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: March 31, 2017

¨ 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, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

As of April 27, 2017 there were 21,220,444 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 of PetroQuest Energy, Inc. as of March 31, 2017 and December 31, 2016	1
Consolidated Statements of Operations of PetroQuest Energy, Inc. for the Three Months Ended March 31, 2017 and 2016	2
Consolidated Statements of Comprehensive Loss of PetroQuest Energy, Inc. for the Three Months Ended March 31, 2017 and 2016	3
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc. for the Three Months Ended March 31, 2017 and 2016	4
Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3. Quantitative and Qualitative Disclosures About Market Risk	22
Item 4. Controls and Procedures	23
Part II. Other Information
Item 1. Legal Proceedings	23
Item 1A. Risk Factors	23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3. Defaults upon Senior Securities	27
Item 4. Mine Safety Disclosures	27
Item 5. Other Information	27
Item 6. Exhibits	27

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	March 31, 2017			December 31, 2016
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	28,191		$	28,312
Revenue receivable	9,269			10,294
Joint interest billing receivable	7,172			7,632
Derivative asset	168			—
Other current assets	3,794			2,353
Total current assets	48,594			48,591
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,331,930			1,323,333
Unevaluated oil and gas properties	11,909			9,015
Accumulated depreciation, depletion and amortization	(1,249,300		)	(1,243,286		)
Oil and gas properties, net	94,539			89,062
Other property and equipment	9,315			10,951
Accumulated depreciation of other property and equipment	(8,560		)	(10,109		)
Total property and equipment	95,294			89,904
Other assets	6,364			6,365
Total assets	$	150,252		$	144,860
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	30,808		$	25,265
Advances from co-owners	3,879			2,330
Oil and gas revenue payable	22,639			22,146
Accrued interest	874			2,047
Asset retirement obligation	3,291			4,160
Derivative liability	1,729			3,947
10% Senior Unsecured Notes due 2017	—			22,568
Other accrued liabilities	3,211			3,938
Total current liabilities	66,431			86,401
Multi-draw Term Loan	27,429			7,249
10% Senior Secured Notes due 2021	15,174			15,228
10% Senior Secured PIK Notes due 2021	254,130			248,600
Asset retirement obligation	32,958			32,450
Other long-term liabilities	6,491			6,027
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 21,214 and 21,197 shares, respectively	21			21
Paid-in capital	304,805			304,341
Accumulated other comprehensive loss	(1,562		)	(4,750		)
Accumulated deficit	(555,626		)	(550,708		)
Total stockholders’ equity	(252,361		)	(251,095		)
Total liabilities and stockholders’ equity	$	150,252		$	144,860

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
	March 31,
	2017			2016
Revenues:
Oil and gas sales	$	20,772		$	17,320
Expenses:
Lease operating expenses	7,076			8,177
Production taxes	308			338
Depreciation, depletion and amortization	6,117			10,138
Ceiling test write-down	—			18,857
General and administrative	3,153			8,599
Accretion of asset retirement obligation	547			608
Interest expense	7,258			8,257
	24,459			54,974
Other income:
Other income	54			97
Loss from operations	(3,633		)	(37,557		)
Income tax expense	—			86
Net loss	(3,633		)	(37,643		)
Preferred stock dividend	1,285			1,494
Loss available to common stockholders	$	(4,918	)	$	(39,137	)
Loss per common share:
Basic
Net loss per share	$	(0.23	)	$	(2.31	)
Diluted
Net loss per share	$	(0.23	)	$	(2.31	)
Weighted average number of common shares:
Basic	21,208			16,956
Diluted	21,208			16,956

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Loss

(unaudited)

(Amounts in Thousands)

	Three Months Ended
	March 31,
	2017			2016
Net loss	$	(3,633	)	$	(37,643	)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $0, and $86, respectively	3,188			(145		)
Comprehensive loss	$	(445	)	$	(37,788	)

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Three Months Ended
	March 31,
	2017			2016
Cash flows from operating activities:
Net loss	$	(3,633	)	$	(37,643	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax expense	—			86
Depreciation, depletion and amortization	6,117			10,138
Ceiling test writedown	—			18,857
Accretion of asset retirement obligation	547			608
Share-based compensation expense	425			442
Amortization costs and other	238			562
Non-cash PIK Interest	5,512			—
Payments to settle asset retirement obligations	(402		)	(464		)
Costs incurred to issue 2021 Notes	—			4,740
Changes in working capital accounts:
Revenue receivable	1,025			(842		)
Joint interest billing receivable	460			10,709
Accounts payable and accrued liabilities	3,037			(20,413		)
Advances from co-owners	1,549			(12,021		)
Other	(1,462		)	(949		)
Net cash provided by (used in) operating activities	13,413			(26,190		)
Cash flows used in investing activities:
Investment in oil and gas properties	(10,898		)	(15,812		)
Investment in other property and equipment	(16		)	(23		)
Sale of oil and gas properties	—			7,000
Net cash used in investing activities	(10,914		)	(8,835		)
Cash flows used in financing activities:
Net proceeds from share based compensation	40			65
Deferred financing costs	(10		)	(38		)
Payment of preferred stock dividend	—			(1,284		)
Redemption of 2017 Notes	(22,650		)	(53,626		)
Costs incurred to issue 2021 Notes	—			(4,740		)
Proceeds from borrowings	20,000			—
Net cash used in financing activities	(2,620		)	(59,623		)
Net decrease in cash and cash equivalents	(121		)	(94,648		)
Cash and cash equivalents, beginning of period	28,312			148,013
Cash and cash equivalents, end of period	$	28,191		$	53,365
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	2,975		$	16,781

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 month periods ended March 31, 2017 and 2016, has been prepared by the Company and was not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at March 31, 2017 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, 2016 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, 2016.

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

Divestitures:

In March 2016, the Company sold certain non-producing assets in East Texas for $7 million to a potential joint venture partner. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. After determining it would not pursue a joint venture with this party, the Company repurchased the non-producing assets for $5.0 million in December 2016 pursuant to the terms of the purchase and sale agreement related to this sale. The Company subsequently entered into a new drilling joint venture in East Texas with another group of partners.

On April 20, 2016, the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field for approximately $18 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

On October 31, 2016, the Company completed the sale of its remaining Oklahoma assets for approximately $0.7 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

Note 3—Equity

Common Stock

On May 18, 2016, the Company effected a reverse split of its 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 70.5 million shares to approximately 17.6 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.

5

In connection with an amendment to the Company's prior bank credit facility, which was terminated in October 2016, 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 March 31, 2017, the Company has deferred four dividend payments and has accrued a $6.4 million payable related to the four deferred payments and the quarterly dividend that was payable on April 15, 2017, 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. The Multidraw Term Loan Agreement (see Note 5) currently restricts the Company from paying cash dividends on the Series B Preferred Stock.

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, 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.

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 March 31, 2017	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(4,918	)	21,208	$	(0.23	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(4,918	)	21,208	$	(0.23	)
For the Three Months Ended March 31, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(39,137	)	16,956	$	(2.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(39,137	)	16,956	$	(2.31	)

An aggregate of 1.5 million and 0.7 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 March 31, 2017 and 2016, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods.

6

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 February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, 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 September 27, 2016, the Company closed 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. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then 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. Following the consummation of the September Exchange, there were $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.

On March 31, 2017, the Company redeemed its remaining outstanding 2017 Notes at a redemption price of 100% of the principal amount thereof, plus accrued interest to the redemption date, in the amount of $22.8 million. The redemption was funded by cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described below.

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. 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. The Company exercised this PIK option in connection with the interest payment due on February 15, 2017. As of March 31, 2017, the Company was 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 March 31, 2017, the Company was in compliance with all of the covenants under the 2021 Notes.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") Topic 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 is being amortized under the effective interest method over the term of the 2021 PIK Notes. At March 31, 2017, $0.6 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and the Company recognized $18 thousand of amortization expense as an increase to interest expense during the three months ended March 31, 2017.

