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.

During the first quarter of 2016, there have been no material changes in our risk factors disclosed in the 2015 Annual Report Form 10-K for the year ended December 31, 2015, except for the following:

Risks Related to our Emergence from Chapter 11 Bankruptcy

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, employees and suppliers. Due to uncertainties, many risks exist, including the following:


•	key suppliers could terminate their relationship or require financial assurances or enhanced performance;


•	the ability to renew existing contracts and compete for new business may be adversely affected;


•	the ability to attract, motivate and/or retain key executives and employees may be adversely affected;


•	employees may be distracted from performance of their duties or more easily attracted to other employment opportunities; and


•	competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the plan of reorganization and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the bankruptcy court, and the hearing to consider confirmation of the plan of reorganization, we prepared projected financial information to demonstrate to the bankruptcy court the feasibility of the plan of reorganization and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance and with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results will likely vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

In addition, upon our emergence from bankruptcy, we will adopt fresh start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

There is a limited trading market for our securities and the market price of our securities is subject to volatility.

Upon our emergence from bankruptcy, our old common stock was cancelled and we issued new common stock. Our common stock is not listed on any national or regional securities exchange or quoted on any over-the-counter market. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control. These factors include, among other things, our new capital structure as a result of the transactions contemplated by the plan of reorganization, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the concentration of holdings of our common stock, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated

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variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part II, Item 1A of this Report. No assurance can be given that an active market will develop for the common stock or as to the liquidity of the trading market for the common stock. The common stock may be traded only infrequently in transactions arranged through brokers or otherwise, and reliable market quotations may not be available. Holders of our common stock may experience difficulty in reselling, or an inability to sell, their shares. In addition, if an active trading market does not develop or is not maintained, significant sales of our common stock, or the expectation of these sales, could materially and adversely affect the market price of our common stock.

The Company intends to be quoted on one of the over-the-counter markets in anticipation of later joining a national exchange. However, no assurances can be given regarding the Company’s ability to do so in a timely manner or at all.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the plan of reorganization, the composition of the Board changed significantly. Upon emergence, the Board is now made up of seven directors, with the new non-executive chairman of the Board to be designated, of which six will not have previously served on the Board. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Funds associated with SVP and DW Partners, LP (“DW”) currently own approximately 37% and 14%, respectively, of our outstanding common stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in us or another company in which they invest. Such transactions might adversely affect us or other holders of our common stock. Furthermore, we have entered into a director nomination agreement with each of SVP, DW and other former holders of our senior notes that provides for certain continuing nomination rights subject to conditions on share ownership. In addition, our significant concentration of share ownership may adversely affect the trading price of our common shares because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We do not expect to pay dividends in the near future.

We do not anticipate that cash dividends or other distributions will be paid with respect to our common stock in the foreseeable future. In addition, restrictive covenants in certain debt instruments to which we are, or may be, a party, may limit our ability to pay dividends or for us to receive dividends from our operating companies, any of which may negatively impact the trading price of our common stock.

Certain provisions of our certificate of incorporation and our bylaws may make it difficult for stockholders to change the composition of our Board and may discourage, delay or prevent a merger or acquisition that some stockholders may consider beneficial.

Certain provisions of our Certificate of Incorporation (the “Charter”) and our Bylaws may have the effect of delaying or preventing changes in control if our Board determines that such changes in control are not in the best interests of the Company and our stockholders. The provisions in our Charter and Bylaws include, among other things, those that:


•	provide for a classified board of directors;

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•	authorize our Board to issue preferred stock and to determine the price and other terms, including preferences and voting rights, of those shares without stockholder approval;


•	establish advance notice procedures for nominating directors or presenting matters at stockholder meetings; and


•	limit the persons who may call special meetings of stockholders.

While these provisions have the effect of encouraging persons seeking to acquire control of the Company to negotiate with our Board, they could enable the Board to hinder or frustrate a transaction that some, or a majority, of the stockholders may believe to be in their best interests and, in that case, may prevent or discourage attempts to remove and replace incumbent directors. These provisions may frustrate or prevent any attempts by our stockholders to replace or remove our current management by making it more difficult for stockholders to replace members of our Board, which is responsible for appointing the members of our management.

