10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2013

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

For the transition period from:                    to:                    

Commission file number: 001-32681

_________________________________________________________________

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

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

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

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

As of November 1, 2013 there were 64,484,346 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

	Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	1
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2013 and 2012	2
Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2013 and 2012	3
Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2013 and 2012	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	21
Item 4. Controls and Procedures	22
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	25
Item 3. Defaults upon Senior Securities	25
Item 4. Mine Safety Disclosures	25
Item 5. Other Information	25
Item 6. Exhibits	26

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	September 30, 2013			December 31, 2012
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	19,409		$	14,904
Revenue receivable	31,561			17,742
Joint interest billing receivable	27,212			42,595
Other receivable	—			9,208
Derivative asset	2,323			830
Prepaid drilling costs	963			1,698
Other current assets	7,411			2,607
Total current assets	88,879			89,584
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	2,003,907			1,734,477
Unevaluated oil and gas properties	87,117			71,713
Accumulated depreciation, depletion and amortization	(1,530,928		)	(1,472,244		)
Oil and gas properties, net	560,096			333,946
Other property and equipment	13,340			12,370
Accumulated depreciation of other property and equipment	(8,512		)	(7,607		)
Total property and equipment	564,924			338,709
Derivative asset	305			—
Other assets, net of accumulated depreciation and amortization of $5,166 and $4,240, respectively	9,783			5,110
Total assets	$	663,891		$	433,403
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	31,353		$	58,960
Advances from co-owners	7,144			20,459
Oil and gas revenue payable	45,438			26,175
Accrued interest and preferred stock dividend	4,175			6,190
Asset retirement obligation	1,502			2,351
Derivative liability	525			233
Other accrued liabilities	9,616			6,535
Total current liabilities	99,753			120,903
Bank debt	75,000			50,000
10% Senior Notes	350,000			150,000
Asset retirement obligation	41,350			24,909
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 63,353 and 62,768 shares, respectively	63			63
Paid-in capital	279,260			276,534
Accumulated other comprehensive income	1,340			521
Accumulated deficit	(182,876		)	(189,528		)
Total stockholders’ equity	97,788			87,591
Total liabilities and stockholders’ equity	$	663,891		$	433,403

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2013		2012			2013			2012
Revenues:
Oil and gas sales	$	55,578	$	33,913		$	129,630		$	103,286
Gas gathering revenue	9		38			68			119
	55,587		33,951			129,698			103,405
Expenses:
Lease operating expenses	12,652		9,658			31,208			28,408
Production taxes	1,248		880			3,757			112
Depreciation, depletion and amortization	22,475		15,032			49,882			46,024
Ceiling test write-down	—		35,391			—			108,987
General and administrative	9,132		5,963			20,199			17,541
Accretion of asset retirement obligation	543		525			1,203			1,542
Interest expense	8,071		2,338			14,051			7,021
	54,121		69,787			120,300			209,635
Other income (expense):
Other income	176		257			432			529
Derivative income (expense)	45		(340		)	202			(715		)
	221		(83		)	634			(186		)
Income (loss) from operations	1,687		(35,919		)	10,032			(106,416		)
Income tax expense (benefit)	17		1,435			(474		)	1,496
Net income (loss)	1,670		(37,354		)	10,506			(107,912		)
Preferred stock dividend	1,287		1,285			3,854			3,855
Net income (loss) available to common stockholders	$	383	$	(38,639	)	$	6,652		$	(111,767	)
Earnings per common share:
Basic
Net income (loss) per share	$	0.01	$	(0.62	)	$	0.10		$	(1.79	)
Diluted
Net income (loss) per share	$	0.01	$	(0.62	)	$	0.10		$	(1.79	)
Weighted average number of common shares:
Basic	63,096		62,492			62,936			62,356
Diluted	63,242		62,492			63,105			62,356

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013		2012
Net income (loss)	$	1,670		$	(37,354	)	$	10,506	$	(107,912	)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of $(46), $1,435, $485 and $2,032, respectively.	(78		)	(2,423		)	819		(3,431		)
Comprehensive income (loss)	$	1,592		$	(39,777	)	$	11,325	$	(111,343	)