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. 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 March 31, 2017, $1.1 million of the excess remained as part of the carrying value of the 2021 Notes

7

and the Company recognized $0.1 million of amortization expense as a reduction to interest expense during the three months ended March 31, 2017.

The issuance of the 2021 Notes, 2021 PIK Notes and shares of common stock, as well as the exchange of the 2017 Notes and 2021 Notes, in the February Exchange and September Exchange represent non-cash financing activities for purposes of the Statement of Cash Flows.

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, jointly and severally, 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.

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 prior credit agreement with JPMorgan Chase Bank, N.A. 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 March 31, 2017, the Company has $30.0 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 PetroQuest Energy, L.L.C. (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 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 March 31, 2017, no default or event of default existed 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.

8

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

	March 31, 2017											December 31, 2016
	2017 Notes		2021 Notes			2021 PIK Notes			Term Loans			2017 Notes			2021 Notes			2021 PIK Notes			Term Loans
Face Value	$	—	$	14,177		$	251,868		$	30,000		$	22,650		$	14,177		$	243,468		$	10,000
Unamortized Deferred Financing Costs	—		(102		)	—			(2,571		)	(82		)	(108		)	—			(2,751		)
Excess (shortfall) Carrying Value	—		1,099			(572		)	—			—			1,159			(590		)	—
Accrued PIK Interest	—		—			2,834			—			—			—			5,722			—
Carrying Value	$	—	$	15,174		$	254,130		$	27,429		$	22,568		$	15,228		$	248,600		$	7,249

Note 6—Asset Retirement Obligation

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

	Three Months Ended March 31,
	2017			2016
Asset retirement obligation, beginning of period	$	36,610		$	42,556
Liabilities incurred	13			—
Liabilities settled	(540		)	(464		)
Accretion expense	547			608
Revisions in estimates	(381		)	—
Asset retirement obligation, end of period	36,249			42,700
Less: current portion of asset retirement obligation	(3,291		)	(5,545		)
Long-term asset retirement obligation	$	32,958		$	37,155

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, the prices used in computing the estimated future net cash flows from the Company's estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 per Mcf of natural gas, $45.92 per barrel of oil and $1.91 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $18.9 million during the three months ended March 31, 2016. The Company's cash flow hedges in place at March 31, 2016 decreased the ceiling test write-down by approximately $0.8 million. No such write-down occurred during the three months ended March 31, 2017.

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

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not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At March 31, 2017, the Company's derivative instruments were designated as effective cash flow hedges.

Oil and gas sales include (reductions) additions related to the settlement of gas hedges of ($321,000) and $1,032,000 for the three months endedMarch 31, 2017 and 2016, respectively.

As of March 31, 2017, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April - December 2017	Swap	30,000 Mmbtu	$3.22
October - December 2017	Swap	10,000 Mmbtu	$3.22
January - March 2018	Swap	35,000 Mmbtu	$3.24

At March 31, 2017, the Company had recognized an accumulated other comprehensive loss of approximately $1.6 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of March 31, 2017, the Company would reclassify approximately $1.0 million, net of taxes, of accumulated other comprehensive loss into oil and gas sales during the next twelve months.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheets at March 31, 2017 and December 31, 2016:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
March 31, 2017	Derivative asset	$	168
March 31, 2017	Derivative liability	$	(1,729	)
December 31, 2016	Derivative liability	$	(3,947	)
December 31, 2016	Other long-term liabilities	$	(803	)

Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the three months ended March 31, 2017 and 2016:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into oil and gas sales
Commodity Derivatives at March 31, 2017	$	2,867	Oil and gas sales	$	(321	)
Commodity Derivatives at March 31, 2016	$	801	Oil and gas sales	$	1,032

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.

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The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at March 31, 2017 and December 31, 2016 were in the form of swaps based on NYMEX pricing for natural gas. The fair value of these derivatives are 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 fair value of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2017 and December 31, 2016 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
March 31, 2017	$	—	$	(1,561	)	$	—
December 31, 2016	$	—	$	(4,750	)	$	—

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

	March 31, 2017						December 31, 2016
	Fair Value		Face Value		Carrying Value		Fair Value		Face Value		Carrying Value
2017 Notes	$	—	$	—	$	—	$	21,970	$	22,650	22,568
2021 Notes	12,618		14,177		15,174		12,192		14,177		15,228
2021 PIK Notes	191,420		251,868		254,130		177,732		243,468		248,600
	$	204,038	$	266,045	$	269,304	$	211,894	$	280,295	$	286,396

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 $182.2 million and $177.4 million as of March 31, 2017 and December 31, 2016, respectively.

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Note 11 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended March 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	2,867			—			2,867
Income tax effect	(1,066		)	1,066			—
Net of tax	1,801			1,066			2,867
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	321			—			321
Income tax effect	(120		)	120			—
Net of tax	201			120			321
Net other comprehensive income	2,002			1,186			3,188
Balance as of March 31, 2017	$	(981	)	$	(581	)	$	(1,562	)

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

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

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Note 12 - Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. We expect to apply the modified retrospective approach upon adoption of this standard. The Company is currently evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however, the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases" (Topic 842)", to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. The Company is currently evaluating the impact of the new standard on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. The standard did not have a material impact on the Company's 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 with our acquisition of the Carthage Field in East Texas. From 2005 through 2015, we were actively acquiring acreage and drilling wells primarily in the Woodford Shale play in Oklahoma. We divested all of our acreage and producing wells in Oklahoma in three transactions that closed in June 2015, April 2016 and October 2016 (the "Oklahoma Divestitures"). See Note 2 - Acquisitions and Divestitures.

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

• Completed the Oklahoma Divestitures for $292.6 million;

• Reduced our 2016 capital expenditures by 75% as compared to 2015 spending of approximately $65 million;

• Completed two debt exchanges to extend maturities on a significant portion of debt;

• Reduced total debt 30% from $425 million at December 31, 2014 to $296 million at March 31, 2017;

• Entered into a new $50 million Multidraw Term Loan Agreement (as defined below) maturing in 2020;

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

• Secured a new 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 2016 debt exchange permits us to reduce our cash interest expense on our 2021 PIK Notes (as defined below) 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 (as defined below), 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. During March 2017, we utilized borrowings under this Multidraw Term Loan Agreement and cash on hand to redeem the remaining 2017 Notes.

We currently have a more favorable outlook on oil and gas prices for 2017 than what we experienced in 2016. We recently recompleted our Thunder Bayou well in South Louisiana into a larger sand package and commenced the East Texas joint venture drilling program where we expect to drill eight gross wells during 2017. As a result, we expect to grow production during 2017 as compared to 2016. Our production during the first quarter of 2017 increased 13% from 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

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may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.

Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the 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 decline, 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 March 31, 2017, our derivative instruments were designated as effective cash flow hedges.

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

Results of Operations

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

	Three Months Ended March 31,
	2017		2016
Production:
Oil (Bbls)	132,678		139,989
Gas (Mcf)	3,524,966		5,547,477
Ngl (Mcfe)	904,206		1,246,632
Total Production (Mcfe)	5,225,240		7,634,043
Sales:
Total oil sales	$	6,871,409	$	4,358,744
Total gas sales	10,662,342		10,718,208
Total ngl sales	3,238,546		2,242,762
Total oil, gas, and ngl sales	$	20,772,297	$	17,319,714
Average sales prices:
Oil (per Bbl)	$	51.79	$	31.14
Gas (per Mcf)	3.02		1.93
Ngl (per Mcfe)	3.58		1.80
Per Mcfe	3.98		2.27

The above sales and average sales prices include (decreases) increases to revenue related to the settlement of gas hedges of ($321,000) and $1,032,000 for the three months endedMarch 31, 2017 and 2016, 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 $4,918,000 and $39,137,000 for the three months ended March 31, 2017 and 2016, respectively. The primary fluctuations were as follows:

Production Total production decreased32% during the three month period ended March 31, 2017 as compared to the 2016 period. The decrease in total production was due primarily to the 2016 Oklahoma divestitures and normal production declines at our Gulf Coast and East Texas fields as a result of the reduction in capital expenditures during 2016. As a result of the successful recompletion of our Thunder Bayou well in the first quarter of 2017 as well as the commencement of our East Texas drilling program, we expect our total production for the remainder of 2017 to continue to increase as compared to 2016. Our total production during the first quarter of 2017 increased 13% from total production during the fourth quarter of 2016.

