PETROQUEST ENERGY INC - FORM 10-Q

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EX-32.2 - EXHIBIT 32.2 - PETROQUEST ENERGY INC	pq3311610qex322.htm
EX-31.1 - EXHIBIT 31.1 - PETROQUEST ENERGY INC	pq3311610qex311.htm
EX-31.2 - EXHIBIT 31.2 - PETROQUEST ENERGY INC	pq3311610qex312.htm
EX-32.1 - EXHIBIT 32.1 - PETROQUEST ENERGY INC	pq3311610qex321.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)



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



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from: to:

Commission file number: 001-32681

_________________________________________________________________

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)

––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––



DELAWARE		72-1440714
(State of Incorporation)		(I.R.S. Employer Identification No.)



400 E. Kaliste Saloom Rd., Suite 6000 Lafayette, Louisiana		70508
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area code: (337) 232-7028

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

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 (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

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



Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of April 29, 2016 there were 70,522,794 shares of the registrant’s common stock, par value $.001 per share, outstanding.

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PETROQUEST ENERGY, INC.

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	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015	1

Consolidated Statements of Operations for the Three Months Ended March 31, 2016 and 2015	2

Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2016 and 2015	3

Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2016 and 2015	4

Notes to Consolidated Financial Statements	5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3. Quantitative and Qualitative Disclosures About Market Risk	21

Item 4. Controls and Procedures	22

Part II. Other Information

Item 1. Legal Proceedings	22

Item 1A. Risk Factors	22

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	25

Item 3. Defaults upon Senior Securities	26

Item 4. Mine Safety Disclosures	26

Item 5. Other Information	26

Item 6. Exhibits	27

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PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)



	March 31, 2016			December 31, 2015
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	53,365		$	148,013
Revenue receivable	7,318			6,476
Joint interest billing receivable	38,665			49,374
Derivative asset	1,277			1,508
Other current assets	6,119			3,874
Total current assets	106,744			209,245
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,310,800			1,310,891
Unevaluated oil and gas properties	11,751			12,516
Accumulated depreciation, depletion and amortization	(1,186,262		)	(1,157,455		)
Oil and gas properties, net	136,289			165,952
Other property and equipment	11,252			11,229
Accumulated depreciation of other property and equipment	(8,925		)	(8,737		)
Total property and equipment	138,616			168,444
Other assets, net of accumulated depreciation and amortization of $3,922 and $3,842, respectively	1,533			1,630
Total assets	$	246,893		$	379,319
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	76,815		$	97,999
Advances from co-owners	4,097			16,118
Oil and gas revenue payable	23,108			18,911
Accrued interest and preferred stock dividend	2,942			12,795
Asset retirement obligation	5,545			6,015
Accrued acquisition cost	—			4,409
Other accrued liabilities	3,915			2,537
Total current liabilities	116,422			158,784
10% Senior Unsecured Notes due 2017	134,583			347,008
10% Senior Secured Notes due 2021	157,039			—
Asset retirement obligation	37,155			36,541
Other long-term liabilities	1,349			53
Commitments and contingencies
Stockholders’ deficit:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	1			1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 70,104 and 65,641 shares, respectively	70			66
Paid-in capital	293,072			290,382
Accumulated other comprehensive income	802			947
Accumulated deficit	(493,600		)	(454,463		)
Total stockholders’ deficit	(199,655		)	(163,067		)
Total liabilities and stockholders’ deficit	$	246,893		$	379,319

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)



	Three Months Ended
	March 31,
	2016			2015
Revenues:
Oil and gas sales	$	17,320		$	33,451
Expenses:
Lease operating expenses	8,177			10,902
Production taxes	338			956
Depreciation, depletion and amortization	10,138			20,654
Ceiling test write-down	18,857			108,911
General and administrative	8,599			5,339
Accretion of asset retirement obligation	608			859
Interest expense	8,257			7,874
	54,974			155,495
Other income:
Other income	97			157
Loss from operations	(37,557		)	(121,887		)
Income tax expense (benefit)	86			(927		)
Net loss	(37,643		)	(120,960		)
Preferred stock dividend	1,494			1,280
Loss available to common stockholders	$	(39,137	)	$	(122,240	)
Loss per common share:
Basic
Net loss per share	$	(0.58	)	$	(1.89	)
Diluted
Net loss per share	$	(0.58	)	$	(1.89	)
Weighted average number of common shares:
Basic	67,824			64,774
Diluted	67,824			64,774

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)



	Three Months Ended
	March 31,
	2016			2015
Net loss	$	(37,643	)	$	(120,960	)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of ($86) and $947, respectively	(145		)	1,598
Comprehensive loss	$	(37,788	)	$	(119,362	)

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)



	Three Months Ended
	March 31,
	2016			2015
Cash flows from operating activities:
Net loss	$	(37,643	)	$	(120,960	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax expense (benefit)	86			(927		)
Depreciation, depletion and amortization	10,138			20,654
Ceiling test writedown	18,857			108,911
Accretion of asset retirement obligation	608			859
Share-based compensation expense	442			1,478
Amortization costs and other	562			591
Payments to settle asset retirement obligations	(464		)	(894		)
Costs incurred to issue 2021 Notes	4,740			—
Changes in working capital accounts:
Revenue receivable	(842		)	2,794
Joint interest billing receivable	10,709			14,439
Accounts payable and accrued liabilities	(20,413		)	(24,561		)
Advances from co-owners	(12,021		)	22,182
Other	(949		)	(1,335		)
Net cash provided by (used in) operating activities	(26,190		)	23,231
Cash flows used in investing activities:
Investment in oil and gas properties	(15,812		)	(36,033		)
Investment in other property and equipment	(23		)	(80		)
Sale of oil and gas properties	7,000			—
Net cash used in investing activities	(8,835		)	(36,113		)
Cash flows provided by (used in) financing activities:
Net proceeds for share based compensation	65			405
Deferred financing costs	(38		)	(273		)
Payment of preferred stock dividend	(1,284		)	(1,284		)
Redemption of 2017 Notes	(53,626		)	—
Costs incurred to issue 2021 Notes	(4,740		)	—
Proceeds from bank borrowings	—			15,000
Repayment of bank borrowings	—			(5,000		)
Net cash provided by (used in) financing activities	(59,623		)	8,848
Net decrease in cash and cash equivalents	(94,648		)	(4,034		)
Cash and cash equivalents, beginning of period	148,013			18,243
Cash and cash equivalents, end of period	$	53,365		$	14,209
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	16,781		$	17,943
Income taxes	$	—		$	20

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Basis of Presentation

The consolidated financial information for the three month periods ended March 31, 2016 and 2015, has been prepared by the Company and was not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at March 31, 2016 and for all reported periods. Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.