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Nine Months Ended
	September 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	10,506		$	(107,912	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	(474		)	1,496
Depreciation, depletion and amortization	49,882			46,024
Ceiling test writedown	—			108,987
Accretion of asset retirement obligation	1,203			1,542
Share based compensation expense	3,105			5,609
Amortization costs and other	1,138			594
Non-cash derivative (income) expense	(202		)	715
Payments to settle asset retirement obligations	(2,415		)	(2,519		)
Changes in working capital accounts:
Revenue receivable	(13,819		)	141
Prepaid drilling and pipe costs	735			2,891
Joint interest billing receivable	13,612			20,312
Accounts payable and accrued liabilities	(11,781		)	1,464
Advances from co-owners	(13,315		)	(8,802		)
Other	(5,266		)	(2,866		)
Net cash provided by operating activities	32,909			67,676
Cash flows used in investing activities:
Investment in oil and gas properties	(261,707		)	(121,428		)
Investment in other property and equipment	(970		)	—
Sale of oil and gas properties	18,915			837
Sale of unevaluated oil and gas properties	—			6,083
Net cash used in investing activities	(243,762		)	(114,508		)
Cash flows provided by financing activities:
Net payments for share based compensation plans	(379		)	(840		)
Deferred financing costs	(487		)	(33		)
Payment of preferred stock dividend	(3,854		)	(3,855		)
Proceeds from issuance of 10% Senior Notes	200,000			—
Deferred financing costs of 10% Senior Notes	(4,922		)	—
Proceeds from bank borrowings	62,000			72,500
Repayment of bank borrowings	(37,000		)	(37,500		)
Net cash provided by financing activities	215,358			30,272
Net increase (decrease) in cash and cash equivalents	4,505			(16,560		)
Cash and cash equivalents, beginning of period	14,904			22,263
Cash and cash equivalents, end of period	$	19,409		$	5,703
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	19,479		$	15,628
Income taxes	$	11		$	15

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Basis of Presentation

The consolidated financial information for the three and nine month periods ended September 30, 2013 and 2012, 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 September 30, 2013 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, 2012 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, 2012. Certain prior year amounts have been reclassified to conform to current year presentations.

Unless the context otherwise indicates, any references in this Quarterly Report on Form 10-Q to “PetroQuest” or the “Company” refer to PetroQuest Energy, Inc. (Delaware) 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—Acquisition

On July 3, 2013, the Company acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $188.2 million, subject to customary adjustments to reflect an effective date of January 1, 2013 (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets included 16 wells located on seven platforms.

The aggregate cash purchase price of the Gulf of Mexico Acquisition was financed with the net proceeds from the sale in a private offering under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the "Securities Act"), of $200 million aggregate principal amount of the Company's 10% Senior Notes due 2017.  The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes"). The New Notes have terms that, subject to certain exceptions, are substantially identical to the Company's existing $150 million aggregate principal amount of 10% Senior Notes due 2017. The Company recorded $0.9 million of deferred financing costs related to the New Notes in the second and third quarters of 2013 and an additional $4.0 million of deferred financing costs related to the underwriting fee paid to the initial purchasers of the New Notes on the closing date of July 3, 2013. The Company also incurred $3.9 million of acquisition-related costs, including $2.6 million related to a bridge commitment fee, which were recognized as general and administrative expenses.

The Gulf of Mexico Acquisition is accounted for under the purchase method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is preliminary and based on management's best estimates of the fair value of the assets acquired and liabilities assumed as of the date of this Form 10-Q. The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

The fair value of proved and unevaluated oil and gas properties was estimated using the income approach based on estimated reserve quantities, costs to produce and develop reserves, and forward prices for oil and gas, which represent Level 2 and Level 3 inputs. Asset retirement obligations were determined in accordance with applicable accounting standards.

The following table summarizes the estimated acquisition date fair values of the net assets acquired (in thousands):

Oil and gas properties	$	191,466
Unevaluated oil and gas properties	12,033
Asset retirement obligations	(15,319		)
Net assets to be acquired	$	188,180

5

The following unaudited summary pro forma statement of operations for the three and nine month periods ended September 30, 2013 and 2012 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts in millions, except per share amounts.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Revenues	$	55,587	$	46,384		$	162,494	$	132,303
Income (Loss) from Operations	4,318		(38,178		)	15,487		(121,955		)
Net Income (Loss) available to common stockholders	3,014		(40,898		)	12,107		(127,306		)
Basic Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)
Diluted Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)

Note 3—Convertible Preferred Stock

The Company has 1,495,000 shares of 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”) outstanding.

