10-Q

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: September 30, 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 October 28, 2016 there were 21,188,309 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

	Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2016 and December 31, 2015	1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2016 and 2015	2
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2016 and 2015	3
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2016 and 2015	4
Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	15
Item 3. Quantitative and Qualitative Disclosures About Market Risk	23
Item 4. Controls and Procedures	24
Part II. Other Information
Item 1. Legal Proceedings	24
Item 1A. Risk Factors	25
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	31
Item 3. Defaults upon Senior Securities	31
Item 4. Mine Safety Disclosures	31
Item 5. Other Information	31
Item 6. Exhibits	32

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	September 30, 2016			December 31, 2015
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	33,774		$	148,013
Revenue receivable	11,850			6,476
Joint interest billing receivable	22,217			49,374
Derivative asset	—			1,508
Other current assets	4,247			3,874
Total current assets	72,088			209,245
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,325,114			1,310,891
Unevaluated oil and gas properties	8,058			12,516
Accumulated depreciation, depletion and amortization	(1,237,490		)	(1,157,455		)
Oil and gas properties, net	95,682			165,952
Other property and equipment	11,252			11,229
Accumulated depreciation of other property and equipment	(10,199		)	(8,737		)
Total property and equipment	96,735			168,444
Other assets, net of accumulated amortization of $0 and $3,842, respectively	5,546			1,630
Total assets	$	174,369		$	379,319
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	46,166		$	97,999
Advances from co-owners	377			16,118
Oil and gas revenue payable	29,906			18,911
Accrued interest	397			11,720
Asset retirement obligation	1,132			6,015
Derivative liability	228			—
Accrued acquisition costs	5,000			4,409
10% Senior Unsecured Notes due 2017	22,538			—
Other accrued liabilities	2,481			3,612
Total current liabilities	108,225			158,784
10% Senior Unsecured Notes due 2017	—			347,008
10% Senior Secured Notes due 2021	15,286			—
10% Senior Secured PIK Notes due 2021	243,106			—
Asset retirement obligation	40,593			36,541
Other long-term liabilities	3,969			53
Commitments and contingencies
Stockholders’ equity:
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 21,115 and 16,410 shares, respectively	21			16
Paid-in capital	304,445			290,432
Accumulated other comprehensive (loss) income	(228		)	947
Accumulated deficit	(541,049		)	(454,463		)
Total stockholders’ equity	(236,810		)	(163,067		)
Total liabilities and stockholders’ equity	$	174,369		$	379,319

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Revenues:
Oil and gas sales	$	17,094		$	26,872		$	50,238		$	92,873
Expenses:
Lease operating expenses	6,857			10,070			21,898			32,163
Production taxes	319			399			609			2,303
Depreciation, depletion and amortization	6,030			13,687			23,361			52,686
Ceiling test write-down	8,665			40,212			40,304			214,618
General and administrative	8,827			4,686			21,297			16,544
Accretion of asset retirement obligation	670			825			1,896			2,507
Interest expense	7,737			8,526			22,497			24,996
	39,105			78,405			131,862			345,817
Other income (expense):
Gain on sale of oil and gas properties	—			828			—			22,359
Other income (expense)	(28		)	88			(355		)	285
	(28		)	916			(355		)	22,644
Loss from operations	(22,039		)	(50,617		)	(81,979		)	(230,300		)
Income tax expense (benefit)	(18		)	6			543			1,079
Net loss	(22,021		)	(50,623		)	(82,522		)	(231,379		)
Preferred stock dividend	1,285			1,287			4,064			3,854
Loss available to common stockholders	$	(23,306	)	$	(51,910	)	$	(86,586	)	$	(235,233	)
Loss per common share:
Basic
Net loss per share	$	(1.31	)	$	(3.19	)	$	(4.97	)	$	(14.50	)
Diluted
Net loss per share	$	(1.31	)	$	(3.19	)	$	(4.97	)	$	(14.50	)
Weighted average number of common shares:
Basic	17,736			16,259			17,412			16,225
Diluted	17,736			16,259			17,412			16,225

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income (Loss)

(unaudited)

(Amounts in Thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2016			2015
Net loss	$	(22,021	)	$	(50,623	)	$	(82,522	)	$	(231,379	)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $0, $6, $561 and $1,105, respectively	245			(10		)	(1,175		)	(1,866		)
Comprehensive loss	$	(21,776	)	$	(50,633	)	$	(83,697	)	$	(233,245	)

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Nine Months Ended
	September 30,
	2016			2015
Cash flows from operating activities:
Net loss	$	(82,522	)	$	(231,379	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Deferred tax expense	543			1,079
Depreciation, depletion and amortization	23,361			52,686
Ceiling test writedown	40,304			214,618
Accretion of asset retirement obligation	1,896			2,507
Share-based compensation expense	1,361			4,022
Amortization costs and other	1,990			1,679
Payments to settle asset retirement obligations	(2,884		)	(1,826		)
Gain on sale of oil and gas properties	—			(22,359		)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	10,073			—
Changes in working capital accounts:
Revenue receivable	(5,374		)	7,818
Joint interest billing receivable	26,800			20,147
Accounts payable and accrued liabilities	(45,904		)	(36,630		)
Advances from co-owners	(15,741		)	12,031
Other	(5,640		)	(414		)
Net cash (used in) provided by operating activities	(51,737		)	23,979
Cash flows provided by investing activities:
Investment in oil and gas properties	(22,084		)	(75,818		)
Investment in other property and equipment	(23		)	(430		)
Sale of oil and gas properties	24,832			271,891
Net cash provided by investing activities	2,725			195,643
Cash flows used in financing activities:
Net proceeds for share based compensation	130			422
Deferred financing costs	(373		)	(861		)
Payment of preferred stock dividend	(1,285		)	(3,854		)
Redemption of 2017 Notes	(53,626		)	—
Costs incurred to issue 2021 Notes and 2021 PIK Notes	(10,073		)	—
Proceeds from bank borrowings	—			70,000
Repayment of bank borrowings	—			(145,000		)
Net cash used in financing activities	(65,227		)	(79,293		)
Net (decrease) increase in cash and cash equivalents	(114,239		)	140,329
Cash and cash equivalents, beginning of period	148,013			18,243
Cash and cash equivalents, end of period	$	33,774		$	158,572
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest	$	33,114		$	36,137
Income taxes	$	(18	)	$	(26	)

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Basis of Presentation

The consolidated financial information for the three and nine month periods ended September 30, 2016 and 2015, have been prepared by the Company and were 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 September 30, 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 $22.4 million. 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 in connection with a potential joint venture. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. The Company is no longer pursuing a joint venture with this party and will be required to repurchase the non-producing assets for $5.0 million on or before December 31, 2016. This purchase obligation is reflected as accrued acquisition costs in the Consolidated Balance Sheet.

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. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

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Note 3—Equity

Common Stock

On May 18, 2016, the Company effected a reverse split of the Company's common stock at a ratio of one share of newly issued common stock for each four shares of issued and outstanding common stock (the "Reverse Split"). The purpose of the Reverse Split was to increase the per share trading price of the Company's common stock in order to regain compliance with the New York Stock Exchange continued listing standards. The Reverse Split proportionately reduced the total number of outstanding shares of common stock from approximately 70.1 million shares to approximately 17.5 million shares. All references in the consolidated financial statements and notes to consolidated financial statements to the number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the Reverse Split.

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.

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.

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 suspended 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. As of September 30, 2016, the Company has deferred two dividend payments and has accrued a $3.9 million payable related to the two deferred payments and the third quarter 2016 dividend that was payable on October 15, 2016, which is included in other long-term liabilities on the Consolidated Balance Sheet. 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 0.8608 shares of the Company’s common stock (which is based on a conversion price of approximately $58.08 per share of common stock as adjusted for the Reverse Split, subject to further 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.

6

Note 4—Earnings Per Share

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

For the Three Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(23,306	)	17,736	$	(1.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(23,306	)	17,736	$	(1.31	)
For the Nine Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(86,586	)	17,412	$	(4.97	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(86,586	)	17,412	$	(4.97	)
For the Three Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(51,910	)	16,259	$	(3.19	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(51,910	)	16,259	$	(3.19	)
For the Nine Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(235,233	)	16,225	$	(14.50	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(235,233	)	16,225	$	(14.50	)

An aggregate of 0.7 million and 0.2 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 1.3 million shares were not included in the computation of diluted earnings per share for the three month periods ended September 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

An aggregate of 0.7 million and 0.4 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 1.3 million shares were not included in the computation of diluted earnings per share for the nine months endedSeptember 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

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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 "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. The February 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 February 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 1.1 million shares of its common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On August 25, 2016, the Company announced the commencement of private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. The September Exchange closed on September 27, 2016, and in satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of its common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Interest on the 2021 PIK Notes will accrue from September 27, 2016. Following the consummation of the September Exchange, there is $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

Unless the Company exercises its payable in kind ("PIK") interest option, the 2021 PIK Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year, starting on February 15, 2017. The Company may, at its option, for one or more of the first three interest payment dates of the 2021 PIK Notes, pay interest at (i) the annual rate of 1% per annum in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. As of the date hereof, the Company is in compliance with all of the covenants under the 2021 PIK Notes.

The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year. As of the date hereof, the Company is in compliance with all of the covenants under the 2021 Notes.

The 2017 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on March 1 and September 1 of each year and the 2017 Notes mature on September 1, 2017. On September 23, 2016, the Company made the interest payment that was due on September 1, 2016 with respect to the 2017 Notes, which payment was made prior to the expiration of the 30 day grace period for payment of interest under the indenture governing the 2017 Notes. As of the date hereof, the Company is in compliance with the remaining covenants under the 2017 Notes.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") section 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million is reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall will be amortized under the effective interest method as an addition of interest expense over the term of the 2021 PIK Notes.

The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes, and

8

will be amortized under the effective interest method as a reduction of interest expense over the term of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the term of the 2021 Notes. At September 30, 2016, $1.2 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.6 million and $1.4 million of amortization expense as a reduction to interest expense during the three and nine months ended September 30, 2016, respectively.

The indentures governing the 2021 PIK Notes and the 2021 Notes contain affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 PIK Notes and 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 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company.

The 2021 PIK Notes and the 2021 Notes are secured equally and ratably 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 Multidraw Term Loan 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 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.

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 $0.1 million and $3.0 million of related financing costs at September 30, 2016 and December 31, 2015, respectively. The 2021 Notes are reflected net of $0.1 million of related financing costs as of September 30, 2016.

The following table reconciles the face value of the 2017 Notes, 2021 Notes and 2021 PIK Notes to the carrying value included in the Company's Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016									December 31, 2015
	2017 Notes			2021 Notes			2021 PIK Notes			2017 Notes			2021 Notes		2021 PIK Notes
Face Value	$	22,650		$	14,177		$	243,468		$	350,000		$	—	$	—
Deferred Financing Costs	(112		)	(109		)	—			(2,992		)	—		—
Excess (shortfall) Carrying Value	—			1,218			(605		)	—			—		—
Accrued PIK Interest	$	—		$	—		$	243		$	—		$	—	$	—
Carrying Value	$	22,538		$	15,286		$	243,106		$	347,008		$	—	$	—

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) terminated the credit agreement with JPMorgan Chase Bank, N.A. (as amended, the “Credit Agreement”).

On October 17, 2016, the Company entered into the Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the Credit Agreement. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes.

The Term Loans mature on October 17, 2020. As of the date hereof, the Company had $10 million of borrowings outstanding under the Term Loans.

The Company’s obligations under the Multidraw Term Loan Agreement and the Term Loans are secured by a first priority lien on substantially all of the assets of the Company and certain of its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the oil and gas properties of the Company and its subsidiaries, a pledge of the equity interests of the Borrower and certain of the Company’s other subsidiaries, and corporate guarantees of the Company and certain of the Company’s other subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.