The balance sheet at December 31, 2015 has been derived from the audited financial statements at that date. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted. These consolidated financial statements should be read in conjunction with the audited financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2015. Certain prior period amounts have been reclassified to conform to current year presentation.

Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to the “Company,” "we," or "us" refer to PetroQuest Energy, Inc. ("PetroQuest") and its wholly-owned consolidated subsidiaries, PetroQuest Energy, L.L.C. (a single member Louisiana limited liability company), PetroQuest Oil & Gas, L.L.C. (a single member Louisiana limited liability company), TDC Energy LLC (a single member Louisiana limited liability company) and Pittrans, Inc. (an Oklahoma corporation).

Note 2—Acquisitions and Divestitures

Acquisition:

In June 2014, the Company entered into a joint venture in Louisiana for an aggregate purchase price of $24 million. The assets acquired under the joint venture include an average 37% working interest in an approximately 30,000 acre leasehold position in Louisiana and exclusive rights, along with the Company's joint venture partner, to a 200 square mile proprietary 3D survey which has generated several conventional and shallow non-conventional oil focused prospects.

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. At December 31, 2015, $4.4 million of this drilling carry remained outstanding and was reflected as accrued acquisition costs in the Consolidated Balance Sheet. During February 2016, the Company paid $4.4 million to settle this liability with its joint venture partner in connection with the terms of the agreement.

Divestitures:

On June 4, 2015, the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime (the “Sold Assets”) for $260.2 million. At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227 Bcfe, which represented approximately 57% of the Company's estimated proved reserves. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $23.2 million during 2015. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

In March 2016, the Company sold certain non-producing assets in East Texas for $7 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

Subsequent Event:

On April 20, 2016, the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field (the "East Hoss Assets") for approximately $18 million, subject to customary post-closing purchase price adjustments, effective April 1, 2016. The East Hoss Assets produced approximately 0.9 Bcfe, net to the Company, during the first quarter of 2016. As of December 31, 2015, the Company's estimated proved reserves attributable to the East Hoss Assets totaled approximately 19 Bcfe.

Note 3—Convertible Preferred Stock

The Company has 1,495,000 shares of 6.875% Series B Cumulative Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) outstanding.

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The following is a summary of certain terms of the Series B Preferred Stock:

Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.

On January 26, 2016, in connection with an amendment to the Company's bank credit facility prohibiting the Company from declaring or paying dividends on the Series B Preferred Stock, the Company announced its intention to suspend the quarterly cash dividend on its Series B Preferred Stock beginning with the dividend payment due on April 15, 2016. Under the terms of the Series B Preferred Stock, any unpaid dividends will accumulate. If the Company fails to pay six quarterly dividends on the Series B Preferred Stock, whether or not consecutive, holders of the Series B Preferred Stock, voting as a single class, will have the right to elect two additional directors to the Company's Board of Directors until all accumulated and unpaid dividends on the Series B Preferred Stock are paid in full.

Mandatory conversion. The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

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Note 4—Earnings Per Share

A reconciliation between the basic and diluted earnings per share computations (in thousands, except per share amounts) is as follows:



For the Three Months Ended March 31, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(39,137	)	67,824	$	(0.58	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(39,137	)	67,824	$	(0.58	)

For the Three Months Ended March 31, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(122,240	)	64,774	$	(1.89	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(122,240	)	64,774	$	(1.89	)

An aggregate of 2.6 million and 0.5 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three month periods ended March 31, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

Note 5—Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017. On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (collectively, the "2017 Notes").

On January 14, 2016, the Company announced the commencement of a private exchange offer (the "Exchange") and consent solicitation (the "Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. The Exchange closed on February 17, 2016, and in satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the outstanding aggregate principal amount of 2017 Notes, in the Exchange the Company (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of its new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 4.3 million shares of its common stock. Following the completion of the Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remain outstanding. The Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

The Exchange was accounted for as a troubled debt restructuring pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") section 470-60 "Troubled Debt Restructurings by Debtors." The Company has determined that the future undiscounted cash flows from the 2021 Notes issued in the Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the Exchange. The excess of the future undiscounted cash flows from the 2021 Notes issued in the Exchange over the remaining carrying value of the 2017 Notes tendered in the Exchange of $13.9 million is reflected as part of the 2021 Notes. Such excess will be amortized under the effective interest method as a reduction of interest expense over the term of the 2021 Notes. At March 31, 2016, $13.6 million of the excess remained as part of the 2021 Notes and the Company recognized $0.3 million of amortization expense as a reduction to interest expense during the first quarter of 2016.

The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company.

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The 2021 Notes are secured by second-priority liens on substantially all of the Company's and the subsidiary guarantors' oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Credit Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the 2021 Notes and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.

The Company will pay 10% per annum on the principal amount of the 2021 Notes semi-annually in arrears on February 15 and August 15 of each year, beginning August 15, 2016. At March 31, 2016, $1.8 million had been accrued in connection with the August 15, 2016 payment and the Company was in compliance with all of the covenants under the 2021 Notes. Interest on the 2017 Notes is payable semi-annually on March 1 and September 1. At March 31, 2016, $1.1 million had been accrued in connection with the September 1, 2016 interest payment and the Company was in compliance with all of the covenants under the 2017 Notes.

During 2015, the Company adopted ASU No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs", which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related liability rather than as an asset. As a result, the 2017 Notes are reflected net of $1.0 million and $3.0 million of related financing costs at March 31, 2016 and December 31, 2015, respectively. The 2021 Notes are reflected net of $1.2 million of related financing costs as of March 31, 2016.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 2017 Notes remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of March 31, 2016, the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. Two interim redeterminations are also scheduled to occur on July 31 and December 31 of each year commencing on July 31, 2016. The Company or the lenders may also request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

As of March 31, 2016, the borrowing base and aggregate commitments of the lenders were both $42 million, provided, that the Company's utilization of the borrowing base was limited by applicable financial covenants to 25% of the aggregate commitments of the lenders, or $10.5 million. The Company is currently undergoing a borrowing base redetermination and expects that the borrowing base and aggregate commitments of the lenders will be reduced due in part to the April 2016 sale of the East Hoss Assets. However, under the terms of the Limited Waiver described below, the Company is not permitted to request any borrowings under (or issue any letters of credit pursuant to) the Credit Agreement until this borrowing base redetermination is completed.