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.

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

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

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

6

Note 4—Earnings Per Share

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

For the Three Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	383		63,096
Attributable to participating securities	(8		)
BASIC EPS	$	375		63,096	$	0.01
Net income available to common stockholders	383			63,096
Effect of dilutive securities:
Stock options	—			146
Attributable to participating securities	(8		)	—
DILUTED EPS	$	375		63,242	$	0.01
For the Nine Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	6,652		62,936
Attributable to participating securities	(151		)
BASIC EPS	$	6,501		62,936	$	0.10
Net income available to common stockholders	$	6,652		62,936
Effect of dilutive securities:
Stock options				169
Attributable to participating securities	(151		)	—
DILUTED EPS	$	6,501		63,105	$	0.10
For the Three Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(38,639	)	62,492	$	(0.62	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(38,639	)	62,492	$	(0.62	)
For the Nine Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(111,767	)	62,356	$	(1.79	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(111,767	)	62,356	$	(1.79	)

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2013 because the inclusion would have been anti-dilutive. Options to purchase 1,199,000 and 1,245,000 shares of common stock were outstanding during the three and nine month periods ended September 30, 2013, respectively, and were not included in the computation of diluted earnings per share because the options' exercise prices were in excess of the average market price of the common shares.

7

An aggregate of 1,104,000 and 943,000 shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2012, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the respective periods.

Note 5—Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of 10% Senior Notes due 2017 (the “ Existing Notes”) in a public offering. On July 3, 2013, the Company closed a private offering of $200 million aggregate principal amount of 10% Senior Notes due 2017. The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of their face value plus accrued interest from March 1, 2013.  The New Notes have terms that, subject to certain exceptions, are substantially identical to the Existing Notes. The net proceeds from the offering were used to finance the $188.2 million aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013.

The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At September 30, 2013, $2.9 million had been accrued in connection with the March 1, 2014 interest payment and the Company was in compliance with all of the covenants contained in the Notes.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A. and IberiaBank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3, 2016. As of September 30, 2013 the Company had $75.0 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. On July 3, 2013 the borrowing base was increased from $150 million to $200 million (subject to the aggregate commitments of the lenders then in effect). As of September 30, 2013, the aggregate commitments of the lenders was $150 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2014. The Company or the lenders may request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 80% of the aggregate total value of the Company’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a tiered rolling four quarter basis, of 3.5 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common

8

stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of September 30, 2013, the Company was in compliance with all of the covenants contained in the Credit Agreement.

Note 6—Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2013			2012
Asset retirement obligation, beginning of period	$	27,260		$	30,427
Liabilities incurred	498			867
Liabilities assumed	15,319			—
Liabilities settled	(2,415		)	(2,519		)
Accretion expense	1,203			1,542
Revisions in estimated cash flows	987			(42		)
Asset retirement obligation, end of period	42,852			30,275
Less: current portion of asset retirement obligation	(1,502		)	(1,034		)
Long-term asset retirement obligation	$	41,350		$	29,241

Note 7—Share-Based Compensation

Share-based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share-based compensation expense for the three and nine month periods ended September 30, 2013 and 2012 is as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	86	$	211	$	175	$	646
Non-Qualified Stock Options	41		181		176		509
Restricted stock	1,182		1,379		2,754		4,454
Restricted stock units	604		—		1,147		—
Share based compensation	$	1,913	$	1,771	$	4,252	$	5,609

Note 8—Ceiling Test

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

At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of the Company’s longer-lived estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of $35.4 million and $109.0 million during the three and nine months ended September 30, 2012, respectively. The Company’s cash flow hedges in place at September 30, 2012decreased the ceiling test write-down by approximately $2.1 million. The Company recognized no such ceiling test write-down during the three and nine months ended September 30, 2013.