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Gas production during the three month period ended March 31, 2017decreased36% from the comparable period in 2016. The decrease was primarily the result of the 2016 Oklahoma divestitures and normal production declines at our Gulf Coast and East Texas fields. As a result of the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our drilling program in East Texas, we expect our average daily gas production to increase during the remainder of 2017 as compared to 2016.

Oil production during the three month period ended March 31, 2017decreased5% from the 2016 period due primarily to normal production declines at our Gulf Coast and East Texas fields and downtime due to pipeline constraints at one of our Gulf of Mexico properties. Partially offsetting these decreases were increases due to the recompletion of our Thunder Bayou well as well as the recompletion of several Gulf of Mexico wells during the second half of 2016. As a result of these successful recompletions, we expect our average daily oil production to increase during the remainder of 2017 as compared to 2016.

Ngl production during the three month period ended March 31, 2017decreased27% from the 2016 period primarily due to normal production declines at certain of our Gulf Coast and East Texas fields. As a result of the successful recompletion of our Thunder Bayou well during the first quarter of 2017 and our drilling program in East Texas, we expect our average daily Ngl production to increase during the remainder of 2017 as compared to 2016.

Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2017 were $3.02 as compared to $1.93 for the 2016 period. Average oil prices per Bbl for the three months ended March 31, 2017 were $51.79 as compared to $31.14 for the 2016 period and average Ngl prices per Mcfe were $3.58 for the three months ended March 31, 2017, as compared to $1.80 for the 2016 period. Stated on a Mcfe basis, unit prices received during the three months ended March 31, 2017 were 75%higher than the prices received during the comparable 2016 period.

Revenue Including the effects of hedges, oil and gas sales during the three months endedMarch 31, 2017increased20% to $20,772,000, as compared to oil and gas sales of $17,320,000 during the 2016 period. This increase was primarily the result of higher average realized prices for our production during 2017.

Expenses Lease operating expenses for the three months ended March 31, 2017 totaled $7,076,000 as compared to $8,177,000 during the 2016 period. Per unit lease operating expenses totaled $1.35 per Mcfe during the three month period ended March 31, 2017 as compared to $1.07 per Mcfe during the 2016 period. Total lease operating expenses decreased during the three months ended March 31, 2017 primarily as result of the 2016 Oklahoma divestitures, but increased on a per unit basis due to these wells having a much lower per unit rate compared to our Gulf of Mexico and East Texas wells. Lease operating expenses decreased overall at our Gulf Coast and East Texas fields as a result of certain cost saving measures initiated during 2016. We expect total lease operating expenses to generally approximate 2016 expenses on an absolute value basis and to decrease on a per unit basis during the remainder of 2017.

Production taxes for the three months ended March 31, 2017 totaled $308,000 as compared to $338,000 during the 2016 period. Per unit production taxes totaled $0.06 per Mcfe during the three month period ended March 31, 2017 as compared to $0.04 per Mcfe during the comparable 2016 period. Severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. As a result of the expected increases in production and completion of the two-year severance tax exemption on our Thunder Bayou well in June 2017, we expect an increase in our total and per unit production taxes during the remainder of 2017 as compared to 2016.

General and administrative expenses during the three months ended March 31, 2017 totaled $3,153,000 as compared to $8,599,000 during the 2016 period. General and administrative expenses during the three months ended March 31, 2016 included $4,740,000 of costs related to the issuance of the 2021 Notes (as defined below). ASC Topic 470-60 "Troubled Debt Restructurings by Debtors" requires financing costs related to a troubled debt transaction to be expensed in the period incurred. Share-based compensation costs totaled $420,000 during the first quarter of 2017, compared to $513,000 during the 2016 period. We capitalized $1,334,000 of general and administrative expenses during the three month period ended March 31, 2017 compared to $1,489,000 during the 2016 period. Excluding the non-recurring debt restructuring fees incurred in 2016, we expect general and administrative expenses during the remainder of 2017 to be lower than 2016 due to an approximate 50% reduction in staff levels during 2016.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended March 31, 2017 totaled $6,014,000, or $1.15 per Mcfe, as compared to $9,950,000, or $1.30 per Mcfe, during the comparable 2016 period. The decrease in the per unit DD&A rate is primarily the result of the recent ceiling test write-downs. We expect our DD&A rate to approximate the first quarter rate during the remainder of 2017.

At March 31, 2016, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 per Mcf of natural gas, $45.92 per barrel of oil and $1.91 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized a ceiling test write-down of $18,857,000 during the three months ended March 31, 2016. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-down. We recognized no such ceiling test write-down during the three

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months ended March 31, 2017. Utilizing current strip prices for oil and gas prices for the second quarter of 2017 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of March 31, 2017, we do not expect to recognize a ceiling test write-down in the second quarter of 2017.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $7,258,000 during the three months ended March 31, 2017 as compared to $8,257,000 during the 2016 period. During the three month period ended March 31, 2017, our capitalized interest totaled $305,000 as compared to $309,000 during the 2016 period. The decrease in interest expense during the 2017 period was the result of the February 2016 debt exchange in which the total amount of debt outstanding was reduced by approximately $53.6 million.

We had no income tax expense during the three months ended March 31, 2017 as compared to $86,000 during the comparable 2016 period. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.

As a result of ceiling test write-downs, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $182,162,000 as of March 31, 2017.

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 aimed at preserving liquidity, reducing overall debt levels and extending debt maturities. Through these transactions, which included two debt exchanges, we have eliminated all debt maturing in 2017 and have reduced total debt 30% from $425 million at December 31, 2014 to $296 million at March 31, 2017. In addition to extending the maturity on the majority of our debt that was due in 2017, our September 2016 debt exchange permits us to reduce our cash interest expense on our 2021 PIK Notes 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. For additional information, see "Source of Capital: Debt" below.

At March 31, 2017, we had a working capital deficit of approximately $17.8 million as compared to a working capital deficit of approximately $37.8 million as of December 31, 2016. The increase in working capital is primarily due to the redemption on March 31, 2017 of our remaining 2017 Notes 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 requested collateral be posted to support certain of the bonds issued on our behalf and to date, we have provided cash deposits totaling $7.2 million to 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 future requests 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 increased from $(26.2) million during the three months ended March 31, 2016 to $13.4 million during the 2017 period. The increase in operating cash flow during 2017 as compared to 2016 is primarily attributable to increases in oil and gas revenues as well as the timing of payment of payables based on operational activity.

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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 2016, we sold our remaining assets in Oklahoma for approximately $18.5 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 February 17, 2016, we closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of our outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, we (i) paid approximately $53.6 million of cash, (ii) issued $144.7 million aggregate principal amount of our new 10% Second Lien Senior Secured Notes due 2021 (the "2021 Notes") and (iii) issued approximately 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 remained outstanding. The February Consent Solicitation eliminated or waived substantially all of the restrictive covenants contained in the indenture governing the 2017 Notes.

On September 27, 2016, we closed 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. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then 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. Following the consummation of the September Exchange, there was $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.