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

The following table summarizes repurchases of our common stock occurring during the first quarter of 2016:



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)
January 1 – 31, 2016 ⁽¹⁾	1,472	$	0.14	—	$	—
February 1 – 29, 2016 ⁽¹⁾	59,615	$	0.06	—	—
March 1 – 31, 2016 ⁽¹⁾	2,124	$	0.09	—	—
Total	63,211	$	0.06	—	$	—
(1) These shares were withheld from employees to satisfy tax obligations arising upon the vesting of restricted shares.

Item 3. Defaults Upon Senior Securities.

The filing of the voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code constituted an event of default that accelerated the Company’s obligations under the following debt instruments:


•	indenture governing $250,000,000 in outstanding aggregate principal amount of 7.125% senior notes due 2017, dated as of May 16, 2007, between the Company and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, as supplemented by that certain Supplemental Indenture, dated as of June 1, 2007;


•	indenture governing $225,000,000 in outstanding aggregate principal amount of 8.875% senior notes due 2020, dated as of May 19, 2009, between the Company and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, as supplemented by that certain First Supplemental Indenture, dated as of November 25, 2009; and


•	indenture governing $250,000,000 in outstanding aggregate principal amount of 7.875% senior notes due 2022, dated as of May 19, 2009, between the Company and Wilmington Trust, National Association, as successor to Wells Fargo Bank, National Association, as supplemented by that certain Second Supplemental Indenture, dated as of November 30, 2011.

As previously disclosed, 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. On April 22, 2016, the obligation of the Company and the Chapter 11 Subsidiaries with respect to these notes were cancelled.

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. 1-08754).
10.1	Restructuring Support Agreement dated December 31, 2015 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed January 4, 2016, File No. 1-08754).
10.2	Debtor-In-Possession Credit Agreement dated December 31, 2015 (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Form 8-K filed January 4, 2016, File No. 1-08754).
10.3	Debtor-In-Possession Credit Agreement dated January 6, 2016 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed January 11, 2016, File No. 1-08754).
99.1	Syndication Procedures dated January 11, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed January 11, 2016, File No. 1-08754).
99.2	Syndication Procedures dated March 10, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 15, 2016, File No. 1-08754).
99.3	Notice of Syndication Procedures Deadline Extension dated March 18, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 21, 2016, File No. 1-08754).
99.4	Revised Syndication Procedures dated March 23, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 24, 2016, File No. 1-08754).
99.5	Notice of Syndication Procedures Deadline Extension dated March 29, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 29, 2016, File No. 1-08754).
99.6	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. 1-08754).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith

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SIGNATURES

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



		SWIFT ENERGY COMPANY (Registrant)
Date:	May 10, 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. 1-08754).
10.1	Restructuring Support Agreement dated December 31, 2015 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed January 4, 2016, File No. 1-08754).
10.2	Debtor-In-Possession Credit Agreement dated December 31, 2015 (incorporated by reference as Exhibit 10.2 to Swift Energy Company’s Form 8-K filed January 4, 2016, File No. 1-08754).
10.3	Debtor-In-Possession Credit Agreement dated January 6, 2016 (incorporated by reference as Exhibit 10.1 to Swift Energy Company’s Form 8-K filed January 11, 2016, File No. 1-08754).
99.1	Syndication Procedures dated January 11, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed January 11, 2016, File No. 1-08754).
99.2	Syndication Procedures dated March 10, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 15, 2016, File No. 1-08754).
99.3	Notice of Syndication Procedures Deadline Extension dated March 18, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 21, 2016, File No. 1-08754).
99.4	Revised Syndication Procedures dated March 23, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 24, 2016, File No. 1-08754).
99.5	Notice of Syndication Procedures Deadline Extension dated March 29, 2016 (incorporated by reference as Exhibit 99.1 to Swift Energy Company’s Form 8-K filed March 29, 2016, File No. 1-08754).
99.6	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. 1-08754).
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32*	Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document
101.SCH*	XBRL Schema Document
101.CAL*	XBRL Calculation Linkbase Document
101.LAB*	XBRL Label Linkbase Document
101.PRE*	XBRL Presentation Linkbase Document
101.DEF*	XBRL Definition Linkbase Document

*Filed herewith