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Note 9—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, natural gas or natural gas liquids (Ngl) 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). At September 30, 2013, the Company designated all but three of its derivative instruments as effective cash flow hedges. The Company does not have master netting arrangements with any of its counterparties. Accordingly, derivative assets and liabilities are recorded on a gross basis in the consolidated balance sheet.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $767,000 and $1,482,000, Ngl hedges of $5,000 and $312,000 and oil hedges of ($538,000) and $491,000 for the three months endedSeptember 30, 2013 and 2012, respectively. For the nine month periods ended September 30, 2013 and 2012, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $422,000 and $6,867,000, Ngl hedges of $5,000 and $544,000 and oil hedges of ($684,000) and $853,000, respectively.

As of September 30, 2013, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes		Weighted Average Price
Natural Gas:
October - December 2013	Three-Way Collar	10,000 Mmbtu		$2.00-$3.00-$4.09
October - December 2013	Swap	30,000 Mmbtu		$3.78
October - December 2013	Collar	5,000 Mmbtu		$4.00 - $4.75
2014	Swap	20,000 Mmbtu		$4.04
Crude Oil:
October - December 2013	Swap	1,350 Bbls	(1)	$102.45
January - June 2014	Swap	200 Bbls	(3)	$101.30
2014	Swap	750 Bbls	(2)	$97.47
Natural Gas Liquids:
October - December 2013	Swap	150 Bbls		$92.42

(1) 500 Bbls per day tied to LLS index.

(2) 400 Bbls per day tied to LLS index.

(3) 200 Bbls per day tied to LLS index.

At September 30, 2013, the Company had accumulated other comprehensive income of approximately $1.3 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of September 30, 2013, the Company would realize a $1.1 milliongain, net of taxes, during the next 12 months. This gain is expected to be reclassified based on the schedule of volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	2,274
September 30, 2013	Derivative asset (long-term)	$	305
September 30, 2013	Derivative liability (short-term)	$	(445	)
December 31, 2012	Derivative asset (short-term)	$	830

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Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Loss Recognized in Other Comprehensive Income			Location of Gain Reclassified into Income	Amount of Gain Reclassified into Income
Commodity Derivatives at September 30, 2013	$	(78	)	Oil and gas sales	$	436
Commodity Derivatives at September 30, 2012	$	(2,423	)	Oil and gas sales	$	2,285

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012 :

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2013	$	819		Oil and gas sales	$	(18	)
Commodity Derivatives at September 30, 2012	$	(3,431	)	Oil and gas sales	$	8,264

Derivatives not designated as hedging instruments:

The following tables reflect the fair value of the Company’s non-designated derivative instruments in the consolidated financial statements (in thousands):

Effect of Non-designated Derivative Instruments on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	49
September 30, 2013	Derivative liability (short-term)	$	(80	)
December 31, 2012	Derivative liability (short-term)	$	(233	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	45
Commodity Derivatives at September 30, 2012	$	(340	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	202
Commodity Derivatives at September 30, 2012	$	(715	)

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Note 10 – 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 September 30, 2013 were in the form of a three-way collar, a zero cost collar and swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of September 30, 2013 and December 31, 2012 (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:
At September 30, 2013	$	—	$	2,103	$	—
At December 31, 2012	$	—	$	597	$	—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at September 30, 2013 and December 31, 2012. The estimated fair value of the Notes was $350.9 million and $155.3 million as of September 30, 2013 and December 31, 2012, respectively, as compared to the book value of $350 million and $150 million as of September 30, 2013 and December 31, 2012, respectively. The estimated fair value of the Notes was provided by independent brokers using the actual period end quotes for the Notes, which represent Level 2 inputs.

Note 11—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 expense and state income taxes. As a result of the 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 $47.2 million as of September 30, 2013.

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Note 12 - Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2013	$	1,418
Other comprehensive income before reclassifications	196
Amounts reclassified from accumulated other comprehensive income	(274		)
Net other comprehensive loss	(78		)
Balance as of September 30, 2013	$	1,340

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2012	$	521
Other comprehensive income before reclassifications	808
Amounts reclassified from accumulated other comprehensive income	11
Net other comprehensive income	819
Balance as of September 30, 2013	$	1,340

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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 Oklahoma, Texas and the Gulf Coast Basin. 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 in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

We have successfully diversified into onshore, longer life basins in Oklahoma and Texas through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in East Texas through 2012, we have invested approximately $998 million into growing our longer life assets. During the nine year period ended December 31, 2012, we have realized a 95% drilling success rate on 878 gross wells drilled. Comparing 2012 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 252% and estimated proved reserves by 174%. At September 30, 2013, 80% of our estimated proved reserves and 66% of our first nine months 2013 production were derived from our longer life assets.