On March 31, 2017, we redeemed our remaining outstanding 2017 Notes at a redemption price of 100% of the principal amount thereof, plus accrued interest to the redemption date, in the amount of $22.8 million. The redemption was funded by cash on hand and $20 million borrowed under the Multidraw Term Loan Agreement described below.

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. 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. We exercised this PIK option in connection with the interest payment due in February 15, 2017. As of the date hereof, 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 February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by ASC 470-60 "Troubled Debt Restructurings by Debtors." We 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 was 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. At March 31, 2017, $0.6 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and we recognized $18 thousand of amortization expense as an increase to interest expense during the three months ended March 31, 2017.

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We 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. 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 March 31, 2017, $1.1 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.1 million of amortization expense as a reduction to interest expense during the three months ended March 31, 2017.

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 ("Franklin"), as a lender, and Wells Fargo Bank, National Association, as administrative agent, replacing the prior credit agreement with JPMorgan Chase Bank, N.A. 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, including the 2017 Notes, 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 $30 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 PetroQuest Energy, L.L.C. (the "Borrower") and certain of our other subsidiaries, and corporate guarantees by us and certain of our subsidiaries of the indebtedness of the Borrower. Term Loans under the Multidraw Term Loan Agreement bear interest at the rate of 10% per annum.

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 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.

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

	March 31, 2017											December 31, 2016
	2017 Notes		2021 Notes			2021 PIK Notes			Term Loans			2017 Notes			2021 Notes			2021 PIK Notes			Term Loans
Face Value	$	—	$	14,177		$	251,868		$	30,000		$	22,650		$	14,177		$	243,468		$	10,000
Unamortized Deferred Financing Costs	—		(102		)	—			(2,571		)	(82		)	(108		)	—			(2,751		)
Excess (shortfall) Carrying Value	—		1,099			(572		)	—			—			1,159			(590		)	—
Accrued PIK Interest	—		—			2,834			—			—			—			5,722			—
Carrying Value	$	—	$	15,174		$	254,130		$	27,429		$	22,568		$	15,228		$	248,600		$	7,249

Use of Capital: Exploration and Development

Our 2017 capital expenditure budget, which includes capitalized interest and general and administrative costs, is expected to range between $40 million and $48 million (which from the midpoint of such range, represents a 176% increase from our 2016 capital expenditures), of which $11.5 million was incurred during the first three months of 2017. During the three months ended March 31, 2017, we funded our capital expenditures with cash on hand and cash flow from operations. We plan to fund our capital expenditures during the remainder of 2017 with cash flow from operations and cash on hand. To the extent additional capital is required, we may utilize borrowings under our Multidraw Term Loan Agreement, sales of equity or debt securities or the sales of properties or assets or we may reduce our capital expenditures to manage our liquidity position.

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, borrowings under our Multidraw Term Loan Agreement, 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 the Multidraw Term Loan Agreement; our ability to post additional collateral to satisfy our offshore decommissioning obligations; our ability to execute our 2017 drilling and recompletion program as planned and to increase our production; our ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing market; our ability to find, develop and produce oil and natural gas reserves that are economically recoverable and to replace reserves and sustain and/or increase production; ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices; our ability to raise additional 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 the Multidraw Term Loan Agreement and restrictive debt covenants; approximately 67% of our production being exposed to the additional risk of severe weather, including hurricanes, tropical storms and flooding, and natural disasters; losses and liabilities from uninsured or underinsured drilling and operating activities; changes in laws and 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 continue 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.

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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 2017, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have a $4.3 million impact on our revenues for 2017.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three months ended March 31, 2017, we paid$0.3 millionto 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 counterparties to our existing hedge contracts are Shell Trading Risk Management LLC and Koch Supply and Trading LP.

As of March 31, 2017, we had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April - December 2017	Swap	30,000 Mmbtu	$3.22
October - December 2017	Swap	10,000 Mmbtu	$3.22
January - March 2018	Swap	35,000 Mmbtu	$3.24

After executing the above transactions, we have approximately 9.2 Bcf of gas volumes, at an average price of $3.22 per Mcf hedged for 2017 and approximately 3.2 Bcf of gas volumes, at an average price of $3.24 per Mcf hedged for 2018. 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 March 31, 2017, we had no debt subject to variable interest rates.

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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. 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. Although a single or multiple adverse rulings or settlements could possibly have a material adverse effect on the Company's business or financial position, the Company only accrues for losses from litigation and claims if the Company determines that a loss is probable and the amount can be reasonably estimated.

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, 2016.

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 March 31, 2017 as compared to December 31, 2014. For example, the SEC pricing at March 31, 2017 for crude oil (WTI Cushing) was $45.68 per Bbl and natural gas (Henry Hub) was $2.69 per MMBtu as compared to $94.99 per Bbl and $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.

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These factors include:

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

• the condition of the United States and worldwide economies;

• market uncertainty;

• the level of consumer product demand;

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

• the actions of the Organization of Petroleum Exporting Countries;

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

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

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

• the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices 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, 2017 to decline compared to our estimated proved reserves at December 31, 2016. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices.

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

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

As of March 31, 2017, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $268.5 million. We currently have $20 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 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 $5.9 million per year for interest on our 2021 Notes, 2021 PIK Notes and amounts borrowed under our Multidraw Term Loan Agreement 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 permissible 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

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• 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 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 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.

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.

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 requested collateral be posted to support certain of the bonds issued on our behalf. To date, we have provided cash deposits totaling $7.2 million to 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 (“NTL”) No. 2016-N01 effective September 12, 2016 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 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. On January 6, 2017, the BOEM announced that it was extending the implementation timeline for NTL No. 2016-N01 by an additional six months as to leases, rights-of-way and rights of use and easement for which there are co-lessees and/or predecessors in interest, except in circumstances in which BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities. All of our decommissioning liabilities as of the date hereof have co-lessees and/or predecessors in interest and are expected to be included in this extended implementation timeline.

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 or that we will have sufficient liquidity to support such supplemental bonding requirements, and if we are unable to obtain the additional required bonds, assurances 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.

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 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 Item 3 Legal Proceedings in our Annual Report on Form 10-K for the year ended December 31, 2016.

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

25

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. As of March 31, 2017, we have deferred four dividend payments and have accrued a $6.4 million payable related to the four deferred payments and the quarterly dividend that was payable on April 15, 2017, which is included in other long-term liabilities on the Consolidated Balance Sheet. 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.

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

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended March 31, 2017.

	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program	Maximum Number (or Approximate Dollar Value) of Shares that May be Purchased Under the Plans or Programs
January 1 - January 31, 2017	322	$	4.02	—	—
February 1 - February 28, 2017	—	—		—	—
March 1 - March 31, 2017	—	$	—	—	—
Total	322	$	4.02	—	—

 ________________________

26

(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 $6.4 million.

Item 4. MINE SAFETY DISCLOSURES

NONE.

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

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

27

SIGNATURE

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

		PETROQUEST ENERGY, INC.
Date:	May 4, 2017	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief Financial Officer (Authorized Officer and Principal Financial and Accounting Officer)

28

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

May 4, 2017

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

May 4, 2017

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 March 31, 2017 (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

May 4, 2017

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 March 31, 2017 (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

May 4, 2017

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.