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The Company and its subsidiaries are subject to a restrictive financial covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of the Company’s and its subsidiaries’ oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than (a) 1.7 to 1.0 as measured on December 31, 2016, and March 31, 2017, and (b) 2.0 to 1.0 as measured on June 30, 2017, and the last day of each calendar quarter thereafter (the "Coverage Ratio")

Sales of the Company’s and its subsidiaries’ oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits the Company from declaring and paying dividends on its Series B Preferred Stock.

The Multidraw Term Loan 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. As of the date hereof, no default or event of default exists under the Multidraw Term Loan Agreement and the Company was in compliance with all covenants contained in the Multidraw Term Loan Agreement including the Coverage Ratio.

Note 6—Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2016			2015
Asset retirement obligation, beginning of period	$	42,556		$	54,970
Liabilities incurred	—			392
Liabilities settled	(2,943		)	(1,826		)
Accretion expense	1,896			2,507
Revisions in estimates	291			(5,345		)
Divestiture of oil and gas properties	(75		)	(2,103		)
Asset retirement obligation, end of period	41,725			48,595
Less: current portion of asset retirement obligation	(1,132		)	(5,378		)
Long-term asset retirement obligation	$	40,593		$	43,217

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 unevaluated 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, June 30, 2016 and September 30, 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, $2.15 and $2.19 per Mcf of natural gas, $45.92, $42.12 and $39.97 per barrel of oil and $1.91, $1.71 and $1.66 per Mcfe of Ngl, respectively. 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 ceiling test write-downs of approximately $18.9 million, $12.8 million and $8.7 million during the three months ended March 31, 2016, June 30, 2016 and September 30, 2016, respectively. The Company’s cash flow hedges in place at March 31, 2016, June 30, 2016 and September 30, 2016 decreased the ceiling test write-downs by approximately $0.8 million, $0.2 million and $0.1 million, respectively.

At March 31, 2015, June 30, 2015 and September 30, 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, $3.20

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and $2.89 per Mcf of natural gas, $81.33, $71.27 and $59.71 per barrel of oil and $3.52, $3.35 and $2.70 per Mcfe of Ngl, respectively. 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 ceiling test write-downs of approximately $108.9 million, $65.5 million and $40.2 million during the three months ended March 31, 2015, June 30, 2015 and September 30, 2015, respectively. The Company's cash flow hedges in place at March 31, 2015 and June 30, 2015 increased the ceiling test write-downs by approximately $14 million and $1 million, respectively, and the Company's cash flow hedges in place at September 30, 2015 decreased the ceiling test write-down by approximately $2.2 million.

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 September 30, 2016, the Company's derivative instrument was designated as an effective cash flow hedge.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($144,000) and $3,603,000, oil hedges of $0 and $299,000 and Ngl hedges of $0 and $191,000 for the three months endedSeptember 30, 2016 and 2015, respectively. Oil and gas sales include additions related to the settlement of gas hedges of $2,043,000 and $10,108,000, oil hedges of $0 and $38,000 and Ngl hedges of $0 and $348,000 for the nine months ended September 30, 2016 and 2015, respectively.

As of September 30, 2016, the Company had entered into the following commodity derivative instrument:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
October 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

At September 30, 2016, the Company had recognized an accumulated other comprehensive loss of approximately $0.2 million related to the estimated fair value of its effective cash flow hedge. Based on estimated future commodity prices as of September 30, 2016, the Company would reclassify approximately $0.1 million, net of taxes, of accumulated other comprehensive loss into earnings during the next three months. This derivative instrument was terminated in October 2016 and the accumulated other comprehensive loss was recognized in earnings.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2016 and December 31, 2015:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2016	Derivative liability	$	(228	)
December 31, 2015	Derivative asset	$	1,508

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2016 and 2015:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2016	$	101	Oil and gas sales	$	(144	)
Commodity Derivatives at September 30, 2015	$	4,077	Oil and gas sales	$	4,093

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Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 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 September 30, 2016	$	307	Oil and gas sales	$	2,043
Commodity Derivatives at September 30, 2015	$	7,523	Oil and gas sales	$	10,494

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;

• 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 instrument at September 30, 2016 was in the form of a swap based on NYMEX pricing for natural gas. The fair value of this derivative 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 September 30, 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:
September 30, 2016	$	—	$	(228	)	$	—
December 31, 2015	$	—	$	1,508		$	—

The fair value of the Company's cash and cash equivalents approximated book value at September 30, 2016 and December 31, 2015. The fair value of the 2017 Notes, 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The following table summarizes the valuation of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016								December 31, 2015
	Fair Value		Face Value		Carrying Value				Fair Value		Face Value		Carrying Value
2017 Notes	$	18,799	$	22,650	$	22,538			$	238,000	$	350,000	$	347,008
2021 Notes	10,349		14,177		15,286		(1	)	—		—		—
2021 PIK Notes	165,558		243,468		243,106		(1	)	—		—		—
	$	194,706	$	280,295	$	280,930			$	238,000	$	350,000	$	347,008

(1) The carrying value of the 2021 Notes and 2021 PIK Notes includes the effect of the troubled debt restructurings described in Note 5.

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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 $174.9 million as of September 30, 2016.

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 September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of June 30, 2016	$	(297	)	$	(176	)	$	(473	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	101			—			101
Income tax effect	(37		)	91			54
Net of tax	64			91			155
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	144			—			144
Income tax effect	(54		)	—			(54		)
Net of tax	90			—			90
Net other comprehensive income	154			91			245
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	307			—			307
Income tax effect	(114		)	(85		)	(199		)
Net of tax	193			(85		)	108
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(2,043		)	—			(2,043		)
Income tax effect	760			—			760
Net of tax	(1,283		)	—			(1,283		)
Net other comprehensive loss	(1,090		)	(85		)	(1,175		)
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

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The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2015	$	3,564
Other comprehensive income before reclassifications:
Change in fair value of derivatives	4,077
Income tax effect	(1,517		)
Net of tax	2,560
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,093		)
Income tax effect	1,523
Net of tax	(2,570		)
Net other comprehensive loss	(10		)
Balance as of September 30, 2015	$	3,554

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$	5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	7,523
Income tax effect	(2,799		)
Net of tax	4,724
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(10,494		)
Income tax effect	3,904
Net of tax	(6,590		)
Net other comprehensive loss	(1,866		)
Balance as of September 30, 2015	$	3,554

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, Louisiana and the shallow waters of the Gulf of Mexico. 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.

Our liquidity position has been negatively impacted by the prolonged decline in commodity prices that began in late 2014. In response to lower commodity prices we have taken the following actions during 2015 and 2016 aimed at preserving liquidity, reducing overall debt levels and extending debt maturities:

• Completed the sale of substantially all of our interests in Oklahoma for $278 million;

• Reduced our 2016 capital expenditure budget to between $15 million and $20 million, as compared to 2015 spending of approximately $65 million;

• Suspended the quarterly dividend on our outstanding Series B Preferred Stock saving $5.1 million annually;

• Completed two debt exchanges reducing debt maturing in 2017 from $350 million to $22.7 million;

• Reduced total debt 34% from $425 million at December 31, 2014 to $280.3 million at September 30, 2016;

• Entered into a new $50 million Multidraw Term Loan Agreement maturing in 2020; and

• Launched a process to secure a drilling joint venture in East Texas.

In addition to extending the maturity on approximately $113 million of debt due in 2017 to 2021, our September Exchange permits us to reduce our cash interest expense on $243.5 million of debt from 10% cash to 1% cash and 9% payment-in-kind for the first three semi-annual interest payments, which is expected to provide us with more than $30 million of cash interest savings during 2017 and 2018. To enhance our liquidity and provide capital to address the remaining 2017 Notes, in October 2016, we entered into a new $50 million Multidraw Term Loan Agreement maturing in 2020, replacing our prior bank credit facility which had no borrowing base on the date of termination. We currently have a more favorable outlook on oil and gas prices for 2017 than what we experienced in 2016. We expect to recomplete our Thunder Bayou well in South Louisiana into a larger sand package and to finalize our East Texas joint venture and commence the related drilling program before the end of 2016. As a result, we expect to begin growing production during 2017 as compared to the production expected during the fourth quarter of 2016.

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

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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 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.

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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).

Our hedges are specifically referenced to NYMEX prices for natural gas. 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 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 prices at which the hedges will be settled. At September 30, 2016, our derivative instrument was designated as an effective cash flow hedge.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX 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 September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
Production:
Oil (Bbls)	123,165		123,102		377,473		421,539
Gas (Mcf)	3,650,109		5,395,789		13,470,406		20,478,563
Ngl (Mcfe)	838,294		1,297,566		3,130,784		4,458,392
Total Production (Mcfe)	5,227,393		7,431,967		18,866,028		27,466,189
Sales:
Total oil sales	$	5,380,110	$	6,073,709	$	14,675,611	$	21,613,942
Total gas sales	9,873,068		17,737,112		29,444,803		59,314,437
Total ngl sales	1,840,764		3,060,948		6,117,868		11,944,564
Total oil, gas, and ngl sales	$	17,093,942	$	26,871,769	$	50,238,282	$	92,872,943
Average sales prices:
Oil (per Bbl)	$	43.68	$	49.34	$	38.88	$	51.27
Gas (per Mcf)	2.70		3.29		2.19		2.90
Ngl (per Mcfe)	2.20		2.36		1.95		2.68
Per Mcfe	3.27		3.62		2.66		3.38

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of ($144,000) and $3,603,000, oil hedges of $0 and $299,000 and Ngl hedges of $0 and $191,000 for the three months endedSeptember 30, 2016 and 2015, respectively. The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of $2,043,000 and $10,108,000, oil hedges of $0 and $38,000 and Ngl hedges of $0 and $348,000 for the nine months endedSeptember 30, 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 $23,306,000 and $51,910,000 for the quarters ended September 30, 2016 and 2015, respectively, while net loss available to common stockholders totaled $86,586,000 and $235,233,000 for the nine months endedSeptember 30, 2016 and 2015, respectively. The primary fluctuations were as follows:

Production Total production decreased30% and 31% during the three and nine month periods ended September 30, 2016, respectively, as compared to the 2015 periods. The decreases in total production were primarily the result of the divestment of substantially all of our Oklahoma assets and normal production declines at our Gulf Coast and East Texas fields. Partially offsetting

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these decreases was the successful completion of our Thunder Bayou discovery, which commenced production in June 2015 as well as successful recompletions and workovers at several of our Gulf of Mexico wells.

Due to the 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. However, we expect to recomplete our Thunder Bayou well into a larger sand package and to finalize our East Texas joint venture and commence the related drilling program before the end of 2016. As a result, we expect to begin increasing production during 2017 as compared to the production expected during the fourth quarter of 2016.

Gas production during the three and nine month periods ended September 30, 2016decreased32% and 34%, respectively, from the comparable periods in 2015. The decreases were primarily the result of our 2015 and 2016 Oklahoma divestments and normal production declines at our Gulf Coast and East Texas fields. Partially offsetting these decreases was the successful completion of our Thunder Bayou discovery. 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 and substantial decrease in capital spending.

Oil production during the nine month period ended September 30, 2016decreased10% from the 2015 period due primarily to normal production declines at our Gulf Coast and East Texas fields. Partially offsetting these decreases was an increase due to the commencement of production at our Thunder Bayou discovery in June 2015 and successful recompletions and workovers at several of our Gulf of Mexico wells. As a result of normal production declines and the substantial decrease in capital spending, we expect our average daily oil production to continue to decrease during the remainder of 2016 as compared to 2015.

Ngl production during the three and nine month periods ended September 30, 2016decreased35% and 30%, respectively, from the respective 2015 periods primarily due to our 2015 and 2016 Oklahoma divestments and normal production declines at certain of our Gulf Coast and East Texas fields. Additionally, Ngl production declined at several of our fields in the Gulf Coast where we decided to cease processing until prices improve for the residual products. Offsetting these decreases was the successful completion of our Thunder Bayou discovery. We expect our average daily Ngl production to continue 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 and substantial decrease in capital spending.