Gas prices have remained weak since late-2008.  As a result of the impact of low natural gas prices on our revenues and cash flow, we have focused on growing our reserves and production through a balanced drilling budget with an increased emphasis on growing our oil and natural gas liquids production.  In May 2010, we entered into the Woodford joint development agreement ("JDA"), which provided us with $85 million in cash during 2010 and 2011, along with a drilling carry that we have utilized since May 2010 to enhanceeconomic returns by reducing our share of capital expenditures in the Woodford Shale and Mississippian Lime.  As a result of the JDA and the success of our drilling programs, as of December 31, 2012 we grew our estimated proved reserves by 18% and production by 10% since 2010, while maintaining our long-term debt 28% below 2008 levels.

On July 3, 2013, we acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $188.2 million, subject to customary adjustments to reflect an effective date of January 1, 2013, (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets include 16 wells located on 7 platforms. We believe the acquisition of the Acquired Assets represents both a strategic and transformative transaction for us. This transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop our longer life resource assets. We plan to utilize a portion of the free cash flow generated from these acquired properties to accelerate the development of our Woodford Shale and Cotton Valley resource plays.

Critical Accounting Policies

Reserve Estimates

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

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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 further 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

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 oil and natural gas and OPIS Mt. Belvieu for natural gas liquids. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX and OPIS Mt. Belvieu prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX and OPIS Mt. Belvieu prices at which the hedges will be settled. At September 30, 2013, our derivative instruments, with the exception of our three-way collar and two of our oil swaps, were designated as effective cash flow hedges.

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

Results of Operations

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Production:
Oil (Bbls)	219,402		122,645		460,822		379,958
Gas (Mcf)	8,351,200		6,888,569		21,519,550		20,563,350
Ngl (Mcfe)	1,238,719		894,138		3,560,179		2,250,569
Total Production (Mcfe)	10,906,331		8,518,577		27,844,661		25,093,667
Sales:
Total oil sales	$	23,663,415	$	13,287,548	$	48,831,937	$	41,627,602
Total gas sales	25,009,383		15,583,994		61,980,015		46,321,605
Total ngl sales	6,905,048		5,041,274		18,818,166		15,336,515
Total oil and gas sales	$	55,577,846	$	33,912,816	$	129,630,118	$	103,285,722
Average sales prices:
Oil (per Bbl)	$	107.85	$	108.34	$	105.97	$	109.56
Gas (per Mcf)	2.99		2.26		2.88		2.25
Ngl (per Mcfe)	5.57		5.64		5.29		6.81
Per Mcfe	5.10		3.98		4.66		4.12

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $767,000 and $1,482,000, Ngl hedges of $5,000 and $312,000 and oil hedges of ($538,000) and $491,000 for the three months endedSeptember 30, 2013 and 2012, respectively. The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $422,000 and $6,867,000, Ngl hedges of $5,000 and $544,000, and oil hedges of ($684,000) and $853,000 for the nine months ended September 30, 2013 and 2012, respectively.

Net income (loss) available to common stockholders totaled $383,000 and ($38,639,000) for the quarters ended September 30, 2013 and 2012, respectively, while net income (loss) available to common stockholders totaled $6,652,000 and ($111,767,000) for the nine months ended September 30, 2013 and 2012, respectively. The primary fluctuations were as follows:

Production Total production increased28% and 11% during the three and nine month periods ended September 30, 2013 as compared to the respective 2012 periods. Gas production during the three and nine month periods ended September 30, 2013increased21% and 5% from the comparable periods in 2012. The increases in gas production were primarily the result of added

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production from the wells acquired in the Gulf of Mexico Acquisition which closed on July 3, 2013. Additionally, gas production increased as a result of the successful drilling programs in our La Cantera field and our liquids rich Woodford acreage. Partially offsetting these increases were decreases in gas production due to normal production declines at our dry gas Oklahoma fields as well as certain of our legacy Gulf of Mexico fields in addition to the loss of production resulting from the sale of our Fayetteville assets in December 2012. For the remainder of 2013, we expect our average daily gas production to continue to increase as compared to 2012.