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1% to 2% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2% to 3% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%. For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) if the Company has unused availability greater than or equal to 75% of the aggregate commitments of the Lenders at all times during the consecutive three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 5.0 to 1.0

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as of the last day of the fiscal quarter ending March 31, 2016, 5.50 to 1.0 as of the last day of the fiscal quarter ending June 30, 2016 and 5.75 to 1.0 as of the last day of the fiscal quarters ending September 30, 2016 and December 31, 2016, with in each case the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted cash of the Company and cash subject to an account control agreement, (b) if the Company has unused availability of less than 75% of the aggregate commitments of the Lenders at any time during the consecutive three month period prior to and including the date of calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.0 as of the last day of the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, and (c) 5.0 to 1.0 as of the last day of any fiscal quarter ending on or after March 31, 2017 and (ii) a minimum ratio of EBITDAX to total cash interest expense of 1.0 to 1.0, all as defined in the Credit Agreement.

The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. The Credit Agreement also currently prohibits the Company from declaring and paying dividends on its Series B Preferred Stock. As of March 31, 2016, the Company was not in compliance with the restrictive financial covenant under the Credit Agreement relating to the ratio of total debt to EBITDAX. The Company received a limited waiver (the “Limited Waiver”) from the Lenders under the Credit Agreement with respect to this covenant violation and any event of default relating thereto, provided, that the Company is not permitted to request any borrowings under (or issue any letters of credit pursuant to) the Credit Agreement until the ongoing redetermination of the borrowing base under the Credit Agreement is completed.

Note 6—Asset Retirement Obligation

The following table describes the changes to the Company’s asset retirement obligation liability (in thousands):



	Three Months Ended March 31,
	2016			2015
Asset retirement obligation, beginning of period	$	42,556		$	54,970
Liabilities incurred	—			380
Liabilities settled	(464		)	(894		)
Accretion expense	608			859
Revisions in estimates	—			43
Asset retirement obligation, end of period	42,700			55,358
Less: current portion of asset retirement obligation	(5,545		)	(1,910		)
Long-term asset retirement obligation	$	37,155		$	53,448

Note 7—Ceiling Test

The Company uses the full cost method to account for its oil and gas properties. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from estimated proved oil and gas reserves, including the effects of cash flow hedges in place, discounted at 10%, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write-down of oil and gas properties in the quarter in which the excess occurs.

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At March 31, 2016, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 per Mcf of natural gas, $45.92 per barrel of oil and $1.91 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $18.9 million during the three months ended March 31, 2016. The Company’s cash flow hedges in place at March 31, 2016 decreased the ceiling test write-down by approximately $0.8 million.

At March 31, 2015, the prices used in computing the estimated future net cash flows from the Company's estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 per Mcf of natural gas, $81.33 per barrel of oil and $3.52 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $108.9 million during the three months ended March 31, 2015. The Company's cash flow hedges in place at March 31, 2015 increased the ceiling test write-down by approximately $14 million.

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Note 8—Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At March 31, 2016, all of the Company's derivative instruments were designated as effective cash flow hedges.

Oil and gas sales include additions related to the settlement of gas hedges of $1,032,000 and $2,324,000, oil hedges of $0 and $27,000 and Ngl hedges of $0 and $21,000 for the three months ended March 31, 2016 and 2015, respectively.

As of March 31, 2016, the Company had entered into the following commodity derivative instruments:



Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April 2016 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

At March 31, 2016, the Company had recognized accumulated other comprehensive income of approximately $0.8 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of March 31, 2016, the Company would reclassify approximately $0.8 million, net of taxes, of accumulated other comprehensive income into earnings during the next nine months. These gains are expected to be reclassified to oil and gas sales based on the schedule of gas volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

The following tables reflect the fair value of the Company’s effective cash flow hedges in the consolidated financial statements (in thousands):

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at March 31, 2016 and December 31, 2015:



	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
March 31, 2016	Derivative asset	$	1,277
December 31, 2015	Derivative asset	$	1,508

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended March 31, 2016 and 2015:



Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain Reclassified into Income	Amount of Gain Reclassified into Income
Commodity Derivatives at March 31, 2016	$	801	Oil and gas sales	$	1,032
Commodity Derivatives at March 31, 2015	$	4,917	Oil and gas sales	$	2,372

Note 9 – Fair Value Measurements

As defined in ASC Topic 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:


•	Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;


•	Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

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•	Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at March 31, 2016 were in the form of swaps based on NYMEX pricing for natural gas. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2016 and December 31, 2015 (in thousands):



	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
March 31, 2016	$	—	$	1,277	$	—
December 31, 2015	$	—	$	1,508	$	—

The fair value of the Company's cash and cash equivalents approximated book value at March 31, 2016 and December 31, 2015. The Company had no variable rate bank debt as of March 31, 2016 and December 31, 2015. The fair value of the 2017 Notes was approximately $62.5 million and $238 million as of March 31, 2016 and December 31, 2015, respectively, as compared to the book value of $135.6 million and $350.0 million, respectively. The fair value of the 2021 Notes was approximately $92.6 million as of March 31, 2016 as compared to the book value of $158.3 million (including the excess of future undiscounted cash flows from the 2021 Notes over the remaining carrying value of the 2017 Notes described in Note 5) and the face value of $144.7 million. The fair value of the 2017 and 2021 Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input.

Note 10—Income Taxes

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs recognized, the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $157.6 million as of March 31, 2016.

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Note 11 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended March 31, 2016 (in thousands):



	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2015	$947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	801
Income tax effect	(298	)
Net of tax	503
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(1,032	)
Income tax effect	384
Net of tax	(648	)
Net other comprehensive loss	(145	)
Balance as of March 31, 2016	$802

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended March 31, 2015 (in thousands):



	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$5,420
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	4,917
Income tax effect	(1,829	)
Net of tax	3,088
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	(2,372	)
Income tax effect	882
Net of tax	(1,490	)
Net other comprehensive income	1,598
Balance as of March 31, 2015	$7,018

Note 12 - Recently Issued Accounting Standards

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2016-02, "Leases" ("ASU 2016-02"), which will require lessees to recognize lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous guidance. Public entities are required to adopt ASU 2016-02 for reporting periods beginning after December 15, 2018. The Company is currently evaluating the impact of the new standard on its consolidated financial statements.