Prices Including the effects of our hedges, average gas prices per Mcf for the three and nine month periods ended September 30, 2016 were $2.70 and $2.19, respectively, as compared to $3.29 and $2.90 for the respective 2015 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2016 were $43.68 and $38.88, respectively, as compared to $49.34 and $51.27 for the respective 2015 periods and average Ngl prices per Mcfe were $2.20 and $1.95 for the three and nine months ended September 30, 2016, respectively, as compared to $2.36 and $2.68 for the respective 2015 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2016 were 10% and 21%lower, respectively, than the prices received during the comparable 2015 periods.

Revenue Including the effects of hedges, oil and gas sales during the three months endedSeptember 30, 2016decreased36% to $17,094,000, as compared to oil and gas sales of $26,872,000 during the 2015 period. Including the effects of hedges, oil and gas sales during the nine months endedSeptember 30, 2016decreased46% to $50,238,000, as compared to oil and gas sales of $92,873,000 during the 2015 period. These decreases were 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 and nine months ended September 30, 2016 totaled $6,857,000 and $21,898,000, respectively, as compared to $10,070,000 and $32,163,000 during the respective 2015 periods. Per unit lease operating expenses totaled $1.31 and $1.16 per Mcfe, respectively, during the three and nine month periods ended September 30, 2016 as compared to $1.35 and $1.17 per Mcfe during the respective 2015 periods. Total lease operating expenses decreased during the three and nine months ended September 30, 2016 primarily as a result of our Oklahoma divestitures. As a result of our 2015 and 2016 Oklahoma divestitures, we expect total lease operating expenses during the remainder of 2016 to decrease as compared to 2015.

Production taxes for the three and nine months ended September 30, 2016 totaled $319,000 and $609,000, respectively, as compared to $399,000 and $2,303,000, respectively, during the 2015 periods. Per unit production taxes totaled $0.06 and $0.03 per Mcfe, respectively, during the three and nine month periods ended September 30, 2016 as compared to $0.05 and $0.08 per Mcfe, respectively, during the comparable 2015 periods. The decreases in production taxes were primarily due to lower commodity prices for our production during the 2016 periods as compared to the 2015 periods as severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. Additionally, during the second quarter of 2016 we received production tax refunds on certain of our East Texas wells which qualified for a gas tax credit. 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 continued decrease in our total and per unit production taxes during 2016 as compared to 2015.

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General and administrative expenses during the three and nine months ended September 30, 2016 totaled $8,827,000 and $21,297,000, respectively, as compared to $4,686,000 and $16,544,000 during the 2015 periods. General and administrative expenses during the three and nine months ended September 30, 2016 included $5,244,000 and $10,073,000, respectively, of costs related to the issuance of the 2021 Notes and 2021 PIK Notes. ASC Topic 470-60 "Troubled Debt Restructurings by Debtors" requires financing costs related to a troubled debt restructuring to be expensed in the period incurred. Offsetting this increase were lower employee related costs, including share-based compensation. Included in general and administrative expenses for the three and nine month periods ended September 30, 2016 were share-based compensation costs of $464,000 and $1,558,000, respectively, compared to $988,000 and $3,940,000, respectively, during the 2015 periods. We capitalized $1,268,000 and $4,347,000, respectively, of general and administrative expenses during the three and nine month periods ended September 30, 2016 compared to $1,926,000 and $6,522,000, respectively, during the 2015 periods. We expect total general and administrative expenses during the fourth quarter of 2016 to be lower than the comparable 2015 period.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and nine months ended September 30, 2016 totaled $5,851,000, or $1.12 per Mcfe, and $22,815,000, or $1.21 per Mcfe, respectively, as compared to $13,318,000, or $1.79 per Mcfe, and $51,632,000, or $1.88 per Mcfe, respectively, during the comparable 2015 periods. The decreases in the per unit DD&A rate are primarily the result of the recent ceiling test write-downs. As a result of current year ceiling test write-downs, we expect our DD&A rate to be lower for the remainder of 2016.

At March 31, 2016, June 30, 2016 and September 30, 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, $2.15 and $2.19 per Mcf of natural gas, $45.92, $42.12 and $39.97 per barrel of oil and $1.91, $1.71 and $1.66 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $18.9 million, $12.8 million and $8.7 million during the three months ended March 31, 2016, June 30, 2016 and September 30, 2016, respectively. Our cash flow hedges in place at March 31, 2016, June 30, 2016 and September 30, 2016 decreased the ceiling test write-downs by approximately $0.8 million, $0.2 million and $0.1 million, respectively. At March 31, 2015, June 30, 2015 and September 30, 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, $3.20 and $2.89 per Mcf of natural gas, $81.33, $71.27 and $59.71 per barrel of oil and $3.52, $3.35 and $2.70 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $108.9 million, $65.5 million and $40.2 million during the three months ended March 31, 2015, June 30, 2015 and September 30, 2015, respectively. Our cash flow hedges in place at March 31, 2015 and June 30, 2015 increased the ceiling test write-downs by approximately $14 million and $1 million, respectively, and the Company's cash flow hedges in place at September 30, 2015 decreased the ceiling test write-down by approximately $2.2 million. 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 fourth quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of September 30, 2016, we do not expect to recognize an additional ceiling test write-down in the fourth quarter of 2016.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $7,737,000 and $22,497,000 during the three and nine months ended September 30, 2016, respectively, as compared to $8,526,000 and $24,996,000, respectively, during the 2015 periods. During the three and nine month periods ended September 30, 2016, our capitalized interest totaled $167,000 and $722,000, respectively, as compared to $724,000 and $4,100,000, respectively, during the 2015 periods. The decrease in interest expense during the 2016 periods was the result of the February Exchange, including a $1,436,000 non-cash reduction related to the amortization of the excess carrying value of the 2017 Notes tendered in the February Exchange (see Note 5 - Long-Term Debt), as well as the repayment of our bank debt in June 2015.

Income tax expense (benefit) during the three and nine months ended September 30, 2016 was ($18,000) and $543,000, respectively, as compared to income tax expense of $6,000 and $1,079,000 during the comparable 2015 periods. 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 $174,926,000 as of September 30, 2016.

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Liquidity and Capital Resources

We have historically financed our acquisition, exploration and development activities principally through cash flow from operations, borrowings from banks and other lenders, issuances of equity and debt securities, joint ventures and sales of assets. However, our liquidity position has been negatively impacted by the prolonged decline in commodity prices that began in late 2014. In response to lower commodity prices we executed a number of transactions during 2015 and 2016 aimed at preserving liquidity, reducing overall debt levels and extending debt maturities. Through these transactions, which included two debt exchanges, we have reduced debt maturing in 2017 from $350 million to $22.7 million and have reduced total debt 34% from $425 million at December 31, 2014 to $280.3 million at September 30, 2016. In addition to extending the maturity on the majority of our debt due in 2017, our September Exchange permits us to reduce our cash interest expense on $243.5 million of debt from 10% cash to 1% cash and 9% payment-in-kind for the first three semi-annual interest payments, which is expected to provide us with more than $30 million of cash interest savings during 2017 and 2018. Finally, in October 2016, we entered into a new $50 million Multidraw Term Loan Agreement maturing in 2020, replacing our prior bank credit facility, which had no borrowing base on the date of termination. The Multidraw Term Loan Agreement will provide capital for general corporate purposes, including refinancing the $22.7 million of remaining 2017 Notes. For additional information, see "Source of Capital: Debt" below.

At September 30, 2016, we had a working capital deficit of approximately $36.1 million as compared to a working capital surplus of approximately $50.5 million as of December 31, 2015. The decrease in working capital is primarily due to the $63.7 million in cash payments made in connection with the February Exchange and September Exchange and the inclusion of the 2017 Notes in current liabilities as discussed in "Source of Capital: Debt" below.

Our liquidity may be negatively impacted by federal bonding requirements related to our properties located on the Outer Continental Shelf (the "OCS"). To cover the various obligations of lessees on the OCS, the Bureau of Ocean Energy Management (the"BOEM") and the Bureau of Safety and Environmental Enforcement (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 be posted to support certain of the bonds issued on our behalf and to date, we have provided cash deposits totaling $5.2 million to partially satisfy these requests. The surety companies may request additional collateral which 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 the Multidraw Term Loan Agreement and potentially the indentures governing the 2021 Notes and 2021 PIK Notes. In addition, recently updated BOEM financial assurance and risk management requirements may increase the amount of surety bonds or other security required to be provided by us. For additional information, see "Item 1A Risk Factors - We may be required to post additional collateral to satisfy the collateral requirements related to the surety bonds that secure our offshore decommissioning obligations or to increase the amount of surety bonds or other security required pursuant to updated BOEM financial assurance and risk management requirements".

Source of Capital: Operations

Net cash flow provided by (used in) operations decreased from $24.0 million during the nine months ended September 30, 2015 to ($51.7) 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 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 the February Exchange and consent solicitation (the "February Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. The February 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 February Exchange, we (i) paid approximately $53.6

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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 1.1 million shares of our common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remain outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On August 25, 2016, we announced the commencement of private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes and 2021 Notes. The September Exchange closed on September 27, 2016, and in satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the outstanding aggregate principal amount of 2021 Notes, we issued (i) $243.5 million in aggregate principal amount of our new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of our common stock. We also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Interest on the 2021 PIK Notes will accrue from September 27, 2016. Following the consummation of the September Exchange, there is $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

Unless we exercise our payable in kind ("PIK") interest option, the 2021 PIK Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year, starting on February 15, 2017. We may, at our option, for one or more of the first three interest payment dates of the 2021 PIK Notes, pay interest at (i) the annual rate of 1% per annum in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. As of the date hereof, we expect to exercise our PIK option for the payment due in February 2017 and we are in compliance with all of the covenants under the 2021 PIK Notes.

The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year. As of the date hereof, we are in compliance with all of the covenants under the 2021 Notes. The 2017 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on March 1 and September 1 of each year and the 2017 Notes mature on September 1, 2017. As of the date hereof, we are in compliance with all of the covenants under the 2017 Notes.

The indentures governing the 2021 PIK Notes and the 2021 Notes contains affirmative and negative covenants that, among other things, limit our ability and the subsidiary guarantors of the 2021 PIK Notes and 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 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain of our wholly-owned subsidiaries.

The 2021 PIK Notes and the 2021 Notes are equally and ratably secured by second-priority liens on substantially all of our and the subsidiary guarantors' oil and gas properties and substantially all of their other assets to the extent such properties and assets secure the Multidraw Term Loan 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 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.

On October 17, 2016, we entered into the Multidraw Term Loan Agreement (the “Multidraw Term Loan Agreement”) with Franklin Custodian Funds - Franklin Income Fund, as a lender, and Wells Fargo Bank, National Association, as administrative agent. The Multidraw Term Loan Agreement replaced our bank credit facility.

The Multidraw Term Loan Agreement provides a new multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes.

The Term Loans mature on October 17, 2020. As of the date hereof, we had $10 million of borrowings outstanding under the Term Loans.

Our obligations under the Multidraw Term Loan Agreement and the Term Loans are 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, a pledge of the equity interests of certain of our subsidiaries, and corporate guarantees. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.

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We are subject to a restrictive financial covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of our oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than (a) 1.7 to 1.0 as measured on December 31, 2016, and March 31, 2017, and (b) 2.0 to 1.0 as measured on June 30, 2017, and the last day of each calendar quarter thereafter (the "Coverage Ratio").

Sales of our oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits us from declaring and paying dividends on the Series B Preferred Stock.

The Multidraw Term Loan 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. As of the date hereof, no default or event of default exists under the Multidraw Term Loan Agreement and we were in compliance with all covenants contained in the Multidraw Term Loan Agreement including the Coverage Ratio.