XML

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	Apr. 27, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		21,220,444

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 28,191	$ 28,312
Revenue receivable	9,269	10,294
Joint interest billing receivable	7,172	7,632
Derivative asset	168	0
Other current assets	3,794	2,353
Total current assets	48,594	48,591
Oil and gas properties:
Oil and gas properties, full cost method	1,331,930	1,323,333
Unevaluated oil and gas properties	11,909	9,015
Accumulated depreciation, depletion and amortization	(1,249,300)	(1,243,286)
Oil and gas properties, net	94,539	89,062
Other property and equipment	9,315	10,951
Accumulated depreciation of other property and equipment	(8,560)	(10,109)
Total property and equipment	95,294	89,904
Other assets	6,364	6,365
Total assets	150,252	144,860
Current liabilities:
Accounts payable to vendors	30,808	25,265
Advances from co-owners	3,879	2,330
Oil and gas revenue payable	22,639	22,146
Accrued interest	874	2,047
Asset retirement obligation	3,291	4,160
Derivative liability	1,729	3,947
10% Senior Unsecured Notes due 2017	0	22,568
Other accrued liabilities	3,211	3,938
Total current liabilities	66,431	86,401
Multi-draw Term Loan	27,429	7,249
Asset retirement obligation	32,958	32,450
Other long-term liabilities	6,491	6,027
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 21,214 and 21,197 shares, respectively	21	21
Paid-in capital	304,805	304,341
Accumulated other comprehensive loss	(1,562)	(4,750)
Accumulated deficit	(555,626)	(550,708)
Total stockholders’ equity	(252,361)	(251,095)
Total liabilities and stockholders’ equity	150,252	144,860
10% Senior Secured Notes due 2021 | Senior Notes
Current liabilities:
10% Senior Secured Notes	15,174	15,228
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Current liabilities:
10% Senior Secured Notes	$ 254,130	$ 248,600

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Mar. 31, 2017	Dec. 31, 2016
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	21,214,000	21,197,000
Common stock, shares outstanding	21,214,000	21,197,000
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%	10.00%
10% Senior Secured PIK Notes due 2021 | Payment in Kind (PIK) Note
Stated interest rate	10.00%	10.00%

XML

Consolidated Statements of Operations (unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Revenues:
Oil and gas sales	$ 20,772	$ 17,320
Expenses:
Lease operating expenses	7,076	8,177
Production taxes	308	338
Depreciation, depletion and amortization	6,117	10,138
Ceiling test write-down	0	18,857
General and administrative	3,153	8,599
Accretion of asset retirement obligation	547	608
Interest expense	7,258	8,257
Expenses	24,459	54,974
Other income:
Other income	54	97
Loss from operations	(3,633)	(37,557)
Income tax expense	0	86
Net loss	(3,633)	(37,643)
Preferred stock dividend	1,285	1,494
Loss available to common stockholders	$ (4,918)	$ (39,137)
Basic
Net income (loss) per share (in usd per share)	$ (0.23)	$ (2.31)
Diluted
Net income (loss) per share (in usd per share)	$ (0.23)	$ (2.31)
Weighted average number of common shares:
Basic (shares)	21,208	16,956
Diluted (shares)	21,208	16,956

XML

Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Net loss	$ (3,633)	$ (37,643)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $0, and $86, respectively	3,188	(145)
Comprehensive loss	$ (445)	$ (37,788)

XML

Consolidated Statements of Comprehensive Income (Loss) (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement of Comprehensive Income [Abstract]
Income tax (expense) benefit related to other comprehensive income due to derivatives	$ 0	$ 86

XML

Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Cash flows from operating activities:
Net loss	$ (3,633)	$ (37,643)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Deferred tax expense	0	86
Depreciation, depletion and amortization	6,117	10,138
Ceiling test writedown	0	18,857
Accretion of asset retirement obligation	547	608
Share-based compensation expense	425	442
Amortization costs and other	238	562
Non-cash PIK Interest	5,512	0
Payments to settle asset retirement obligations	(402)	(464)
Costs incurred to issue 2021 Notes	0	4,740
Changes in working capital accounts:
Revenue receivable	1,025	(842)
Joint interest billing receivable	460	10,709
Accounts payable and accrued liabilities	3,037	(20,413)
Advances from co-owners	1,549	(12,021)
Other	(1,462)	(949)
Net cash provided by (used in) operating activities	13,413	(26,190)
Cash flows used in investing activities:
Investment in oil and gas properties	(10,898)	(15,812)
Investment in other property and equipment	(16)	(23)
Sale of oil and gas properties	0	7,000
Net cash used in investing activities	(10,914)	(8,835)
Cash flows used in financing activities:
Net proceeds from share based compensation	40	65
Deferred financing costs	(10)	(38)
Payment of preferred stock dividend	0	(1,284)
Redemption of 2017 Notes	(22,650)	(53,626)
Costs incurred to issue 2021 Notes	0	(4,740)
Proceeds from borrowings	20,000	0
Net cash used in financing activities	(2,620)	(59,623)
Net decrease in cash and cash equivalents	(121)	(94,648)
Cash and cash equivalents, beginning of period	28,312	148,013
Cash and cash equivalents, end of period	28,191	53,365
Cash paid during the period for:
Interest	$ 2,975	$ 16,781

XML

Basis of Presentation

3 Months Ended

Mar. 31, 2017

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial information for the three month periods ended March 31, 2017 and 2016, has been prepared by the Company and was not audited by its independent registered public accountants. In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at March 31, 2017 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, 2016 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, 2016.

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).

XML

Acquisitions and Divestitures

3 Months Ended

Mar. 31, 2017

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Divestitures:

In March 2016, the Company sold certain non-producing assets in East Texas for $7 million to a potential joint venture partner. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties. After determining it would not pursue a joint venture with this party, the Company repurchased the non-producing assets for $5.0 million in December 2016 pursuant to the terms of the purchase and sale agreement related to this sale. The Company subsequently entered into a new drilling joint venture in East Texas with another group of partners.

On April 20, 2016, the Company completed the sale of a majority of its remaining Woodford Shale assets in the East Hoss field for approximately $18 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

On October 31, 2016, the Company completed the sale of its remaining Oklahoma assets for approximately $0.7 million. This sale was accounted for as an adjustment to the capitalized costs of oil and gas properties.

XML

Equity

3 Months Ended

Mar. 31, 2017

Equity [Abstract]

Equity

Equity

Common Stock

On May 18, 2016, the Company effected a reverse split of its 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 70.5 million shares to approximately 17.6 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 prior bank credit facility, which was terminated in October 2016, 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 March 31, 2017, the Company has deferred four dividend payments and has accrued a $6.4 million payable related to the four deferred payments and the quarterly dividend that was payable on April 15, 2017, 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. The Multidraw Term Loan Agreement (see Note 5) currently restricts the Company from paying cash dividends on the Series B Preferred Stock.

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, 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.

XML

Earnings Per Share

3 Months Ended

Mar. 31, 2017

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 March 31, 2017	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(4,918	)	21,208	$	(0.23	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(4,918	)	21,208	$	(0.23	)
For the Three Months Ended March 31, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(39,137	)	16,956	$	(2.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(39,137	)	16,956	$	(2.31	)

An aggregate of 1.5 million and 0.7 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 March 31, 2017 and 2016, 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

3 Months Ended

Mar. 31, 2017

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 February 17, 2016, the Company closed a private exchange offer (the "February Exchange") and consent solicitation (the "February Consent Solicitation") to certain eligible holders of its outstanding 2017 Notes. In satisfaction of the tender of $214.4 million in aggregate principal amount of the 2017 Notes, representing approximately 61% of the then outstanding aggregate principal amount of 2017 Notes, 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 September 27, 2016, the Company closed 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. In satisfaction of the consideration of $113.0 million in aggregate principal amount of the 2017 Notes, representing approximately 83% of the then outstanding aggregate principal amount of 2017 Notes, and $130.5 million in aggregate principal amount of the 2021 Notes, representing approximately 90% of the then 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. Following the consummation of the September Exchange, there were $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.

On March 31, 2017, the Company redeemed its remaining outstanding 2017 Notes at a redemption price of 100% of the principal amount thereof, plus accrued interest to the redemption date, in the amount of $22.8 million. The redemption was funded by cash on hand and amounts borrowed under the Multidraw Term Loan Agreement described below.