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Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas, the Gulf Coast Basin and Oklahoma. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

We have successfully diversified into onshore, longer life basins through a combination of selective acquisitions and drilling activity, partially offset by our recent asset divestitures in Oklahoma as discussed below. As a result of our transition to lower-risk, longer life basins, we have realized a 95% drilling success rate on 913 gross wells drilled over the last 10 years. Comparing 2015 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 254% and estimated proved reserves by 114%.

On June 4, 2015, we completed the sale of a majority of our interests in the Woodford and Mississippian Lime for $260.2 million. In March 2016, we sold certain non-producing assets in East Texas for $7 million and in April 2016, we sold the majority of the remainder of our Woodford Shale assets for approximately $18 million.

In response to the decline in commodity prices that began in late 2014 and has continued throughout 2015 and into 2016, we have reduced our capital expenditures in 2016 as compared to 2015. In addition and as discussed above, we recently completed asset sales that have strengthened our liquidity position and repaid all indebtedness under our bank credit facility. We also completed a Debt Exchange (see Note 5 - Long Term Debt Exchange) in February 2016 that reduced indebtedness by $69.7 million and extended the maturity on $144.7 million of indebtedness from September 2017 to February 2021. We also suspended the dividend on our Series B Preferred Stock beginning with the April 2016 payment, which will save $5.1 million annually. We plan to reduce our cash costs during 2016 by 25% as compared to 2015 and consider additional options to refinance the remaining $135.6 million of 2017 Notes. As of March 31, 2016, we had $53 million of cash on hand and had no borrowings outstanding under our bank credit facility. We plan to fund the remainder of our 2016 capital expenditures with cash flows from operations and cash on hand.

Critical Accounting Policies

Reserve Estimates

Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.

Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the

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existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization.

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.

We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings.

We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate.

Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of cash flow hedges in place, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices remain at current levels or decline further, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Derivative Instruments

We seek to reduce our exposure to commodity price volatility by hedging a portion of our production through commodity derivative instruments. The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil and natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense).

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Our hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX and OPIS Mt. Belvieu prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX or OPIS Mt. Belvieu prices at which the hedges will be settled. At March 31, 2016, our derivative instruments were designated as effective cash flow hedges.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX or OPIS Mt. Belvieu prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our default risk for derivative liabilities.

Results of Operations

The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.



	Three Months Ended March 31,
	2016		2015
Production:
Oil (Bbls)	139,989		147,214
Gas (Mcf)	5,547,477		7,915,504
Ngl (Mcfe)	1,246,632		1,576,540
Total Production (Mcfe)	7,634,043		10,375,330
Sales:
Total oil sales	$	4,358,744	$	6,952,900
Total gas sales	10,718,208		21,650,095
Total ngl sales	2,242,762		4,848,046
Total oil, gas, and ngl sales	$	17,319,714	$	33,451,041
Average sales prices:
Oil (per Bbl)	$	31.14	$	47.23
Gas (per Mcf)	1.93		2.74
Ngl (per Mcfe)	1.80		3.08
Per Mcfe	2.27		3.22

The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of $1,032,000 and $2,324,000, oil hedges of $0 and $27,000 and Ngl hedges of $0 and $21,000 for the three months ended March 31, 2016 and 2015, respectively. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q for further details on our hedging program and our current hedging arrangements.

Net loss available to common stockholders totaled $39,137,000 and $122,240,000 for the three months ended March 31, 2016 and 2015, respectively. The primary fluctuations were as follows:

Production Total production decreased 26% during the three month period ended March 31, 2016 as compared to the 2015 period. The decrease in total production was primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 as well as normal production declines at our Gulf Coast fields. Partially offsetting the decrease was the successful drilling program in our Carthage field as well as our Thunder Bayou discovery. Due to the current low commodity price environment, our capital expenditures budget for 2016 is significantly reduced as compared to 2015. As a result of the substantial decrease in capital spending, combined with our 2015 and 2016 Oklahoma divestments, we expect our total production for the remainder of 2016 to continue to decrease as compared to 2015.

Gas production during the three month period ended March 31, 2016 decreased 30% from the comparable period in 2015. The decrease was primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 as well as normal production declines at our Gulf Coast fields. Partially offsetting the decrease was the successful completion of our Thunder Bayou discovery and the drilling program at our East Hoss field in Oklahoma. We expect our average daily gas production to decrease during the remainder of 2016 as compared to 2015 due to our 2015 and 2016 Oklahoma divestments, only partially offset by the successful drilling program in our Carthage field and our Thunder Bayou discovery which was brought online in June 2015.

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Oil production during the three month period ended March 31, 2016 decreased 5% from the 2015 period due primarily to pipeline repairs which shut-in several of our Gulf Coast fields during January and February of 2016 along with normal production declines at our Gulf Coast fields and the sale of our Fort Trinidad field in East Texas. Partially offsetting these decreases were increases due to the successful drilling at our Carthage field and our Thunder Bayou discovery as well as improved production at our West Delta 89 field due to successful recompletions during 2015. As a result of normal production declines, we expect our average daily oil production to decrease during the remainder of 2016 as compared to 2015.

Ngl production during the three month period ended March 31, 2016 decreased 21% from the 2015 period primarily due to our 2015 Oklahoma divestiture. Partially offsetting this decrease was the successful completion of our Thunder Bayou discovery, continued success in our Carthage field and improved production from our West Delta 89 field due to successful recompletions during 2015. We expect our average daily Ngl production to decrease during the remainder of 2016 as compared to 2015 primarily due to the divestment of the liquids rich portion of our Oklahoma acreage position.

Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2016 were $1.93 as compared to $2.74 for the 2015 period. Average oil prices per Bbl for the three months ended March 31, 2016 were $31.14 as compared to $47.23 for the 2015 period and average Ngl prices per Mcfe were $1.80 for the three months ended March 31, 2016, as compared to $3.08 for the 2015 period. Stated on an Mcfe basis, unit prices received during the three months ended March 31, 2016 were 30% lower than the prices received during the comparable 2015 period.

Revenue Including the effects of hedges, oil and gas sales during the three months ended March 31, 2016 decreased 48% to $17,320,000, as compared to oil and gas sales of $33,451,000 during the 2015 period. This decrease was primarily the result of lower average realized prices for our production during 2016 as well as decreased production as discussed above.