Source of Capital: Joint Ventures

We are currently pursuing a joint venture relative to a portion of our East Texas assets. In March 2016, we sold certain non-producing assets in East Texas to a potential joint venture partner for $7.0 million. We are no longer pursuing a joint venture with this party and are required to repurchase these assets for $5.0 million on or before December 31, 2016. We expect to repurchase these assets, close the joint venture with different parties and commence drilling prior to the end of 2016. If consummated, the joint venture would enhance our drilling economics and provide capital to fund a portion of our estimated drilling and completion costs.

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 $15 million and $20 million (which from the midpoint of such range, represents a 73% reduction from our 2015 capital expenditures), of which $12.5 million was incurred during the first nine months of 2016. During the nine months ended September 30, 2016, we funded our capital expenditures with cash on hand. We plan to fund our capital expenditures during the remainder of 2016 with cash on hand as well as proceeds from our Multidraw Term Loan Agreement.

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. 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; our estimate of the sufficiency of our existing capital sources, including availability under our new multidraw term loan facility; our ability to post additional collateral to satisfy our offshore decommissioning obligations; our ability to consummate a drilling joint venture in East Texas and initiate our Cotton Valley drilling program before the end of the year; 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 raise capital to fund cash requirements for future operations; limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by our multidraw term loan facility and restrictive debt covenants; our ability to find, develop, produce oil and natural gas reserves that are economically recoverable and to replace reserves and sustain and/or increase production; approximately 50% of our production being exposed to the additional risk of severe weather, including hurricanes and tropical storms and flooding, and natural disasters; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in laws and

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governmental regulations as they relate to our operations; the operating hazards attendant to the oil and gas business; the volatility of our stock price; and 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.

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 $1.4 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 nine months ended September 30, 2016, we received$2.0 millionfrom the counterparties to our derivative instruments in connection with 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 Multidraw Term Loan Agreement requires that the counterparties to our hedge contracts be rated A-/A3 or higher by S&P or Moody's. Currently, the counterparty to our existing hedge contract is Shell Trading Risk Management LLC.

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As of September 30, 2016, we had entered into the following commodity derivative instrument:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
October 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

During October 2016, we terminated this contract and entered into the following commodity derivative instrument:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
2017	Swap	5,000 Mmbtu	$3.25

For further discussion of our commodity derivative instruments, please see Item 1, Note 8 "Derivative Instruments" in this Form 10-Q.

Interest Rate Risk

As of September 30, 2016, we had no debt subject to variable interest rates.

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:

i. 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

The Company is involved in litigation relating to claims arising out of its operations in the normal course of business, including worker's compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Although we cannot predict the outcome of these proceedings with certainty, management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on the Company’s business or financial position.

Other then as set forth below, there have been no significant changes with respect to the legal matters disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.

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On May 27, 2016, the Company was named as a defendant in a putative class action lawsuit filed on behalf of holders of the 2017 Notes in the U.S. District Court for the Southern District of New York. The lawsuit alleges that, as a result of the February Exchange, the Company violated the Trust Indenture Act of 1939, the indenture governing the 2017 Notes and the implied covenant of good faith and fair dealing by benefiting itself and a minority of noteholders who are qualified institutional buyers ("QIBs"). According to the lawsuit, as a result of the February Exchange in which only QIBs (and non-U.S. persons under Regulation S) were eligible to participate, the Company unjustly enriched itself at the expense of class members by reducing indebtedness, extending the maturity date of its long term debt and reducing the value of the 2017 Notes. The lawsuit seeks damages and attorney's fees, in addition to declaratory relief that the debt exchange and the liens created for the benefit of the 2021 Notes are null and void and that the debt exchange effectively resulted in a default under the indenture for the 2017 Notes. In August 2016, the lawsuit was transferred to the U.S. District Court for the Western District of Louisiana.

On October 11, 2016, the Company’s subsidiary, PetroQuest Energy, L.L.C. (“PQ LLC”), and another exploration and production company were named as defendants in a putative class action lawsuit filed on behalf of royalty owners in the state district court in Hughes County, Oklahoma. The lawsuit alleges that PQ LLC and the other defendant failed to pay interest with respect to untimely royalty payments. The lawsuit seeks actual and punitive damages, an accounting, disgorgement, injunctive relief and attorney's fees.

On October 25, 2016, PQ LLC and another exploration and production company were named as defendants in a putative class action lawsuit filed on behalf of royalty owners in the U.S. District Court for the Eastern District of Oklahoma. The lawsuit alleges that PQ LLC and the other defendant underpaid royalties or did not pay royalties by various means. The lawsuit seeks actual, compensatory and punitive damages, and attorney's fees.

We continue to vigorously defend against each of these claims. At this time we are unable to express an opinion with respect to the likelihood of an unfavorable outcome or provide an estimate of potential losses, if any.

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 and September 30, 2016 as compared to December 31, 2014. For example, the SEC pricing at December 31, 2015 and September 30, 2016 for crude oil (WTI Cushing) was $50.28 and $41.53 per Bbl, respectively, and natural gas (Henry Hub) was $2.58 and $2.28 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.

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We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices has, and may continue to, 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 September 30, 2016, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $247.2 million. We currently have $40 million of additional availability under the Multidraw Term Loan Agreement, subject to compliance with the covenants contained therein. 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 Notes, 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, 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;

• we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $6.1 million per year for interest on our 2017 Notes, 2021 Notes and 2021 PIK Notes alone (assuming we elect our PIK interest option with respect to the first three semi-annual interest payments on the 2021 PIK Notes), 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;

• 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 Notes, 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, 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 Notes, 2021 Notes, 2021 PIK Notes and the Multidraw Term Loan Agreement, 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.

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To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make payments on and to refinance our indebtedness, including our 2017 Notes, 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under the Multidraw Term Loan Agreement in an amount sufficient to enable us to pay principal and interest on our indebtedness, including our 2017 Notes, 2021 Notes and 2021 PIK Notes, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, including payments on our 2017 Notes, 2021 Notes, 2021 PIK Notes and amounts borrowed under the Multidraw Term Loan Agreement, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Borrowings under the Multidraw TermLoan Agreement are subject to our compliance with a significant financial ratio.

Under the terms of the Multidraw Term Loan Agreement, our ability to borrow is based on our maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of our oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than (a) 1.7 to 1.0 as measured on December 31, 2016, and March 31, 2017, and (b) 2.0 to 1.0 as measured on June 30, 2017, and the last day of each calendar quarter thereafter. We may not be able to comply with this restrictive covenant in the future and, as a result, our ability to borrow money under the Multidraw Term Loan Agreement could be limited, in which case we would need to find other sources of liquidity including, but not limited to, negotiated renewals of our borrowings, arranging new financing or selling a portion of our assets.

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Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

The Multidraw Term Loan Agreement and the indentures governing our 2021 Notes and 2021 PIK Notes contain a number of significant covenants that, among other things, restrict or limit our ability to:    

•

pay dividends or distributions on our capital stock or issue preferred stock;

•

repurchase, redeem or retire our capital stock or subordinated debt;

•

make certain loans and investments;

•

place restrictions on the ability of subsidiaries to make distributions;

•

sell assets, including the capital stock of subsidiaries;

•

enter into certain transactions with affiliates;

•

create or assume certain liens on our assets;

•

enter into sale and leaseback transactions;

•

merge or enter into other business combination transactions;

•

enter into transactions that would result in a change of control of us; or

•

engage in other corporate activities.

Also, the Multidraw Term Loan Agreement and the indentures governing our 2021 Notes and 2021 PIK Notes require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests.

Further, these financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the Multidraw Term Loan Agreement and the indentures governing our 2021 Notes and 2021 PIK Notes impose on us.

A breach of any of these covenants or our inability to comply with the required Coverage Ratio or financial condition tests could result in a default under the Multidraw Term Loan Agreement, the 2021 Notes and the 2021 PIK Notes. A default, if not cured or waived, could result in all indebtedness outstanding under the Multidraw Term Loan Agreement, the 2021 Notes and the 2021 PIK Notes to become immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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 hedge as of October 31, 2016 is in the form of a swap placed with Shell Trading Risk Management LLC. We cannot assure you that this 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 nine months ended September 30, 2016, our total oil and gas sales included additions related to the settlement of gas hedges of $2.0 million, oil hedges of zero and Ngl hedges of zero, which in total represented 4% of our total oil and gas sales

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for the year. We cannot assure you that the hedging transaction we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices.  In addition, at October 31, 2016, we had approximately 1.8 Bcf of gas volumes hedged for 2017.  This hedge 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 hedge and our results of operations and financial condition would be negatively impacted.

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 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 be posted to support certain of the bonds issued on our behalf. To date, we have provided cash deposits totaling $5.2 million to partially satisfy these requests. The surety companies may request additional collateral which 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 the indentures governing the 2021 Notes and the 2021 PIK Notes and our Multidraw Term Loan Agreement

 In addition, on July 14, 2016, the BOEM issued a notice to lessees to clarify the procedures and criteria that the BOEM will use to determine if and when additional security is required for OCS leases. This notice, which became effective on September 12, 2016, may result in an increase to the amount of surety bonds or other security required to be posted by us pursuant to these updated BOEM financial assurance and risk management requirements.

We can provide no assurance that we can continue to obtain bonds or other surety in all cases given these new expenses and updated BOEM requirements, 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 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 ceiling test write-downs totaling approximately $266.6 million and $40.3 million during the year ended December 31, 2015 and the nine months ended September 30, 2016, respectively. Utilizing current strip prices for oil and gas prices for the fourth quarter of 2016 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of September 30, 2016, we do not expect to recognize an additional ceiling test write-down in the fourth quarter of 2016.

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We are the subject of putative class action lawsuits that may result in substantial expenditures and divert management's attention.

We are the subject of a putative securities class action lawsuit with respect to the February Exchange and two putative class actions lawsuits in Oklahoma with respect to the alleged failure to pay interest with respect to untimely royalty payments and with respect to the alleged underpayment or failure to pay royalties by various means. These lawsuits seek various remedies, including damages, injunctive relief and attorney’s fees. For additional information on these lawsuits, see Part II - Item 1. Legal Proceedings in this Form 10-Q.

Although we believe that the allegations in these lawsuits are without merit and intend to defend such litigation vigorously, litigation is subject to inherent uncertainties, and an adverse result in one of these lawsuits or other matters that may arise from time to time could have a material adverse effect on our business, results of operations and financial condition. Defending the lawsuits may be costly and, further, could require significant involvement of our senior management and may divert management's attention from our business and operations.

The terms of our debt agreements currently restrict and Delaware law may restrict us from making cash payments with respect to our Series B Preferred Stock.

Quarterly dividends and cash payments upon conversion or repurchase of our Series B preferred stock will be paid only if payment of such amounts is not prohibited by our debt agreements, such as the Multidraw Term Loan Agreement, and assets are legally available to pay such amounts. Quarterly dividends will only be paid if such dividends are declared by our board of directors. The board of directors is not obligated or required to declare quarterly dividends even if we have funds available for such purposes.

The terms of the Multidraw Term Loan Agreement currently restrict us from paying cash dividends on our Series B preferred stock. We previously suspended the cash dividend on our 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 we fail 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 our board of directors until all accumulated and unpaid dividends on the Series B preferred stock are paid in full. We plan to periodically re-evaluate the dividend payment policy, subject to the terms of our term loan facility.

If in the future we are permitted to pay such cash dividends under the terms of our existing debt agreements, including the Multidraw Term Loan Agreement, and any debt agreements that we enter into in the future, we may continue to be limited in our ability to pay cash dividends on our Series B preferred stock and our ability to make any cash payment upon conversion or repurchase of our Series B preferred stock by the terms of such debt agreements. Furthermore, if we are in default under the Multidraw Term Loan Agreement or the indentures governing the 2021 Notes or the 2021 PIK Notes, we will not be permitted to pay any cash dividends on our Series B preferred stock or make any cash payment upon conversion or repurchase of our Series B preferred stock in the absence of a waiver of such default or an amendment or refinancing of such debt agreements.