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. 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. The Company exercised this PIK option in connection with the interest payment due on February 15, 2017. As of March 31, 2017, the Company was 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 March 31, 2017, the Company was in compliance with all of the covenants under the 2021 Notes.

The February Exchange and September Exchange were accounted for as troubled debt restructurings pursuant to guidance provided by FASB Accounting Standards Codification ("ASC") Topic 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 is being amortized under the effective interest method over the term of the 2021 PIK Notes. At March 31, 2017, $0.6 million of the shortfall remained as part of the carrying value of the 2021 PIK Notes and the Company recognized $18 thousand of amortization expense as an increase to interest expense during the three months ended March 31, 2017.

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. 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 March 31, 2017, $1.1 million of the excess remained as part of the carrying value of the 2021 Notes and the Company recognized $0.1 million of amortization expense as a reduction to interest expense during the three months ended March 31, 2017.

The issuance of the 2021 Notes, 2021 PIK Notes and shares of common stock, as well as the exchange of the 2017 Notes and 2021 Notes, in the February Exchange and September Exchange represent non-cash financing activities for purposes of the Statement of Cash Flows.

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, jointly and severally, 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.

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 prior credit agreement with JPMorgan Chase Bank, N.A. 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 March 31, 2017, the Company has $30.0 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 PetroQuest Energy, L.L.C. (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 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 March 31, 2017, no default or event of default existed 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.

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

	March 31, 2017											December 31, 2016
	2017 Notes		2021 Notes			2021 PIK Notes			Term Loans			2017 Notes			2021 Notes			2021 PIK Notes			Term Loans
Face Value	$	—	$	14,177		$	251,868		$	30,000		$	22,650		$	14,177		$	243,468		$	10,000
Unamortized Deferred Financing Costs	—		(102		)	—			(2,571		)	(82		)	(108		)	—			(2,751		)
Excess (shortfall) Carrying Value	—		1,099			(572		)	—			—			1,159			(590		)	—
Accrued PIK Interest	—		—			2,834			—			—			—			5,722			—
Carrying Value	$	—	$	15,174		$	254,130		$	27,429		$	22,568		$	15,228		$	248,600		$	7,249

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Asset Retirement Obligation

3 Months Ended

Mar. 31, 2017

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):

	Three Months Ended March 31,
	2017			2016
Asset retirement obligation, beginning of period	$	36,610		$	42,556
Liabilities incurred	13			—
Liabilities settled	(540		)	(464		)
Accretion expense	547			608
Revisions in estimates	(381		)	—
Asset retirement obligation, end of period	36,249			42,700
Less: current portion of asset retirement obligation	(3,291		)	(5,545		)
Long-term asset retirement obligation	$	32,958		$	37,155

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Ceiling Test

3 Months Ended

Mar. 31, 2017

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, the prices used in computing the estimated future net cash flows from the Company's estimated proved reserves, including the effect of hedges in place at that date, averaged $2.19 per Mcf of natural gas, $45.92 per barrel of oil and $1.91 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $18.9 million during the three months ended March 31, 2016. The Company's cash flow hedges in place at March 31, 2016 decreased the ceiling test write-down by approximately $0.8 million. No such write-down occurred during the three months ended March 31, 2017.

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Derivative Instruments

3 Months Ended

Mar. 31, 2017

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 March 31, 2017, the Company's derivative instruments were designated as effective cash flow hedges.

Oil and gas sales include (reductions) additions related to the settlement of gas hedges of ($321,000) and $1,032,000 for the three months endedMarch 31, 2017 and 2016, respectively.

As of March 31, 2017, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April - December 2017	Swap	30,000 Mmbtu	$3.22
October - December 2017	Swap	10,000 Mmbtu	$3.22
January - March 2018	Swap	35,000 Mmbtu	$3.24

At March 31, 2017, the Company had recognized an accumulated other comprehensive loss of approximately $1.6 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of March 31, 2017, the Company would reclassify approximately $1.0 million, net of taxes, of accumulated other comprehensive loss into oil and gas sales during the next twelve months.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheets at March 31, 2017 and December 31, 2016:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
March 31, 2017	Derivative asset	$	168
March 31, 2017	Derivative liability	$	(1,729	)
December 31, 2016	Derivative liability	$	(3,947	)
December 31, 2016	Other long-term liabilities	$	(803	)

Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the three months ended March 31, 2017 and 2016:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into oil and gas sales
Commodity Derivatives at March 31, 2017	$	2,867	Oil and gas sales	$	(321	)
Commodity Derivatives at March 31, 2016	$	801	Oil and gas sales	$	1,032

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Fair Value Measurements

3 Months Ended

Mar. 31, 2017

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 instruments at March 31, 2017 and December 31, 2016 were in the form of swaps based on NYMEX pricing for natural gas. The fair value of these derivatives are 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 fair value of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2017 and December 31, 2016 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
March 31, 2017	$	—	$	(1,561	)	$	—
December 31, 2016	$	—	$	(4,750	)	$	—

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

	March 31, 2017						December 31, 2016
	Fair Value		Face Value		Carrying Value		Fair Value		Face Value		Carrying Value
2017 Notes	$	—	$	—	$	—	$	21,970	$	22,650	22,568
2021 Notes	12,618		14,177		15,174		12,192		14,177		15,228
2021 PIK Notes	191,420		251,868		254,130		177,732		243,468		248,600
	$	204,038	$	266,045	$	269,304	$	211,894	$	280,295	$	286,396

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Income Taxes

3 Months Ended

Mar. 31, 2017

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 $182.2 million and $177.4 million as of March 31, 2017 and December 31, 2016, respectively.

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Other Comprehensive Income

3 Months Ended

Mar. 31, 2017

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 March 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	2,867			—			2,867
Income tax effect	(1,066		)	1,066			—
Net of tax	1,801			1,066			2,867
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	321			—			321
Income tax effect	(120		)	120			—
Net of tax	201			120			321
Net other comprehensive income	2,002			1,186			3,188
Balance as of March 31, 2017	$	(981	)	$	(581	)	$	(1,562	)

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

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

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Recently Issued Accounting Standards

3 Months Ended

Mar. 31, 2017

Accounting Changes and Error Corrections [Abstract]

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, "Revenue from Contracts with Customers" to clarify the principles for recognizing revenue and to develop a common revenue standard and disclosure requirements. The core principle of ASU 2014-09 is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods and or services. In August 2015, the FASB issued ASU 2015-14 deferring the effective date of ASU 2014-09 by one year to interim and annual periods beginning on or after December 31, 2017. Entities can choose to apply the standard using either a full retrospective approach or a modified retrospective approach, with the cumulative effect of initially applying ASU 2014-09 recognized at the date of initial application. We expect to apply the modified retrospective approach upon adoption of this standard. The Company is currently evaluating the effect that this new standard will have on its consolidated financial statements and related disclosures, however, the Company does not expect the adoption of the standard will have a material impact on its consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, "Leases" (Topic 842)", to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The standard is effective for public entities for fiscal years beginning after December 15, 2018, and for interim periods within those fiscal years, with earlier application permitted. Upon adoption the lessee will apply the new standard retrospectively to all periods presented or retrospectively using a cumulative effect adjustment in the year of adoption. The Company is currently evaluating the impact of the new standard on its consolidated financial statements.