Expenses Lease operating expenses for the three months ended March 31, 2016 totaled $8,177,000 as compared to $10,902,000 during the 2015 period. Per unit lease operating expenses totaled $1.07 per Mcfe during the three month period ended March 31, 2016 as compared to $1.05 per Mcfe during the 2015 period. Total lease operating expenses decreased during the three months ended March 31, 2016 primarily as result of our 2015 Oklahoma divestiture. Per unit lease operating expenses increased during the 2016 quarter as result of our 2015 Oklahoma divestiture, which included properties with a lower relative per unit cost, as well as normal production declines and downtime at certain of our Gulf Coast fields. As a result of our 2015 and 2016 Oklahoma divestitures, we expect total lease operating expenses to be lower and per unit lease operating expenses to be higher during the remainder of 2016 as compared to 2015.

Production taxes for the three months ended March 31, 2016 totaled $338,000 as compared to $956,000 during the 2015 period. Per unit production taxes totaled $0.04 per Mcfe during the three month period ended March 31, 2016 as compared to $0.09 per Mcfe during the comparable 2015 period. The decrease in production taxes was primarily due to lower commodity prices for our production during the 2016 period as compared to the 2015 period. Severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. As a result of the current commodity pricing environment and lower estimated production as a result of our 2015 and 2016 Oklahoma divestitures, we expect a decrease in our total and per unit production taxes during the remainder of 2016 as compared to 2015.

General and administrative expenses during the three months ended March 31, 2016 totaled $8,599,000 as compared to $5,339,000 during the 2015 period. General and administrative expenses during the three months ended March 31, 2016 included $4,740,000 of costs related to the issuance of the 2021 Notes. ASC Topic 470-60 "Troubled Debt Restructurings by Debtors" requires financing costs related to a troubled debt transaction to be expensed in the period incurred. Offsetting this increase were lower employee related costs, including share-based compensation. Share-based compensation costs totaled $513,000 during the first quarter of 2016, compared to $1,519,000 during the 2015 period. We capitalized $1,489,000 of general and administrative expenses during the three month period ended March 31, 2016 compared to $2,240,000 during the 2015 period. We expect total general and administrative expenses during the remainder of 2016 to be lower than 2015.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended March 31, 2016 totaled $9,950,000, or $1.30 per Mcfe, as compared to $20,317,000, or $1.96 per Mcfe, during the comparable 2015 period. The decrease in the per unit DD&A rate is primarily the result of the recent ceiling test write-downs. As a result of ceiling test write-downs, we expect our DD&A rate to be lower for the remainder of 2016.

At March 31, 2016, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 per Mcf of natural gas, $45.92 per barrel of oil and $1.91 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized a ceiling test write-down of $18,857,000 during the three month period ended March 31, 2016. At March 31, 2015 , the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 per Mcf of natural gas, $81.33 per barrel of oil and $3.52 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net

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cash flows, we recognized a ceiling test write-down of $108,911,000 during the three months ended March 31, 2015. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-downs. Utilizing current strip prices for oil and gas prices for the second quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of March 31, 2016, we expect to recognize an additional ceiling test write-down of $10 million to $20 million in the second quarter of 2016.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $8,257,000 during the three months ended March 31, 2016 as compared to $7,874,000 during the 2015 period. During the three month period ended March 31, 2016, our capitalized interest totaled $309,000 as compared to $1,998,000 during the 2015 period. The increase in interest expense during the 2016 period was the result of lower capitalized interest on our reduced unevaluated property balance. Our unevaluated property balance declined during June 2015 as a result of our 2015 Oklahoma divestiture. Partially offsetting the increase in interest expense during the first quarter of 2016 was a $287,000 non-cash reduction related to the amortization of the excess carrying value on the Exchange (see Note 5 - Long Term Debt).

Income tax expense during the three months ended March 31, 2016 was $86,000 as compared to an income tax benefit of $927,000 during the comparable 2015 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.

As a result of ceiling test write-downs, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $157,590,000 as of March 31, 2016.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, issuances of equity and debt securities, joint ventures and sales of assets. At March 31, 2016, we had a working capital deficit of approximately $9.7 million as compared to a working capital surplus of approximately $50.5 million as of December 31, 2015. The decrease in our working capital is primarily due to the $58.4 million in cash payments made in connection with the Exchange discussed below.

Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage our working capital and liquidity position. In response to the impact that the decline in commodity prices has had, and is expected to continue to have, on our cash flow, our 2016 capital expenditure budget of between $20 million and $25 million is significantly reduced as compared to 2015. During the three months ended March 31, 2016, we funded our capital expenditures with cash on hand. To the extent additional capital is required, we may utilize sales of equity or debt securities, evaluate the sale of additional assets, enter into joint venture arrangements or reduce our capital expenditure budget to manage our liquidity position. In addition, we suspended the quarterly dividend on our outstanding Series B Preferred Stock beginning with the dividend payment in April 2016 (which will save $5.1 million annually). We also plan to reduce our cash costs by 25% from 2015 levels and consider additional options to refinance our remaining $135.6 million of 2017 Notes.

To cover the various obligations of lessees on the Outer Continental Shelf (the “OCS”), the BOEM and the BSEE generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. Because we are not exempt from the BOEM's supplemental bonding requirements, we engage surety companies to post the requisite bonds. Pursuant to the terms of our surety agreements, we may be required to post collateral at the surety companies discretion. Two of our surety companies have requested collateral to be posted to support certain of the bonds issued on our behalf. We are currently evaluating options for providing the requested collateral. The satisfaction of this request for collateral could have a material adverse effect on our liquidity position. If we fail to satisfy the request for collateral, we may be in default under our agreements with the surety companies, which could cause a cross-default under our bank credit facility and potentially the indenture governing the 2021 Notes.

We may also be required to provide cash collateral or letters of credit to support the issuance of new bonds. Such letters of credit would likely be issued under our bank credit facility (subject to availability thereunder) and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases or that we will have sufficient availability under our bank credit facility to support such supplemental bonding requirements. If we are unable to obtain the additional required bonds or assurances as requested, the BOEM may require any of our operations on federal leases to be suspended, canceled or otherwise impose monetary penalties, and one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

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As of March 31, 2016, we had $53 million of cash on hand and had no borrowings outstanding under our bank credit facility. As of March 31, 2016, the borrowing base and aggregate commitments of the lenders under the bank credit facility were both $42 million, provided that the Company's utilization of the borrowing base was limited by applicable financial covenants to 25% of the aggregate commitments of the lenders, or $10.5 million. We are currently undergoing a borrowing base redetermination and expect that the borrowing base and aggregate commitments of the lenders will be reduced due in part to the April 2016 sale of the East Hoss Assets. However, under the terms of the Limited Waiver described in “Source of Capital: Debt” below, we are not permitted to request any borrowings under (or issue any letters of credit pursuant to) the Credit Agreement until this borrowing base redetermination is completed.

Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. While we seek to reduce our exposure to price volatility by hedging a portion of our production, our hedges may be inadequate to protect us from continuing and prolonged declines in commodity prices. To the extent that commodity prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive covenants in the indenture governing the 2021 Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as oil and natural gas prices.

Source of Capital: Operations

Net cash flow provided by (used in) operations decreased from $23.2 million during the three months ended March 31, 2015 to $(26.2) million during the 2016 period. The decrease in operating cash flow during 2016 as compared to 2015 is primarily attributable to decreases in oil and gas revenues as well as the timing of payment of payables based on operational activity.

Source of Capital: Divestitures

We do not budget for property divestitures; however, we are continuously evaluating our property base to determine if there are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain assets in order to provide liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We are currently exploring divestment opportunities for certain of our assets. We cannot assure you that we will be able to sell any of our assets in the future.

In June 2015, we sold a majority of our interests in the Woodford and Mississippian Lime fields for cash proceeds of $260.2 million. Net proceeds from the sale were used to repay all borrowings outstanding under our bank credit facility and increase our cash on hand. In March 2016, we sold certain non-producing assets in East Texas for $7 million and in April 2016, we sold the majority of our remaining Woodford Shale assets in Oklahoma for approximately $18 million.

Source of Capital: Debt

On August 19, 2010, we issued $150 million in principal amount of our 10% Senior Notes due 2017. On July 3, 2013, we issued an additional $200 million in principal amount of our 10% Senior Notes due 2017 (collectively, the "2017 Notes").

On January 14, 2016, we announced the commencement of a private exchange offer (the "Exchange") and consent solicitation (the "Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. The Exchange closed on February 17, 2016, and in satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the outstanding aggregate principal amount of 2017 Notes, in the Exchange, we (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of our new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 4.3 million shares of our common stock. Following the completion of the Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remain outstanding. The Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

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The following table reconciles the face value of the 2017 Notes and 2021 Notes to the carrying value included in our Consolidated Balance Sheet as of March 31, 2016 and December 31, 2015 (in thousands):



	March 31, 2016						December 31, 2015
	2017 Notes			2021 Notes			2017 Notes			2021 Notes
Face Value	$	135,621		$	144,674		$	350,000		$	—
Deferred Financing Costs	(1,038		)	(1,240		)	(2,992		)	—
Excess Carrying Value	—			13,605			—			—
Carrying Value	$	134,583		$	157,039		$	347,008		$	—

The indenture governing the 2021 Notes contains affirmative and negative covenants that, among other things, limit our ability and the subsidiary guarantors of the 2021 Notes to incur indebtedness; purchase or redeem stock; make certain investments; create liens that secure debt; enter into transactions with affiliates; sell assets; refinance certain indebtedness; merge with or into other companies or transfer substantially all of their assets; and, in certain circumstances, to pay dividends or make other distributions on stock. The 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain of our wholly-owned subsidiaries.

The 2021 Notes are secured by second-priority liens on substantially all of our and our subsidiary guarantors' oil and gas properties and substantially all of our other assets to the extent such properties and assets secure the Credit Agreement (as defined below), except for certain excluded assets. Pursuant to the terms of an intercreditor agreement, the security interest in those properties and assets that secure the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Credit Agreement and certain other permitted indebtedness. Consequently, the 2021 Notes and the guarantees will be effectively subordinated to the Credit Agreement and such other indebtedness to the extent of the value of such assets.

We will pay 10% per annum on the principal amount of the 2021 Notes semi-annually in arrears on February 15 and August 15 of each year beginning August 15, 2016. At March 31, 2016, $1.8 million had been accrued in connection with the August 15, 2016 payment. Interest on the 2017 Notes is payable semi-annually on March 1 and September 1. At March 31, 2016, $1.1 million had been accrued in connection with the September 1, 2016 interest payment.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of our 2017 Notes remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of March 31, 2016, we had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is determined by March 31 and September 30 of each year and is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. Two interim redeterminations are also scheduled to occur on July 31 and December 31 of each year commencing on July 31, 2016. We or the lenders may also request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

As of March 31, 2016, the borrowing base and aggregate commitments of the lenders were both $42 million, provided, that our utilization of the borrowing base was limited by applicable financial covenants to 25% of the aggregate commitments of the lenders, or $10.5 million. We are currently undergoing a borrowing base redetermination and expect that the borrowing base and aggregate commitments of the lenders will be reduced due in part to the April 2016 sale of the East Hoss Assets. However, under the terms of the Limited Waiver described below, we are not permitted to request any borrowings under (or issue any letters of credit pursuant to) the Credit Agreement until this borrowing base redetermination is completed.

The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 90% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1% to 2% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2% to 3% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%. For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For

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all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

We are subject to certain restrictive financial covenants under the Credit Agreement, including (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) if we have unused availability greater than or equal to 75% of the aggregate commitments of the lenders at all times during the consecutive three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 5.0 to 1.0 as of the last day of the fiscal quarter ending March 31, 2016, 5.50 to 1.0 as of the last day of the fiscal quarter ending June 30, 2016 and 5.75 to 1.0 as of the last day of the fiscal quarters ending September 30, 2016 and December 31, 2016, with in each case the amount of total debt for such quarterly period reduced by the amount of our unencumbered and unrestricted cash and cash subject to an account control agreement, (b) if we have unused availability of less than 75% of the aggregate commitments of the lenders at any time during the consecutive three month period prior to and including the date of calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.0 as of the last day of the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, and (c) 5.0 to 1.0 as of the last day of any fiscal quarter ending on or after March 31, 2017 and (ii) a minimum ratio of EBITDAX to total cash interest expense of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. The Credit Agreement also currently prohibits us from declaring and paying dividends on our Series B Preferred Stock. As of March 31, 2016, we were not in compliance with the restrictive financial covenant under the Credit Agreement relating to the ratio of total debt to EBITDAX. We received a limited waiver (the “Limited Waiver”) from the lenders under the Credit Agreement with respect to this covenant violation and any event of default relating thereto, provided, that we are not permitted to request any borrowings under (or issue any letters of credit pursuant to) the Credit Agreement until the ongoing redetermination of the borrowing base under the Credit Agreement is completed.