Delaware law provides that we may pay dividends on our Series B preferred stock only to the extent that assets are legally available to pay such dividends. Cash payments we may make upon repurchase or conversion of our Series B preferred stock would be generally subject to the same restrictions under Delaware law. Legally available assets is defined as the amount of surplus. Our surplus is the amount by which the fair value of total assets exceeds the sum of:

the fair value of our total liabilities, including our contingent liabilities; and

the amount of our capital.

If there is no surplus, legally available assets will mean, in the case of a dividend, our net profits for the fiscal year in which the dividend payment occurs and/or the preceding fiscal year.

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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 September 30, 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
July 1 - July 31, 2016	—	$	—	—	—
August 1 - August 31, 2016	—	—		—	—
September 1 - September 30, 2016	166	$	2.97	—	—
Total	166	$	2.97	—	—

 ________________________

(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 Multidraw Term Loan Facility, the indentures governing the 2021 Notes and the 2021 PIK 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.

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 periods starting with April 15, 2016. As of the date of this report, the Company had dividends in arrears of approximately $3.9 million.

Item 4. MINE SAFETY DISCLOSURES

NONE.

Item 5. OTHER INFORMATION

NONE.

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Item 6. EXHIBITS

Exhibit 4.1, First Supplemental Indenture, dated as of September 13, 2016, among 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 September 14, 2016).

Exhibit 4.2, Waiver of Registration Rights, dated as of September 13, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors and Seaport Global Securities LLC (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on September 14, 2016).

Exhibit 4.3, Indenture, dated September 27, 2016, among 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 September 27, 2016).

Exhibit 4.4, Registration Rights Agreement, dated September 27, 2016, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, Jefferies LLC and Seaport Global Securities LLC (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on September 27, 2016).

Exhibit 10.1, Fifteenth Amendment to Credit Agreement and Master Assignment dated as of August 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, National Association, IBERIABANK, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 25, 2016).

Exhibit 10.2, Forbearance Agreement dated September 1, 2016 by and among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy, LLC and JP Morgan Chase Bank, N.A. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on September 1, 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:	November 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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EX-31.1

EXHIBIT 31.1

I, Charles T. Goodson, certify that:

1. I have reviewed this Form 10-Q of PetroQuest Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

/s/ Charles T. Goodson                            

Charles T. Goodson

Chief Executive Officer

November 4, 2016

EX-31.2

EXHIBIT 31.2

I, J. Bond Clement, certify that:

1. I have reviewed this Form 10-Q of PetroQuest Energy, Inc.;

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

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

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

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

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

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

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

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

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

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

/s/ J. Bond Clement                        

J. Bond Clement

Chief Financial Officer

November 4, 2016

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending September 30, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Charles T. Goodson

Charles T. Goodson

Chief Executive Officer

November 4, 2016

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending September 30, 2016 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

November 4, 2016

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		21,188,309

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Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 33,774	$ 148,013
Revenue receivable	11,850	6,476
Joint interest billing receivable	22,217	49,374
Derivative asset	0	1,508
Other current assets	4,247	3,874
Total current assets	72,088	209,245
Oil and gas properties:
Oil and gas properties, full cost method	1,325,114	1,310,891
Unevaluated oil and gas properties	8,058	12,516
Accumulated depreciation, depletion and amortization	(1,237,490)	(1,157,455)
Oil and gas properties, net	95,682	165,952
Other property and equipment	11,252	11,229
Accumulated depreciation of other property and equipment	(10,199)	(8,737)
Total property and equipment	96,735	168,444
Other assets, net of accumulated amortization of $0 and $3,842, respectively	5,546	1,630
Total assets	174,369	379,319
Current liabilities:
Accounts payable to vendors	46,166	97,999
Advances from co-owners	377	16,118
Oil and gas revenue payable	29,906	18,911
Accrued interest	397	11,720
Asset retirement obligation	1,132	6,015
Derivative liability	228	0
Accrued acquisition costs	5,000	4,409
10% Senior Unsecured Notes due 2017	22,538	0
Other accrued liabilities	2,481	3,612
Total current liabilities	108,225	158,784
10% Senior Unsecured Notes due 2017	0	347,008
Asset retirement obligation	40,593	36,541
Other long-term liabilities	3,969	53
Commitments and contingencies
Stockholders’ equity:
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 21,115 and 16,410 shares, respectively	21	16
Paid-in capital	304,445	290,432
Accumulated other comprehensive (loss) income	(228)	947
Accumulated deficit	(541,049)	(454,463)
Total stockholders’ equity	(236,810)	(163,067)
Total liabilities and stockholders’ equity	174,369	379,319
10% Senior Secured Notes due 2021 | Senior Notes
Current liabilities:
10% Senior Secured Notes	15,286	0
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Current liabilities:
10% Senior Secured Notes	$ 243,106	$ 0

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Accumulated amortization	$ 0	$ 3,842
Preferred stock, par value (in dollars per share)	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	1,495,000	1,495,000
Preferred stock, shares outstanding	1,495,000	1,495,000
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	21,115,000	16,410,000
Common stock, shares outstanding	21,115,000	16,410,000
10% Senior Unsecured Notes due 2017 | Senior Notes
Stated interest rate	10.00%	10.00%
10% Senior Secured Notes due 2021 | Senior Notes
Stated interest rate	10.00%
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Stated interest rate	10.00%

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil and gas sales	$ 17,094	$ 26,872	$ 50,238	$ 92,873
Expenses:
Lease operating expenses	6,857	10,070	21,898	32,163
Production taxes	319	399	609	2,303
Depreciation, depletion and amortization	6,030	13,687	23,361	52,686
Ceiling test write-down	8,665	40,212	40,304	214,618
General and administrative	8,827	4,686	21,297	16,544
Accretion of asset retirement obligation	670	825	1,896	2,507
Interest expense	7,737	8,526	22,497	24,996
Expenses	39,105	78,405	131,862	345,817
Other income (expense):
Gain on sale of oil and gas properties	0	828	0	22,359
Other income (expense)	(28)	88	(355)	285
Other Income	(28)	916	(355)	22,644
Loss from operations	(22,039)	(50,617)	(81,979)	(230,300)
Income tax expense (benefit)	(18)	6	543	1,079
Net loss	(22,021)	(50,623)	(82,522)	(231,379)
Preferred stock dividend	1,285	1,287	4,064	3,854
Loss available to common stockholders	$ (23,306)	$ (51,910)	$ (86,586)	$ (235,233)
Basic
Net income (loss) per share (in usd per share)	$ (1.31)	$ (3.19)	$ (4.97)	$ (14.50)
Diluted
Net income (loss) per share (in usd per share)	$ (1.31)	$ (3.19)	$ (4.97)	$ (14.50)
Weighted average number of common shares:
Basic (shares)	17,736	16,259	17,412	16,225
Diluted (shares)	17,736	16,259	17,412	16,225

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (22,021)	$ (50,623)	$ (82,522)	$ (231,379)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $0, $6, $561 and $1,105, respectively	245	(10)	(1,175)	(1,866)
Comprehensive loss	$ (21,776)	$ (50,633)	$ (83,697)	$ (233,245)

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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Income tax (benefit) related to other comprehensive income due to derivatives	$ 0	$ (6)	$ (561)	$ (1,105)

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities:
Net loss	$ (82,522)	$ (231,379)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Deferred tax expense	543	1,079
Depreciation, depletion and amortization	23,361	52,686
Ceiling test writedown	40,304	214,618
Accretion of asset retirement obligation	1,896	2,507
Share-based compensation expense	1,361	4,022
Amortization costs and other	1,990	1,679
Payments to settle asset retirement obligations	(2,884)	(1,826)
Gain on sale of oil and gas properties	0	(22,359)
Costs incurred to issue 2021 Notes and 2021 PIK Notes	10,073	0
Changes in working capital accounts:
Revenue receivable	(5,374)	7,818
Joint interest billing receivable	26,800	20,147
Accounts payable and accrued liabilities	(45,904)	(36,630)
Advances from co-owners	(15,741)	12,031
Other	(5,640)	(414)
Net cash (used in) provided by operating activities	(51,737)	23,979
Cash flows provided by investing activities:
Investment in oil and gas properties	(22,084)	(75,818)
Investment in other property and equipment	(23)	(430)
Sale of oil and gas properties	24,832	271,891
Net cash provided by investing activities	2,725	195,643
Cash flows used in financing activities:
Net proceeds for share based compensation	130	422
Deferred financing costs	(373)	(861)
Payment of preferred stock dividend	(1,285)	(3,854)
Redemption of 2017 Notes	(53,626)	0
Costs incurred to issue 2021 Notes and 2021 PIK Notes	(10,073)	0
Proceeds from bank borrowings	0	70,000
Repayment of bank borrowings	0	(145,000)
Net cash used in financing activities	(65,227)	(79,293)
Net (decrease) increase in cash and cash equivalents	(114,239)	140,329
Cash and cash equivalents, beginning of period	148,013	18,243
Cash and cash equivalents, end of period	33,774	158,572
Cash paid (received) during the period for:
Interest	33,114	36,137
Income taxes	$ (18)	$ (26)

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Basis of Presentation

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial information for the three and nine month periods ended September 30, 2016 and 2015, have been prepared by the Company and were 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 September 30, 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).

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Acquisitions and Divestitures

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 $22.4 million. 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 in connection with a potential joint venture. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. The Company is no longer pursuing a joint venture with this party and will be required to repurchase the non-producing assets for $5.0 million on or before December 31, 2016. This purchase obligation is reflected as accrued acquisition costs in the Consolidated Balance Sheet.

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. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

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Equity

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Equity

Equity

Common Stock

On May 18, 2016, the Company effected a reverse split of the Company's common stock at a ratio of one share of newly issued common stock for each four shares of issued and outstanding common stock (the "Reverse Split"). The purpose of the Reverse Split was to increase the per share trading price of the Company's common stock in order to regain compliance with the New York Stock Exchange continued listing standards. The Reverse Split proportionately reduced the total number of outstanding shares of common stock from approximately 70.1 million shares to approximately 17.5 million shares. All references in the consolidated financial statements and notes to consolidated financial statements to the number of shares, per share data, restricted stock and stock option data have been retroactively adjusted to give effect to the Reverse Split.

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.

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.

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 suspended 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. As of September 30, 2016, the Company has deferred two dividend payments and has accrued a $3.9 million payable related to the two deferred payments and the third quarter 2016 dividend that was payable on October 15, 2016, which is included in other long-term liabilities on the Consolidated Balance Sheet. 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 0.8608 shares of the Company’s common stock (which is based on a conversion price of approximately $58.08 per share of common stock as adjusted for the Reverse Split, subject to further 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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Earnings Per Share

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

For the Three Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(23,306	)	17,736	$	(1.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(23,306	)	17,736	$	(1.31	)
For the Nine Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(86,586	)	17,412	$	(4.97	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(86,586	)	17,412	$	(4.97	)
For the Three Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(51,910	)	16,259	$	(3.19	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(51,910	)	16,259	$	(3.19	)
For the Nine Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(235,233	)	16,225	$	(14.50	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(235,233	)	16,225	$	(14.50	)

An aggregate of 0.7 million and 0.2 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 1.3 million shares were not included in the computation of diluted earnings per share for the three month periods ended September 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

An aggregate of 0.7 million and 0.4 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 1.3 million shares were not included in the computation of diluted earnings per share for the nine months endedSeptember 30, 2016 and 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

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Long-Term Debt

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

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 "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. The February 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 February 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 1.1 million shares of its common stock. Following the completion of the February Exchange, $135.6 million in aggregate principal amount of the 2017 Notes remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On August 25, 2016, the Company announced the commencement of private exchange offers (the "September Exchange") and a consent solicitation (the "September Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes and 2021 Notes. The September Exchange closed on September 27, 2016, and in satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the outstanding aggregate principal amount of 2021 Notes, the Company issued (i) $243.5 million in aggregate principal amount of its new 10% Second Lien Senior Secured PIK Notes due 2021 (the "2021 PIK Notes") and (ii) approximately 3.5 million shares of its common stock. The Company also paid, in cash, accrued and unpaid interest on the 2017 Notes and 2021 Notes accepted in the September Exchange from the last applicable interest payment date to, but not including, September 27, 2016. Interest on the 2021 PIK Notes will accrue from September 27, 2016. Following the consummation of the September Exchange, there is $22.7 million in aggregate principal amount of the 2017 Notes outstanding and $14.2 million in aggregate principal amount of the 2021 Notes outstanding. The September Consent Solicitation amended certain provisions of the indenture governing the 2021 Notes and amended the registration rights agreement with respect to the 2021 Notes.