In March 2016, the FASB issued ASU 2016-09, "Compensation - Stock Compensation (Topic 718)" to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and forfeitures, as well as classification in the statement of cash flows. ASU 2016-09 became effective for us on January 1, 2017. The standard did not have a material impact on the Company's consolidated financial statements.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2017

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 March 31, 2017	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(4,918	)	21,208	$	(0.23	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(4,918	)	21,208	$	(0.23	)
For the Three Months Ended March 31, 2016	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(39,137	)	16,956	$	(2.31	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(39,137	)	16,956	$	(2.31	)

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2017

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, 2021 PIK Notes and Term Loans to the carrying value included in the Company's Consolidated Balance Sheet as of March 31, 2017 and December 31, 2016 (in thousands):

	March 31, 2017											December 31, 2016
	2017 Notes		2021 Notes			2021 PIK Notes			Term Loans			2017 Notes			2021 Notes			2021 PIK Notes			Term Loans
Face Value	$	—	$	14,177		$	251,868		$	30,000		$	22,650		$	14,177		$	243,468		$	10,000
Unamortized Deferred Financing Costs	—		(102		)	—			(2,571		)	(82		)	(108		)	—			(2,751		)
Excess (shortfall) Carrying Value	—		1,099			(572		)	—			—			1,159			(590		)	—
Accrued PIK Interest	—		—			2,834			—			—			—			5,722			—
Carrying Value	$	—	$	15,174		$	254,130		$	27,429		$	22,568		$	15,228		$	248,600		$	7,249

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Asset Retirement Obligation (Tables)

3 Months Ended

Mar. 31, 2017

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):

	Three Months Ended March 31,
	2017			2016
Asset retirement obligation, beginning of period	$	36,610		$	42,556
Liabilities incurred	13			—
Liabilities settled	(540		)	(464		)
Accretion expense	547			608
Revisions in estimates	(381		)	—
Asset retirement obligation, end of period	36,249			42,700
Less: current portion of asset retirement obligation	(3,291		)	(5,545		)
Long-term asset retirement obligation	$	32,958		$	37,155

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2017

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Oil and gas contracts

As of March 31, 2017, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
April - December 2017	Swap	30,000 Mmbtu	$3.22
October - December 2017	Swap	10,000 Mmbtu	$3.22
January - March 2018	Swap	35,000 Mmbtu	$3.24

Effect of Cash Flow Hedges on the Consolidated Balance Sheet

Effect of Cash Flow Hedges on the Consolidated Balance Sheets at March 31, 2017 and December 31, 2016:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
March 31, 2017	Derivative asset	$	168
March 31, 2017	Derivative liability	$	(1,729	)
December 31, 2016	Derivative liability	$	(3,947	)
December 31, 2016	Other long-term liabilities	$	(803	)

Effect of Cash Flow Hedges on the Consolidated Statement of Operations

Effect of Cash Flow Hedges on the Consolidated Statements of Operations and Comprehensive Loss for the three months ended March 31, 2017 and 2016:

Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into oil and gas sales
Commodity Derivatives at March 31, 2017	$	2,867	Oil and gas sales	$	(321	)
Commodity Derivatives at March 31, 2016	$	801	Oil and gas sales	$	1,032

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2017

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 fair value of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2017 and December 31, 2016 (in thousands):

	Fair Value Measurements Using
Instrument	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Commodity Derivatives:
March 31, 2017	$	—	$	(1,561	)	$	—
December 31, 2016	$	—	$	(4,750	)	$	—

Fair value of debt instruments

The following table summarizes the fair value, carrying value and face value of the 2017 Notes, 2021 Notes and 2021 PIK Notes as of March 31, 2017 and December 31, 2016 (in thousands):

	March 31, 2017						December 31, 2016
	Fair Value		Face Value		Carrying Value		Fair Value		Face Value		Carrying Value
2017 Notes	$	—	$	—	$	—	$	21,970	$	22,650	22,568
2021 Notes	12,618		14,177		15,174		12,192		14,177		15,228
2021 PIK Notes	191,420		251,868		254,130		177,732		243,468		248,600
	$	204,038	$	266,045	$	269,304	$	211,894	$	280,295	$	286,396

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Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2017

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 March 31, 2017 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of December 31, 2016	$	(2,983	)	$	(1,767	)	$	(4,750	)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	2,867			—			2,867
Income tax effect	(1,066		)	1,066			—
Net of tax	1,801			1,066			2,867
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	321			—			321
Income tax effect	(120		)	120			—
Net of tax	201			120			321
Net other comprehensive income	2,002			1,186			3,188
Balance as of March 31, 2017	$	(981	)	$	(581	)	$	(1,562	)

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

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

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Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended
	Dec. 31, 2016	Mar. 31, 2016	Mar. 31, 2017	Mar. 31, 2016	Oct. 31, 2016	Apr. 20, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of oil and gas properties		$ 7,000	$ 0	$ 7,000
Required purchase price of the non-producing assets if agreement not reached	$ 5,000
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
Oklahoma 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					$ 700

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Equity - Common Stock (Details) shares in Thousands	May 18, 2016 shares	Mar. 31, 2017 shares	Dec. 31, 2016 shares	May 17, 2016 shares
Class of Stock [Line Items]
Common stock, shares outstanding		21,214	21,197
Common Stock
Class of Stock [Line Items]
Reverse stock split, conversion ratio	0.25
Common stock, shares outstanding	17,600			70,500

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Equity - Convertible Preferred Stock (Details)	3 Months Ended
	Mar. 31, 2017 USD ($) dividend payment director $ / shares Rate shares	Dec. 31, 2016 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	4
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 | $	$ 6,400,000

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
A reconciliation between basic and diluted earnings per share computations
Loss available to common stockholders	$ (4,918)	$ (39,137)
Net income (loss) available to common stockholders (in shares)	21,208	16,956
Net income (loss) available to common stockholders (in dollars per share)	$ (0.23)	$ (2.31)
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
DILUTED EPS, Income (Loss)	$ (4,918)	$ (39,137)
DILUTED EPS (in shares)	21,208	16,956
DILUTED EPS (in dollars per share)	$ (0.23)	$ (2.31)

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Earnings Per Share - Narrative (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	1.5
Unvested Restricted Common Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share		0.7
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

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Long-Term Debt - Narrative (Details) shares in Millions					3 Months Ended
	Mar. 31, 2017 USD ($)	Oct. 17, 2016 USD ($)	Sep. 27, 2016 USD ($) payment shares	Feb. 17, 2016 USD ($) shares	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2017	Dec. 31, 2016 USD ($)	Jan. 14, 2016	Jul. 03, 2013 USD ($)	Aug. 19, 2010 USD ($)
Debt Instrument [Line Items]
Principal amount	$ 266,045,000				$ 266,045,000			$ 280,295,000
Amortization of financing costs					0	$ 4,740,000
Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Principal amount	$ 0				$ 0			$ 22,650,000		$ 200,000,000	$ 150,000,000
Stated interest rate	10.00%				10.00%			10.00%		10.00%	10.00%
Long-term debt	$ 0			$ 135,600,000	$ 0			$ 22,568,000
Excess (shortfall) carrying value	0				0			0
Deferred finance costs, net	0				0			(82,000)
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Principal amount	$ 14,177,000				$ 14,177,000			$ 14,177,000
Stated interest rate	10.00%				10.00%			10.00%
Long-term debt	$ 15,174,000				$ 15,174,000			$ 15,228,000
Excess (shortfall) carrying value	1,099,000				1,099,000			1,159,000
Deferred finance costs, net	(102,000)				(102,000)			(108,000)
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Principal amount	$ 251,868,000				$ 251,868,000			$ 243,468,000
Stated interest rate	10.00%				10.00%			10.00%
Long-term debt	$ 254,130,000				$ 254,130,000			$ 248,600,000
Excess (shortfall) carrying value	(572,000)				(572,000)			(590,000)
Deferred finance costs, net	$ 0				0			0
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]
Debt conversion, original debt, amount				$ 214,400,000
Debt conversion, original debt, percent of total				61.00%
Gain on extinguishment of debt				$ 0
Private Exchange Offer and Consent Solicitation | Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Stated interest rate									10.00%
Debt conversion, amount				144,700,000
Excess (shortfall) carrying value				$ 13,900,000
Amortization of financing costs					$ 100,000
Private Exchange Offer and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Stated interest rate	10.00%				10.00%
Excess (shortfall) carrying value	$ (600,000)		$ (600,000)		$ (600,000)
Amortization of financing costs					18,000
September Exchange and Consent Solicitation | Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Debt conversion, original debt, amount			$ 113,000,000
Debt conversion, original debt, percent of total			83.00%
Long-term debt			$ 22,700,000
Redemption price, percentage	100.00%
Repayments of debt	$ 22,800,000
September Exchange and Consent Solicitation | Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Debt conversion, original debt, amount			$ 130,500,000
Debt conversion, original debt, percent of total			90.00%
Long-term debt			$ 14,200,000
September Exchange and Consent Solicitation | Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Debt conversion, amount			$ 243,500,000
Number of interest payments with variable rate | payment			3
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%
Term Loan | Line of Credit
Debt Instrument [Line Items]
Principal amount	30,000,000				30,000,000			10,000,000
Long-term debt	27,429,000				27,429,000			7,249,000
Excess (shortfall) carrying value	0				0			0
Deferred finance costs, net	(2,571,000)				(2,571,000)			$ (2,751,000)
Term Loan | Line of Credit | Loan Agreement
Debt Instrument [Line Items]
Stated interest rate		10.00%
Long-term debt	$ 30,000,000				$ 30,000,000
First priority lien as percent of total value of oil and gas properties		90.00%
Borrowing availability period		3 years
Maximum borrowing capacity		$ 50,000,000
Covenant compliance, present value of estimated future net revenues, discount percent		10.00%
Covenant compliance, ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments	1.7				1.7
Scenario, Forecast | Term Loan | Line of Credit | Loan Agreement
Debt Instrument [Line Items]
Covenant compliance, ratio of present value of estimated future net revenues to sum of outstanding term loans and commitments							2