Source of Capital: Issuance of Securities

Our shelf registration statement, which expires in September 2016, allows us to publicly offer and sell up to $350 million of any combination of debt securities, shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.

Use of Capital: Exploration and Development

Our 2016 capital expenditure budget, which includes capitalized interest and general and administrative costs, is expected to range between $20 million and $25 million (which from the midpoint of such range, represents a 65% reduction from our 2015 capital expenditures), of which $6.1 million was incurred during the first three months of 2016, before consideration of $7 million of proceeds received from the sale of certain East Texas non-producing assets. During the three months ended March 31, 2016, we funded our capital expenditures with cash on hand. We plan to fund our capital expenditures during the remainder of 2016 with cash flow from operations and cash on hand.

Use of Capital: Acquisitions

We do not budget for acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base or establish positions in new core areas.

We expect to finance our future acquisition activities, if consummated, through cash on hand or available borrowings under our bank credit facility. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.

Disclosure Regarding Forward Looking Statements

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.

Among those risks, trends and uncertainties are: the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014; our indebtedness and the significant amount of cash required to service our indebtedness; the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition; our ability to obtain

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adequate financing when the need arises to execute our long-term strategy and to fund our planned capital expenditures; our ability to reduce leverage or refinance our remaining 2017 Notes; our estimate of the sufficiency of our existing capital sources, including availability under our bank credit facility and the result of any borrowing base redetermination; limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our bank credit facility and restrictive debt covenants; our ability to post additional collateral to satisfy our offshore decommissioning obligations; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market; ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; our ability to find, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable; approximately 50% of our production being exposed to the additional risk of severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in laws and governmental regulations; increases in insurance costs or decreases in insurance availability, competition from larger oil and natural gas companies; the operating hazards attendant to the oil and gas business; the loss of our information and computer systems; the impact of terrorist activities on global economies; the volatility of our stock price; our ability to meet the continued listing standards of the New York Stock Exchange with respect to our common stock or to cure any deficiency with respect thereto; and our ability to pay dividends on our Series B Preferred Stock.

Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that such expectations reflected in these forward looking statements will prove to have been correct.

When used in this Quarterly Report on Form 10-Q, the words “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q.

You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. You should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Quarterly Report on Form 10-Q could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment.

We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we undertake no obligation to update any of the forward-looking statements in this Quarterly Report on Form 10-Q after the date of this Quarterly Report on Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We experience market risks primarily in two areas: commodity prices and interest rates. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.

Commodity Price Risk

Our revenues are derived from the sale of our crude oil, natural gas and natural gas liquids production. Based on projected sales volumes for the remainder of 2016, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have a $4.2 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three months ended March 31, 2016, we received $1.0 million from the counterparties to our derivative instruments in connection with net hedge settlements.

We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.

Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing hedge contracts are lenders under the Credit Agreement.

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As of March 31, 2016, we had entered into the following commodity derivative instruments:



Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April 2016 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

The Company has approximately 1.8 Bcf of gas volumes at $2.86 per Mcf hedged for the remainder of 2016. For further discussion of our commodity derivative instruments, please see Item 1, Note 8 "Derivative Instruments" in this Form 10-Q.

Interest Rate Risk

Debt outstanding under our bank credit facility is subject to a floating interest rate. As of March 31, 2016, we had no borrowings outstanding under our credit facility.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, the Company’s management, including its Chief Executive Officer and Chief Financial Officer, completed an evaluation of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15 of the Securities and Exchange Act of 1934, as amended (the “Exchange Act”). Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded:

that the Company’s disclosure controls and procedures are designed to ensure (a) that information required to be disclosed by the Company in the reports it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and (b) that such information is accumulated and communicated to the Company’s management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure; and


ii.	that the Company's disclosure controls and procedures are effective.

Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.

Changes in Internal Control Over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting during the period covered by this report that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 1A. RISK FACTORS

Oil and natural gas prices are volatile, and an extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and oil prices have been significantly depressed since the end of 2014 as demonstrated by the SEC pricing for the value of crude oil and natural gas, which has decreased significantly as of December 31, 2015 as compared to December 31, 2014. For example, the SEC pricing at December 31, 2015

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for crude oil (WTI Cushing) and natural gas (Henry Hub) was $50.28 per Bbl and $2.58 per MMBtu, respectively, as compared to $94.99 per Bbl to a low of $4.35 per MMBtu for crude oil and natural gas, respectively, as of December 31, 2014. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control.

These factors include:


•	relatively minor changes in the supply of or the demand for oil and natural gas;


•	the condition of the United States and worldwide economies;


•	market uncertainty;


•	the level of consumer product demand;


•	weather conditions in the United States, such as hurricanes;


•	the actions of the Organization of Petroleum Exporting Countries;


•	domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;


•	political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;


•	the price and level of foreign imports of oil and natural gas; and


•	the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and will likely require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2016 to decline compared to our estimated proved reserves at December 31, 2015. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that we can enter into effective hedging transactions in the future or that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our outstanding indebtedness may adversely affect our cash flow and our ability to operate our business, remain in compliance with debt covenants and make payments on our debt.

As of March 31, 2016, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $238.3 million. As of March 31, 2016, the borrowing base and aggregate commitments of the lenders under our bank credit facility were both $42 million, provided, that our utilization of the borrowing base was limited by applicable financial covenants to 25% of the aggregate commitments of the lenders, or $10.5 million. We are currently undergoing a borrowing base redetermination and expect that the borrowing base and aggregate commitments of the lenders will be reduced due in part to the April 2016 sale of the East Hoss Assets. However, we are not permitted to request any borrowings under (or issue any letters of credit pursuant to) the bank credit facility until this borrowing base redetermination is completed. We may also incur additional indebtedness in the future. Our high level of debt could have important consequences for you, including the following:


•	it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our 2017 and 2021 Notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness;


•	the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations and may limit our flexibility in operating our business;

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•

we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $28.0 million per year for interest on our 2017 and 2021 Notes alone, and to pay quarterly dividends (which we suspended beginning with the dividend payment due in April 2016), if permissable under the terms of our debt agreements and declared by our Board of Directors, on our Series B Preferred Stock of approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;


•	the amount of our interest expense may increase because certain of our borrowings in the future may be at variable rates of interest, which, if interest rates increase, could result in higher interest expense;


•	we may have a higher level of debt than some of our competitors, which may put us at a competitive disadvantage;


•	we may be more vulnerable to economic downturns and adverse developments in our industry or the economy in general, especially extended or further declines in oil and natural gas prices; and


•	our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 2017 and 2021 Notes, and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 2017 and 2021 Notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations.