Unless the Company exercises its payable in kind ("PIK") interest option, the 2021 PIK Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year, starting on February 15, 2017. The Company may, at its option, for one or more of the first three interest payment dates of the 2021 PIK Notes, pay interest at (i) the annual rate of 1% per annum in cash plus (ii) the annual rate of 9% PIK (the "PIK Interest") payable by increasing the principal amount outstanding of the 2021 PIK Notes or by issuing additional 2021 PIK Notes in certificated form. As of the date hereof, the Company is in compliance with all of the covenants under the 2021 PIK Notes.

The 2021 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on February 15 and August 15 of each year. As of the date hereof, the Company is in compliance with all of the covenants under the 2021 Notes.

The 2017 Notes bear interest at a rate of 10% per annum on the principal amount and interest is payable semi-annually in arrears on March 1 and September 1 of each year and the 2017 Notes mature on September 1, 2017. On September 23, 2016, the Company made the interest payment that was due on September 1, 2016 with respect to the 2017 Notes, which payment was made prior to the expiration of the 30 day grace period for payment of interest under the indenture governing the 2017 Notes. As of the date hereof, the Company is in compliance with the remaining covenants under the 2017 Notes.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") section 470-60 "Troubled Debt Restructurings by Debtors." The Company determined that the future undiscounted cash flows from the 2021 PIK Notes issued in the September Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes and the 2021 Notes tendered in the September Exchange. Accordingly, no gain or loss on extinguishment of debt was recognized in connection with the September Exchange. The net shortfall of the remaining carrying value of the 2017 Notes and 2021 Notes tendered as compared to the principal amount of the 2021 PIK Notes issued in the September Exchange of $0.6 million is reflected as part of the carrying value of the 2021 PIK Notes. Such shortfall will be amortized under the effective interest method as an addition of interest expense over the term of the 2021 PIK Notes.

The Company previously determined that the future undiscounted cash flows from the 2021 Notes issued in the February Exchange through the maturity date exceeded the adjusted carrying amount of the 2017 Notes tendered in the February Exchange. Accordingly, no gain on extinguishment of debt was recognized in connection with the February Exchange. The excess of the remaining carrying value of the 2017 Notes tendered over the principal amount of the 2021 Notes issued in the February Exchange of $13.9 million was reflected as part of the carrying value of the 2021 Notes. The amount of the excess carrying value attributable to the 2021 Notes tendered in the September Exchange is now reflected as part of the carrying value of the 2021 PIK Notes, and will be amortized under the effective interest method as a reduction of interest expense over the term of the 2021 PIK Notes. The excess carrying value attributable to the remaining 2021 Notes is being amortized under the effective interest method over the term of the 2021 Notes. At September 30, 2016, $1.2 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.6 million and $1.4 million of amortization expense as a reduction to interest expense during the three and nine months ended September 30, 2016, respectively.

The indentures governing the 2021 PIK Notes and the 2021 Notes contain affirmative and negative covenants that, among other things, limit the ability of the Company and the subsidiary guarantors of the 2021 PIK Notes and 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 PIK Notes and the 2021 Notes are fully and unconditionally guaranteed on a senior basis by certain wholly-owned subsidiaries of the Company.

The 2021 PIK Notes and the 2021 Notes are secured equally and ratably 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 Multidraw Term Loan 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 PIK Notes and the 2021 Notes and the guarantees are contractually subordinated to liens that secure the Multidraw Term Loan Agreement and certain other permitted indebtedness. Consequently, the 2021 PIK Notes and the 2021 Notes and the guarantees will be effectively subordinated to the Multidraw Term Loan Agreement and such other indebtedness to the extent of the value of such assets.

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 $0.1 million and $3.0 million of related financing costs at September 30, 2016 and December 31, 2015, respectively. The 2021 Notes are reflected net of $0.1 million of related financing costs as of September 30, 2016.

The following table reconciles the face value of the 2017 Notes, 2021 Notes and 2021 PIK Notes to the carrying value included in the Company's Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016									December 31, 2015
	2017 Notes			2021 Notes			2021 PIK Notes			2017 Notes			2021 Notes		2021 PIK Notes
Face Value	$	22,650		$	14,177		$	243,468		$	350,000		$	—	$	—
Deferred Financing Costs	(112		)	(109		)	—			(2,992		)	—		—
Excess (shortfall) Carrying Value	—			1,218			(605		)	—			—		—
Accrued PIK Interest	$	—		$	—		$	243		$	—		$	—	$	—
Carrying Value	$	22,538		$	15,286		$	243,106		$	347,008		$	—	$	—

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) terminated the credit agreement with JPMorgan Chase Bank, N.A. (as amended, the “Credit Agreement”).

On October 17, 2016, the Company entered into the Multidraw Term Loan Agreement (the "Multidraw Term Loan Agreement") with Franklin Custodian Funds - Franklin Income Fund ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the Credit Agreement. The Multidraw Term Loan Agreement provides a multi-advance term loan facility, with borrowing availability for three years, in a principal amount of up to $50 million. The loans drawn under the Multidraw Term Loan Agreement (collectively, the “Term Loans”) may be used to repay existing debt, to pay transaction fees and expenses, to provide working capital for exploration and production operations and for general corporate purposes.

The Term Loans mature on October 17, 2020. As of the date hereof, the Company had $10 million of borrowings outstanding under the Term Loans.

The Company’s obligations under the Multidraw Term Loan Agreement and the Term Loans are secured by a first priority lien on substantially all of the assets of the Company and certain of its subsidiaries, including a lien on all equipment and at least 90% of the aggregate total value of the oil and gas properties of the Company and its subsidiaries, a pledge of the equity interests of the Borrower and certain of the Company’s other subsidiaries, and corporate guarantees of the Company and certain of the Company’s other subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.

The Company and its subsidiaries are subject to a restrictive financial covenant under the Multidraw Term Loan Agreement, consisting of maintaining a ratio of (i) the present value, discounted at 10% per annum, of the estimated future net revenues in respect of the Company’s and its subsidiaries’ oil and gas properties, before any state, federal, foreign or other income taxes, attributable to proved developed reserves, using three-year strip prices in effect at the end of each calendar quarter, including swap agreements in place at the end of each quarter, to (ii) the sum of the outstanding Term Loans and the then outstanding commitments to provide Term Loans, that shall not be less than (a) 1.7 to 1.0 as measured on December 31, 2016, and March 31, 2017, and (b) 2.0 to 1.0 as measured on June 30, 2017, and the last day of each calendar quarter thereafter (the "Coverage Ratio")

Sales of the Company’s and its subsidiaries’ oil and gas properties outside the ordinary course of business are limited under the terms of the Multidraw Term Loan Agreement. In addition, the Multidraw Term Loan Agreement prohibits the Company from declaring and paying dividends on its Series B Preferred Stock.

The Multidraw Term Loan 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. As of the date hereof, no default or event of default exists under the Multidraw Term Loan Agreement and the Company was in compliance with all covenants contained in the Multidraw Term Loan Agreement including the Coverage Ratio.

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2016			2015
Asset retirement obligation, beginning of period	$	42,556		$	54,970
Liabilities incurred	—			392
Liabilities settled	(2,943		)	(1,826		)
Accretion expense	1,896			2,507
Revisions in estimates	291			(5,345		)
Divestiture of oil and gas properties	(75		)	(2,103		)
Asset retirement obligation, end of period	41,725			48,595
Less: current portion of asset retirement obligation	(1,132		)	(5,378		)
Long-term asset retirement obligation	$	40,593		$	43,217

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Ceiling Test

9 Months Ended

Sep. 30, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Ceiling Test

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 unevaluated 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, June 30, 2016 and September 30, 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, $2.15 and $2.19 per Mcf of natural gas, $45.92, $42.12 and $39.97 per barrel of oil and $1.91, $1.71 and $1.66 per Mcfe of Ngl, respectively. 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 ceiling test write-downs of approximately $18.9 million, $12.8 million and $8.7 million during the three months ended March 31, 2016, June 30, 2016 and September 30, 2016, respectively. The Company’s cash flow hedges in place at March 31, 2016, June 30, 2016 and September 30, 2016 decreased the ceiling test write-downs by approximately $0.8 million, $0.2 million and $0.1 million, respectively.

At March 31, 2015, June 30, 2015 and September 30, 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, $3.20 and $2.89 per Mcf of natural gas, $81.33, $71.27 and $59.71 per barrel of oil and $3.52, $3.35 and $2.70 per Mcfe of Ngl, respectively. 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 ceiling test write-downs of approximately $108.9 million, $65.5 million and $40.2 million during the three months ended March 31, 2015, June 30, 2015 and September 30, 2015, respectively. The Company's cash flow hedges in place at March 31, 2015 and June 30, 2015 increased the ceiling test write-downs by approximately $14 million and $1 million, respectively, and the Company's cash flow hedges in place at September 30, 2015 decreased the ceiling test write-down by approximately $2.2 million.

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Derivative Instruments

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

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 September 30, 2016, the Company's derivative instrument was designated as an effective cash flow hedge.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($144,000) and $3,603,000, oil hedges of $0 and $299,000 and Ngl hedges of $0 and $191,000 for the three months endedSeptember 30, 2016 and 2015, respectively. Oil and gas sales include additions related to the settlement of gas hedges of $2,043,000 and $10,108,000, oil hedges of $0 and $38,000 and Ngl hedges of $0 and $348,000 for the nine months ended September 30, 2016 and 2015, respectively.

As of September 30, 2016, the Company had entered into the following commodity derivative instrument:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
October 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

At September 30, 2016, the Company had recognized an accumulated other comprehensive loss of approximately $0.2 million related to the estimated fair value of its effective cash flow hedge. Based on estimated future commodity prices as of September 30, 2016, the Company would reclassify approximately $0.1 million, net of taxes, of accumulated other comprehensive loss into earnings during the next three months. This derivative instrument was terminated in October 2016 and the accumulated other comprehensive loss was recognized in earnings.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2016 and December 31, 2015:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2016	Derivative liability	$	(228	)
December 31, 2015	Derivative asset	$	1,508

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2016 and 2015:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2016	$	101	Oil and gas sales	$	(144	)
Commodity Derivatives at September 30, 2015	$	4,077	Oil and gas sales	$	4,093

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 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 September 30, 2016	$	307	Oil and gas sales	$	2,043
Commodity Derivatives at September 30, 2015	$	7,523	Oil and gas sales	$	10,494

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Fair Value Measurements

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value Measurements

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;

• 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 instrument at September 30, 2016 was in the form of a swap based on NYMEX pricing for natural gas. The fair value of this derivative 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 September 30, 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:
September 30, 2016	$	—	$	(228	)	$	—
December 31, 2015	$	—	$	1,508		$	—

The fair value of the Company's cash and cash equivalents approximated book value at September 30, 2016 and December 31, 2015. The fair value of the 2017 Notes, 2021 Notes and 2021 PIK Notes was determined based upon market quotes provided by an independent broker, which represents a Level 2 input. The following table summarizes the valuation of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016								December 31, 2015
	Fair Value		Face Value		Carrying Value				Fair Value		Face Value		Carrying Value
2017 Notes	$	18,799	$	22,650	$	22,538			$	238,000	$	350,000	$	347,008
2021 Notes	10,349		14,177		15,286		(1	)	—		—		—
2021 PIK Notes	165,558		243,468		243,106		(1	)	—		—		—
	$	194,706	$	280,295	$	280,930			$	238,000	$	350,000	$	347,008

(1) The carrying value of the 2021 Notes and 2021 PIK Notes includes the effect of the troubled debt restructurings described in Note 5.