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Long-Term Debt - Face Value to Carrying Value Reconciliation (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016	Feb. 17, 2016	Jul. 03, 2013	Aug. 19, 2010
Debt Instrument [Line Items]
Face Value	$ 266,045,000	$ 280,295,000
Senior Notes | 10% Senior Unsecured Notes due 2017
Debt Instrument [Line Items]
Face Value	0	22,650,000		$ 200,000,000	$ 150,000,000
Unamortized Deferred Financing Costs	0	(82,000)
Excess (shortfall) Carrying Value	0	0
Carrying Value	0	22,568,000	$ 135,600,000
Senior Notes | 10% Senior Secured Notes due 2021
Debt Instrument [Line Items]
Face Value	14,177,000	14,177,000
Unamortized Deferred Financing Costs	(102,000)	(108,000)
Excess (shortfall) Carrying Value	1,099,000	1,159,000
Carrying Value	15,174,000	15,228,000
Payment in Kind (PIK) Note | 10% Senior Secured PIK Notes due 2021
Debt Instrument [Line Items]
Face Value	251,868,000	243,468,000
Unamortized Deferred Financing Costs	0	0
Excess (shortfall) Carrying Value	(572,000)	(590,000)
Accrued PIK Interest	2,834,000	5,722,000
Carrying Value	254,130,000	248,600,000
Line of Credit | Term Loan
Debt Instrument [Line Items]
Face Value	30,000,000	10,000,000
Unamortized Deferred Financing Costs	(2,571,000)	(2,751,000)
Excess (shortfall) Carrying Value	0	0
Carrying Value	$ 27,429,000	$ 7,249,000

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 36,610	$ 42,556
Liabilities incurred	13	0
Liabilities settled	(540)	(464)
Accretion expense	547	608
Revisions in estimates	(381)	0
Asset retirement obligation, end of period	36,249	42,700
Less: current portion of asset retirement obligation	(3,291)	(5,545)	$ (4,160)
Long-term asset retirement obligation	$ 32,958	$ 37,155	$ 32,450

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Ceiling Test (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2017 USD ($)	Mar. 31, 2016 USD ($) $ / mcf $ / Mcfe $ / bbl
Reserve Quantities [Line Items]
Rate for discounting future cash flows	10.00%
Decrease (Increase) in ceiling test write-downs	$ 0	$ 18,857
Mcf of natural gas
Reserve Quantities [Line Items]
Average sales prices | $ / mcf		2.19
Barrel of oil
Reserve Quantities [Line Items]
Average sales prices | $ / bbl		45.92
Mcfe of Ngl
Reserve Quantities [Line Items]
Average sales prices | $ / Mcfe		1.91
Commodity Derivatives | Cash Flow Hedging
Reserve Quantities [Line Items]
Decrease (Increase) in ceiling test write-downs		$ 800

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Derivative Instruments (Details) - Swap - Natural Gas:	3 Months Ended
	Mar. 31, 2017 MMBTU $ / shares
April - December 2017
Oil and gas contracts
Daily Volumes | MMBTU	30,000
Weighted Average Price | $ / shares	$ 3.22
October - December 2017
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price | $ / shares	$ 3.22
January - March 2018
Oil and gas contracts
Daily Volumes | MMBTU	35,000
Weighted Average Price | $ / shares	$ 3.24

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Derivative Instruments - Fair Value of Effective Cash Flow Hedges (Details 1) - Commodity Derivatives - Designated as Hedging Instrument - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset	$ 168
Derivative liability
Derivatives, Fair Value [Line Items]
Derivative liability	$ (1,729)	$ (3,947)
Other long-term liabilities
Derivatives, Fair Value [Line Items]
Derivative liability		$ (803)

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Derivative Instruments - Effect of Cash Flow Hedges on the Statement of Operations (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Recognized in Other Comprehensive Income	$ 3,188	$ (145)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Recognized in Other Comprehensive Income	2,867	801
Designated as Hedging Instrument | Oil and gas sales
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified into oil and gas sales	$ (321)	$ 1,032

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Derivative Instruments - Textual (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Accumulated other comprehensive loss	$ (1,562)		$ (4,750)
Gain (loss) to be reclassified	(1,000)
Gas hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	$ (321)	$ 1,032

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Fair Value Measurements (Details) - USD ($)	Mar. 31, 2017	Dec. 31, 2016	Jul. 03, 2013	Aug. 19, 2010
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Face Value	$ 266,045,000	$ 280,295,000
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	0	22,650,000	$ 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	14,177,000
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	251,868,000	243,468,000
Fair Value
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	204,038,000	211,894,000
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	0	21,970,000
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	12,618,000	12,192,000
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	191,420,000	177,732,000
Carrying Value
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Long-term debt, fair value	269,304,000	286,396,000
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	0	22,568,000
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	15,174,000	15,228,000
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	254,130,000	248,600,000
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	(1,561,000)	(4,750,000)
Significant Unobservable Inputs (Level 3)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	$ 0	$ 0

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income taxes at a statutory rate	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 182.2	$ 177.4

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Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	$ (251,095)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	2,867
Income tax effect	0
Net of tax	2,867
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	321
Income tax effect	0
Net of tax	321
Net other comprehensive income (loss)	3,188
Ending balance	(252,361)
Gains and Losses on Cash Flow Hedges
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(2,983)	$ 947
Other comprehensive income before reclassifications:
Change in fair value of derivatives	2,867	801
Income tax effect	(1,066)	(298)
Net of tax	1,801	503
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	321	(1,032)
Income tax effect	(120)	384
Net of tax	201	(648)
Net other comprehensive income (loss)	2,002	(145)
Ending balance	(981)	$ 802
Change in Valuation Allowance
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(1,767)
Other comprehensive income before reclassifications:
Change in fair value of derivatives	0
Income tax effect	1,066
Net of tax	1,066
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	0
Income tax effect	120
Net of tax	120
Net other comprehensive income (loss)	1,186
Ending balance	(581)
Total
Accumulated other Comprehensive Income [Roll Forward]
Beginning balance	(4,750)
Amounts reclassified from accumulated other comprehensive loss:
Ending balance	$ (1,562)