To cover the costs for various obligations of lessees on the OCS, including costs for such decommissioning obligations as the plugging of wells, the removal of platforms and other facilities, the decommissioning of pipelines and the clearing of the seafloor of obstructions typically performed at the end of production, the BOEM generally requires that the lessees post substantial bonds or other acceptable financial assurances that such obligations will be met. Failure to post the requisite bonds or otherwise satisfy the BOEM’s security requirements could have a material adverse effect on our ability to operate in the U.S. Gulf of Mexico.

Because we are not exempt from the BOEM’s supplemental bonding requirements, we engage a number of surety companies to post the requisite bonds. Pursuant to the terms of our agreements with these surety companies, we are required to post collateral at the outset of the agreement or subsequently on demand, the amount of which typically may be increased at the surety companies’ discretion. Two of our surety companies have requested that we post collateral to support certain of the bonds that are issued on our behalf. We are currently evaluating various options for posting the requested collateral, however, given the effect of current commodity prices on our liquidity and creditworthiness we cannot assure you that we will be able to satisfy current or future demands for collateral for the requisite bonds or comply with new supplemental bonding requirements. If we fail to do so, we may be in default under our agreements with the surety companies, which in turn could cause a cross-default under our bank credit facility and potentially the indenture governing our 2021 Notes.

We may be required to provide letters of credit to support the additional collateral or bonding requirements requested by the BOEM or the surety companies. Such letters of credit would likely be issued under our bank credit facility (subject to availability thereunder) and would reduce the amount of borrowings available under such facility in the amount of any such letter of credit obligations. We can provide no assurance that we can continue to obtain bonds or other surety in all cases given these new expenses, and if we are unable to obtain the additional required bonds or the increased amount of required collateral as requested, the BOEM may require any or all of our operations on federal leases to be suspended or canceled or otherwise impose monetary penalties, and any one or more of such actions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.

Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unevaluated properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and

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natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders' equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unevaluated properties periodically to determine whether impairment has occurred. The risk that we will be required to recognize further write-downs of the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unevaluated property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized a ceiling test write-down of approximately $18.9 million during the three months ended March 31, 2016. Utilizing current strip prices for oil and gas prices for the second quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of June 30, 2016, we expect to recognize an additional ceiling test write-down of $10 million to $20 million in the second quarter of 2016.

Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at March 31, 2016 are in the form of swaps placed with the commodity trading branches of JPMorgan Chase Bank and The Bank of Nova Scotia, both of which participate in our bank credit facility. We cannot assure you that these or future counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may also limit the benefit we could receive from increases in the market or spot prices for oil and natural gas.

For the three months ended March 31, 2016, our total oil and gas sales included additions related to the settlement of gas hedges of $1.0 million, which in total represented 6% of our total oil and gas sales for the three month period. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. In addition, at March 31, 2016, we had approximately 1.8 Bcf of gas volumes hedged for the remainder of 2016. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted.

Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended March 31, 2016.



	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program	Maximum Number (or Approximate Dollar Value) of Shares that May be Purchased Under the Plans or Programs
January 1 - January 31, 2016	2,399	$	0.37	—	—
February 1 - February 29, 2016	1,339	0.49		—	—
March 1 - March 31, 2016	—	$	—	—	—
Total	3,738	$	0.41	—	—

________________________


(1)	All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.

We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. We are currently restricted from paying dividends on our common stock by our bank credit facility, the indenture governing the 2021 Notes and, in some circumstances, by the terms of our Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

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Item 3. DEFAULTS UPON SENIOR SECURITIES

The Company's Board of Directors did not declare a dividend on the Company's 6.875% Series B Cumulative Convertible Perpetual Preferred Stock for the quarterly period ended April 15, 2016. As of the date of this report, the Company had dividends in arrears of approximately $1.3 million.

Item 4. MINE SAFETY DISCLOSURES

NONE.

Item 5. OTHER INFORMATION

NONE.

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Item 6. EXHIBITS

Exhibit 3.1, Bylaws of PetroQuest Energy, Inc., as amended of February 19, 2016 (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed February 22, 2016)

Exhibit 4.1, Fourth Supplemental Indenture, dated February 1, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and U.S. Bank National Association, as successor trustee to The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed on February 3, 2016).

Exhibit 4.2, Indenture, dated February 17, 2016, between PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and Wilmington Trust, National Association (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed on February 18, 2016).

Exhibit 4.3, Registration Rights Agreement, dated February 17, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and Seaport Global Securities LLC, as representative of the several investors named therein (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on February 18, 2016).

Exhibit 10.1, Thirteenth Amendment to Credit Agreement dated as of January 25, 2016, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on January 26, 2016).

Exhibit 10.2, Collateral Trust Agreement, dated February 17, 2016, among PetroQuest Energy, Inc., the guarantors from time to time party thereto, Wilmington Trust, National Association, as Trustee, the other Parity Lien Debt Representatives from time to time party thereto and Wilmington Trust, National Association, as Collateral Trustee (incorporated herein by reference to exhibit 10.1 to Form 8-K filed on February 18, 2016).

Exhibit 10.3, Intercreditor Agreement, dated February 17, 2016, by and between JPMorgan Chase Bank, N.A., as Priority Lien Agent, and Wilmington Trust, National Association, as Second Lien Collateral Trustee (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed on February 18, 2016).

Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 101.INS, XBRL Instance Document

Exhibit 101.SCH, XBRL Taxonomy Extension Schema Document.

Exhibit 101.CAL, XBRL Taxonomy Extension Calculation Linkbase Document.

Exhibit 101.DEF, XBRL Taxonomy Definitions Linkbase Document

Exhibit 101.LAB, XBRL Taxonomy Extension Label Linkbase Document.

Exhibit 101.PRE, XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURE

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.



		PETROQUEST ENERGY, INC.

Date:	May 4, 2016	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief Financial Officer (Authorized Officer and Principal Financial and Accounting Officer)

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