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Income Taxes

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes

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 $174.9 million as of September 30, 2016.

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Other Comprehensive Income

Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of June 30, 2016	$	(297	)	$	(176	)	$	(473	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	101			—			101
Income tax effect	(37		)	91			54
Net of tax	64			91			155
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	144			—			144
Income tax effect	(54		)	—			(54		)
Net of tax	90			—			90
Net other comprehensive income	154			91			245
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	307			—			307
Income tax effect	(114		)	(85		)	(199		)
Net of tax	193			(85		)	108
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(2,043		)	—			(2,043		)
Income tax effect	760			—			760
Net of tax	(1,283		)	—			(1,283		)
Net other comprehensive loss	(1,090		)	(85		)	(1,175		)
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2015	$	3,564
Other comprehensive income before reclassifications:
Change in fair value of derivatives	4,077
Income tax effect	(1,517		)
Net of tax	2,560
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,093		)
Income tax effect	1,523
Net of tax	(2,570		)
Net other comprehensive loss	(10		)
Balance as of September 30, 2015	$	3,554

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$	5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	7,523
Income tax effect	(2,799		)
Net of tax	4,724
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(10,494		)
Income tax effect	3,904
Net of tax	(6,590		)
Net other comprehensive loss	(1,866		)
Balance as of September 30, 2015	$	3,554

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Recently Issued Accounting Standards

9 Months Ended

Sep. 30, 2016

Accounting Changes and Error Corrections [Abstract]

Recently Issued Accounting Standards

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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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

A reconciliation between basic and diluted earnings per share computations

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

For the Three Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(23,306	)	17,736	$	(1.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(23,306	)	17,736	$	(1.31	)
For the Nine Months Ended September 30, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(86,586	)	17,412	$	(4.97	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(86,586	)	17,412	$	(4.97	)
For the Three Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(51,910	)	16,259	$	(3.19	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(51,910	)	16,259	$	(3.19	)
For the Nine Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(235,233	)	16,225	$	(14.50	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(235,233	)	16,225	$	(14.50	)

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table reconciles the face value of the 2017 Notes, 2021 Notes and 2021 PIK Notes to the carrying value included in the Company's Consolidated Balance Sheet as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016									December 31, 2015
	2017 Notes			2021 Notes			2021 PIK Notes			2017 Notes			2021 Notes		2021 PIK Notes
Face Value	$	22,650		$	14,177		$	243,468		$	350,000		$	—	$	—
Deferred Financing Costs	(112		)	(109		)	—			(2,992		)	—		—
Excess (shortfall) Carrying Value	—			1,218			(605		)	—			—		—
Accrued PIK Interest	$	—		$	—		$	243		$	—		$	—	$	—
Carrying Value	$	22,538		$	15,286		$	243,106		$	347,008		$	—	$	—

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2016

Asset Retirement Obligation Disclosure [Abstract]

Changes to the Company's asset retirement obligation liability

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

	Nine Months Ended September 30,
	2016			2015
Asset retirement obligation, beginning of period	$	42,556		$	54,970
Liabilities incurred	—			392
Liabilities settled	(2,943		)	(1,826		)
Accretion expense	1,896			2,507
Revisions in estimates	291			(5,345		)
Divestiture of oil and gas properties	(75		)	(2,103		)
Asset retirement obligation, end of period	41,725			48,595
Less: current portion of asset retirement obligation	(1,132		)	(5,378		)
Long-term asset retirement obligation	$	40,593		$	43,217

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Oil and gas contracts

As of September 30, 2016, the Company had entered into the following commodity derivative instrument:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
October 2016 - December 2016	Swap	5,000 Mmbtu	$2.50

Effect of Cash Flow Hedges on the Consolidated Balance Sheet

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2016 and December 31, 2015:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2016	Derivative liability	$	(228	)
December 31, 2015	Derivative asset	$	1,508

Effect of Cash Flow Hedges on the Consolidated Statement of Operations

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2016 and 2015:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2016	$	101	Oil and gas sales	$	(144	)
Commodity Derivatives at September 30, 2015	$	4,077	Oil and gas sales	$	4,093

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 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 September 30, 2016	$	307	Oil and gas sales	$	2,043
Commodity Derivatives at September 30, 2015	$	7,523	Oil and gas sales	$	10,494

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of September 30, 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:
September 30, 2016	$	—	$	(228	)	$	—
December 31, 2015	$	—	$	1,508		$	—

Fair value of debt instruments

The following table summarizes the valuation of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of September 30, 2016 and December 31, 2015 (in thousands):

	September 30, 2016								December 31, 2015
	Fair Value		Face Value		Carrying Value				Fair Value		Face Value		Carrying Value
2017 Notes	$	18,799	$	22,650	$	22,538			$	238,000	$	350,000	$	347,008
2021 Notes	10,349		14,177		15,286		(1	)	—		—		—
2021 PIK Notes	165,558		243,468		243,106		(1	)	—		—		—
	$	194,706	$	280,295	$	280,930			$	238,000	$	350,000	$	347,008

(1) The carrying value of the 2021 Notes and 2021 PIK Notes includes the effect of the troubled debt restructurings described in Note 5.

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2016

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of June 30, 2016	$	(297	)	$	(176	)	$	(473	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	101			—			101
Income tax effect	(37		)	91			54
Net of tax	64			91			155
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	144			—			144
Income tax effect	(54		)	—			(54		)
Net of tax	90			—			90
Net other comprehensive income	154			91			245
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2016 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2015	$	947		$	—		$	947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	307			—			307
Income tax effect	(114		)	(85		)	(199		)
Net of tax	193			(85		)	108
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(2,043		)	—			(2,043		)
Income tax effect	760			—			760
Net of tax	(1,283		)	—			(1,283		)
Net other comprehensive loss	(1,090		)	(85		)	(1,175		)
Balance as of September 30, 2016	$	(143	)	$	(85	)	$	(228	)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2015	$	3,564
Other comprehensive income before reclassifications:
Change in fair value of derivatives	4,077
Income tax effect	(1,517		)
Net of tax	2,560
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,093		)
Income tax effect	1,523
Net of tax	(2,570		)
Net other comprehensive loss	(10		)
Balance as of September 30, 2015	$	3,554

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2015 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$	5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	7,523
Income tax effect	(2,799		)
Net of tax	4,724
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(10,494		)
Income tax effect	3,904
Net of tax	(6,590		)
Net other comprehensive loss	(1,866		)
Balance as of September 30, 2015	$	3,554

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Acquisitions and Divestitures - Acquisition (Fleetwood Joint Venture) (Details) a in Thousands, $ in Thousands	1 Months Ended
	Feb. 29, 2016 USD ($)	Jun. 30, 2014 USD ($) a mi²	Sep. 30, 2016 USD ($)	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Cash funding for future drilling, completion and lease acquisition costs, outstanding			$ 5,000	$ 4,409
Fleetwood Joint Venture | Louisiana
Business Acquisition [Line Items]
Purchase price		$ 24,000
Average working interest in leasehold position		37.00%
Acres acquired in leasehold position | a		30
Square miles of proprietary 3D survey | mi²		200
Cash portion of acquisition		$ 10,000
Cash funding for future drilling		$ 14,000
Cash funding for future drilling, completion and lease acquisition costs, outstanding				$ 4,400
Payments for acquisition costs	$ 4,400

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Acquisitions and Divestitures - Divestiture (Details) $ in Thousands, Mcfe in Billions	1 Months Ended		3 Months Ended		9 Months Ended
	Mar. 31, 2016 USD ($)	Jun. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Apr. 20, 2016 USD ($)	Jun. 04, 2015 USD ($)	Dec. 31, 2014 Mcfe
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on sale of oil and gas properties			$ 0	$ 828	$ 0	$ 22,359
Sale of oil and gas properties	$ 7,000				24,832	$ 271,891
Required purchase price of the non-producing assets if agreement not reached					$ 5,000
Woodford and Mississippian Lime
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from sale of a majority of interests								$ 260,200
Proved reserves (Bcfe) | Mcfe									227
Estimated proved reserves attributable to Sold Assets (percent of total)									57.00%
Gain on sale of oil and gas properties		$ 22,400
Woodford Shale assets (East Hoss Assets)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from sale of a majority of interests							$ 18,000

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Equity - Common Stock (Details) shares in Thousands	May 18, 2016 shares	Sep. 30, 2016 shares	May 17, 2016 shares	Dec. 31, 2015 shares
Class of Stock [Line Items]
Common stock, shares outstanding		21,115		16,410
Common Stock
Class of Stock [Line Items]
Reverse stock split, conversion ratio	0.25
Common stock, shares outstanding	17,500		70,100

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Equity - Convertible Preferred Stock (Details)	9 Months Ended
	Sep. 30, 2016 USD ($) dividend payment director $ / shares Rate shares	Dec. 31, 2015 shares
Class of Stock [Line Items]
Preferred stock, shares outstanding	1,495,000	1,495,000
Series B Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate	6.875%
Number of deferred dividend payments | payment	2
Maximum number of unpaid quarterly dividend payments for additional election of directors | dividend	6
Number of additional directors to be elected after threshold of unpaid dividends reached (6 payments) | director	2
Number of trading days	20 days
Number of consecutive trading days	30 days
Closing price as percentage of conversion price | Rate	130.00%
Series B Preferred Stock converted into common stock (in shares)	0.8608
Initial conversion price of common stock (in usd per share) | $ / shares	$ 58.08
Applicable settlement terms	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.
Trading day averaging period for determining conversion value	20 days
Conversion rate numerator for Preferred Stock | $	$ 50
Other long-term liabilities | Series B Preferred Stock
Class of Stock [Line Items]
Dividends payable | $	$ 3,900,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
A reconciliation between basic and diluted earnings per share computations
Loss available to common stockholders	$ (23,306)	$ (51,910)	$ (86,586)	$ (235,233)
Net income (loss) available to common stockholders (in shares)	17,736	16,259	17,412	16,225
Net income (loss) available to common stockholders (in dollars per share)	$ (1.31)	$ (3.19)	$ (4.97)	$ (14.50)
Stock options, Effect of dilutive securities		$ 0		$ 0
Stock options, effect of dilutive securities, (in shares)		0		0
Attributable to participating securities		$ 0		$ 0
Restricted stock, effect of dilutive securities (in shares)	0	0	0	0
DILUTED EPS, Income (Loss)	$ (23,306)	$ (51,910)	$ (86,586)	$ (235,233)
DILUTED EPS (in shares)	17,736	16,259	17,412	16,225
DILUTED EPS (in dollars per share)	$ (1.31)	$ (3.19)	$ (4.97)	$ (14.50)

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Earnings Per Share (Details Textual) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	0.7		0.7
Unvested Restricted Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	0.2		0.4
Convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	1.3	1.3	1.3	1.3

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Long-Term Debt - Exchange Offer and Consent Solicitation (Details) shares in Millions			3 Months Ended	9 Months Ended
	Sep. 27, 2016 USD ($) payment shares	Feb. 17, 2016 USD ($) shares	Sep. 30, 2016 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Jan. 14, 2016	Dec. 31, 2015 USD ($)	Jul. 03, 2013 USD ($)	Aug. 19, 2010 USD ($)
Debt Instrument [Line Items]
Principal amount			$ 280,295,000	$ 280,295,000			$ 350,000,000
Amortization of financing costs				10,073,000	$ 0
Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Principal amount			22,650,000	22,650,000			350,000,000	$ 200,000,000	$ 150,000,000
Long-term debt		$ 135,600,000	22,538,000	22,538,000
Excess (shortfall) carrying value			$ 0	$ 0			$ 0
Stated interest rate			10.00%	10.00%			10.00%	10.00%	10.00%
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Principal amount			$ 14,177,000	$ 14,177,000			$ 0
Long-term debt			15,286,000	15,286,000			0
Excess (shortfall) carrying value			$ 1,218,000	$ 1,218,000			0
Stated interest rate			10.00%	10.00%
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Principal amount			$ 243,468,000	$ 243,468,000			0
Long-term debt			243,106,000	243,106,000			0
Excess (shortfall) carrying value			$ (605,000)	$ (605,000)			$ 0
Stated interest rate			10.00%	10.00%
Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Repayments of debt		53,600,000
Private Exchange Offer and Consent Solicitation | Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Gain on extinguishment of debt		0
Stated interest rate			10.00%	10.00%
Grace period for interest payment				30 days
Debt conversion, original debt, amount		$ 214,400,000
Debt conversion, original debt, percent of total		61.00%
Private Exchange Offer and Consent Solicitation | Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Excess (shortfall) carrying value		$ 13,900,000
Amortization of financing costs			$ 600,000	$ 1,400,000
Stated interest rate						10.00%
Debt conversion, amount		$ 144,700,000
Private Exchange Offer and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Excess (shortfall) carrying value	$ (600,000)
Stated interest rate			10.00%	10.00%
September Exchange and Consent Solicitation | Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Long-term debt	22,700,000
Debt conversion, original debt, amount	$ 113,000,000
Debt conversion, original debt, percent of total	83.00%
September Exchange and Consent Solicitation | Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Long-term debt	$ 14,200,000
Debt conversion, original debt, amount	$ 130,500,000
Debt conversion, original debt, percent of total	90.00%
September Exchange and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Number of interest payments with variable rate | payment	3
Debt conversion, amount	$ 243,500,000
Common Stock | Private Exchange Offer and Consent Solicitation
Debt Instrument [Line Items]
Debt conversion, shares issued | shares	3.5	1.1
PIK Interest | September Exchange and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Stated interest rate	1.00%
Basis spread on variable rate	9.00%

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Long-Term Debt - Face Value to Carrying Value Reconciliation (Details) - USD ($)	Sep. 30, 2016	Sep. 27, 2016	Feb. 17, 2016	Dec. 31, 2015	Jul. 03, 2013	Aug. 19, 2010
Debt Instrument [Line Items]
Face Value	$ 280,295,000			$ 350,000,000
Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Face Value	22,650,000			350,000,000	$ 200,000,000	$ 150,000,000
Deferred Financing Costs	(112,000)			(2,992,000)
Excess (shortfall) Carrying Value	0			0
Carrying Value	22,538,000		$ 135,600,000
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Face Value	14,177,000			0
Deferred Financing Costs	(109,000)			0
Excess (shortfall) Carrying Value	1,218,000			0
Carrying Value	15,286,000			0
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Face Value	243,468,000			0
Deferred Financing Costs	0			0
Excess (shortfall) Carrying Value	(605,000)			0
Accrued PIK Interest	243,000			0
Carrying Value	$ 243,106,000			$ 0
Private Exchange Offer and Consent Solicitation | Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Excess (shortfall) Carrying Value			$ 13,900,000
Private Exchange Offer and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Excess (shortfall) Carrying Value		$ (600,000)

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Long-Term Debt - Narrative (Details)		9 Months Ended
	Oct. 17, 2016 USD ($)	Sep. 30, 2016 USD ($)	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Feb. 17, 2016 USD ($)	Dec. 31, 2015 USD ($)	Jul. 03, 2013 USD ($)	Aug. 19, 2010 USD ($)
Debt Instrument [Line Items]
Principal amount		$ 280,295,000					$ 350,000,000
Credit Agreement
Debt Instrument [Line Items]
Period used in determining EBITDAX to cash interest expense		12 months
10% Senior Unsecured Notes due 2017 | Senior Notes
Debt Instrument [Line Items]
Principal amount		$ 22,650,000					$ 350,000,000	$ 200,000,000	$ 150,000,000
Interest rate of Senior Notes		10.00%					10.00%	10.00%	10.00%
Deferred finance costs, net		$ (112,000)					$ (2,992,000)
Long-term debt		22,538,000				$ 135,600,000
10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Principal amount		$ 14,177,000					0
Interest rate of Senior Notes		10.00%
Deferred finance costs, net		$ (109,000)					0
Long-term debt		15,286,000					0
Scenario, Forecast | Credit Agreement | Minimum
Debt Instrument [Line Items]
Current ratio					1.0
Long-term Debt | Accounting Standards Update 2015-03 | 10% Senior Unsecured Notes due 2017 | Senior Notes
Debt Instrument [Line Items]
Deferred finance costs, net		(100,000)					$ (3,000,000)
Long-term Debt | Accounting Standards Update 2015-03 | 10% Senior Secured Notes due 2021 | Senior Notes
Debt Instrument [Line Items]
Deferred finance costs, net		$ (109,000)
Term Loan | Scenario, Forecast | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Covenant compliance, ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments			2	1.7	1.7
Term Loan | Subsequent Event | Loan Agreement | Line of Credit
Debt Instrument [Line Items]
Borrowing availability period	3 years
Maximum borrowing capacity	$ 50,000,000
Interest rate of Senior Notes	10.00%
Long-term debt	$ 10,000,000
First priority lien as percent of total value of oil and gas properties	90.00%
Covenant compliance, present value of estimated future net revenues, discount percent	10.00%

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 42,556	$ 54,970
Liabilities incurred	0	392
Liabilities settled	(2,943)	(1,826)
Accretion expense	1,896	2,507
Revisions in estimates	291	(5,345)
Divestiture of oil and gas properties	(75)	(2,103)
Asset retirement obligation, end of period	41,725	48,595
Less: current portion of asset retirement obligation	(1,132)	(5,378)	$ (6,015)
Long-term asset retirement obligation	$ 40,593	$ 43,217	$ 36,541

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Ceiling Test (Details) $ in Thousands	3 Months Ended						6 Months Ended		9 Months Ended
	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($) $ / mcf $ / Mcfe $ / bbl	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($) $ / mcf $ / Mcfe $ / bbl	Jun. 30, 2016 USD ($) $ / mcf $ / Mcfe $ / bbl	Jun. 30, 2015 USD ($) $ / mcf $ / Mcfe $ / bbl	Sep. 30, 2016 USD ($) $ / mcf $ / Mcfe $ / bbl	Sep. 30, 2015 USD ($) $ / mcf $ / Mcfe $ / bbl
Reserve Quantities [Line Items]
Rate for discounting future cash flows									10.00%
Decrease (Increase) in ceiling test write-downs	$ 8,665	$ 12,800	$ 18,900	$ 40,212	$ 65,500	$ 108,900			$ 40,304	$ 214,618
Mcf of natural gas
Reserve Quantities [Line Items]
Average sales prices | $ / bbl			45.92			81.33	42.12	71.27	39.97	59.71
Barrel of oil
Reserve Quantities [Line Items]
Average sales prices | $ / mcf			2.19			3.31	2.15	3.20	2.19	2.89
Mcfe of Ngl
Reserve Quantities [Line Items]
Average sales prices | $ / Mcfe			1.91			3.52	1.71	3.35	1.66	2.70
Commodity Derivatives | Cash Flow Hedging
Reserve Quantities [Line Items]
Decrease (Increase) in ceiling test write-downs			$ 800			$ 14,000	$ 200	$ 1,000	$ 100	$ 2,200

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Derivative Instruments (Details) - Swap - October 2016 - December 2016 - Natural Gas:	9 Months Ended
	Sep. 30, 2016 MMBTU $ / shares
Oil and gas contracts
Daily Volumes | MMBTU	5,000
Weighted Average Price | $ / shares	$ 2.50

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Derivative Instruments (Details 1) - Commodity Derivatives - Designated as Hedging Instrument - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative liability	$ (228)
Derivative asset		$ 1,508

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Derivative Instruments (Details 2) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Recognized in Other Comprehensive Income	$ 245	$ (10)	$ (1,175)	$ (1,866)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Recognized in Other Comprehensive Income	101	4,077	307	7,523
Oil and gas sales | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified into Income	$ (144)	$ 4,093	$ 2,043	$ 10,494

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Derivative Instruments (Details Textual) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Accumulated other comprehensive (loss) income	$ (228)		$ (228)		$ 947
Realization of gain, net of taxes			(100)
Gas hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	(144)	$ 3,603	2,043	$ 10,108
Oil hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	0	299	0	38
Ngl hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	$ 0	$ 191	$ 0	$ 348

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Fair Value Measurements (Details) - USD ($)	Sep. 30, 2016	Dec. 31, 2015	Jul. 03, 2013	Aug. 19, 2010
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Face Value	$ 280,295,000	$ 350,000,000
Senior Notes | 10% Senior Unsecured Notes due 2017
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Face Value	22,650,000	350,000,000	$ 200,000,000	$ 150,000,000
Senior Notes | 10% Senior Secured Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Face Value	14,177,000	0
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Face Value	243,468,000	0
Quoted Prices in Active Markets (Level 1)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	0	0
Significant Other Observable Inputs (Level 2)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	(228,000)	1,508,000
Significant Unobservable Inputs (Level 3)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	0	0
Fair Value
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	194,706,000	238,000,000
Fair Value | Senior Notes | 10% Senior Unsecured Notes due 2017
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	18,799,000	238,000,000
Fair Value | Senior Notes | 10% Senior Secured Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	10,349,000	0
Fair Value | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	165,558,000	0
Carrying Value
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	280,930,000	347,008,000
Carrying Value | Senior Notes | 10% Senior Unsecured Notes due 2017
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	22,538,000	347,008,000
Carrying Value | Senior Notes | 10% Senior Secured Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	15,286,000	0
Carrying Value | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	$ 243,106,000	$ 0

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Income Taxes (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Income Tax Disclosure [Abstract]
Income taxes at a statutory rate	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 174.9

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance			$ (163,067)
Amounts reclassified from accumulated other comprehensive loss:
Ending balance	$ (236,810)		(236,810)
Gains and Losses on Cash Flow Hedges
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(297)	$ 3,564	947	$ 5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	101	4,077	307	7,523
Income tax effect	(37)	(1,517)	(114)	(2,799)
Net of tax	64	2,560	193	4,724
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	144	(4,093)	(2,043)	(10,494)
Income tax effect	(54)	1,523	760	3,904
Net of tax	90	(2,570)	(1,283)	(6,590)
Net other comprehensive income (loss)	154	(10)	(1,090)	(1,866)
Ending balance	(143)	$ 3,554	(143)	$ 3,554
Change in Valuation Allowance
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(176)		0
Other comprehensive income before reclassifications:
Change in fair value of derivatives	0		0
Income tax effect	91		(85)
Net of tax	91		(85)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	0		0
Income tax effect	0		0
Net of tax	0		0
Net other comprehensive income (loss)	91		(85)
Ending balance	(85)		(85)
Total
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(473)		947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	101		307
Income tax effect	54		(199)
Net of tax	155		108
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	144		(2,043)
Income tax effect	(54)		760
Net of tax	90		(1,283)
Net other comprehensive income (loss)	245		(1,175)
Ending balance	$ (228)		$ (228)