Oil production during the three and nine month periods ended September 30, 2013increased79% and 21%, respectively, from the 2012 periods due primarily to added production from the wells acquired in the Gulf of Mexico Acquisition as well as the continued success of our La Cantera field. Partially offsetting these increases were decreases as a result of continued normal production declines in certain of our legacy Gulf of Mexico and East Texas fields. As a result of added production from the wells acquired in the Gulf of Mexico Acquisition, we expect our average daily oil production during the remainder of 2013 to continue to increase significantly as compared to 2012.

Ngl production during the three and nine month periods ended September 30, 2013increased39% and 58% from the respective 2012 periods due to the success experienced in our La Cantera field and the liquids rich portion of our Oklahoma properties, as well as added production from the wells acquired in the Gulf of Mexico Acquisition. Partially offsetting these increases were decreases as a result of normal production declines at certain of our offshore Gulf of Mexico fields. As a result of the above, we expect our daily Ngl production for the remainder of 2013 to continue to increase as compared to 2012.

Prices Including the effects of our hedges, average gas prices per Mcf for the three and nine month periods ended September 30, 2013 were $2.99 and $2.88 as compared to $2.26 and $2.25 for the respective 2012 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2013 were $107.85 and $105.97 as compared to $108.34 and $109.56 for the 2012 periods and average Ngl prices per Mcfe were $5.57 and $5.29 for the three and nine months ended September 30, 2013, as compared to $5.64 and $6.81 for the 2012 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2013 were 28% and 13%higher, respectively, than prices received during the comparable 2012 periods.

Revenue Including the effects of hedges, oil and gas sales during the three months endedSeptember 30, 2013increased64% to $55,578,000, as compared to oil and gas sales of $33,913,000 during the 2012 period. Including the effects of hedges, oil and gas sales during the nine months endedSeptember 30, 2013increased26% to $129,630,000, as compared to oil and gas sales of $103,286,000 during the 2012 period. These increases were primarily the result of higher average realized prices for our production during the 2013 periods and increased production as discussed above.

Expenses Lease operating expenses for the three and nine months ended September 30, 2013 totaled $12,652,000 and $31,208,000, respectively, as compared to $9,658,000 and $28,408,000 during the 2012 periods. Per unit lease operating expenses totaled $1.16 and $1.12 per Mcfe, respectively, during the three and nine month periods ended September 30, 2013 as compared to $1.13 per Mcfe during the respective 2012 periods. We expect the absolute amount of lease operating expenses to increase during the remainder of 2013 as a result of the Gulf of Mexico Acquisition, but we expect per unit lease operating costs to approximate per unit amounts in 2012.

Production taxes for the three and nine months ended September 30, 2013 totaled $1,248,000 and $3,757,000, respectively, as compared to $880,000 and $112,000, respectively, during the 2012 periods. Production taxes during 2012 were lowered as a result of recording a receivable of $2,717,000 during the second quarter of 2012 for refunds relative to production taxes previously paid on our Oklahoma horizontal wells that we expect to receive over three years. Because the majority of the assets purchased in the Gulf of Mexico Acquisition are located in Federal waters and are therefore not subject to production taxes, we do not expect a meaningful change to our production taxes as a result of the Gulf of Mexico Acquisition.

General and administrative expenses during the three and nine months ended September 30, 2013 totaled $9,132,000 and $20,199,000, respectively, as compared to $5,963,000 and $17,541,000 during the 2012 periods. Included in general and administrative expenses was non-cash share-based compensation expense as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	86	$	211	$	175	$	646
Non-Qualified Stock Options	41		181		176		509
Restricted stock	1,182		1,379		2,754		4,454
Non-cash share based compensation	$	1,309	$	1,771	$	3,105	$	5,609

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General and administrative expenses increased15% during the nine months ended September 30, 2013 as compared to the comparable period of 2012. Included in general and administrative expenses for the three and nine months endedSeptember 30, 2013 is $2,872,000 and $3,878,000, respectively, of transaction-related costs related to the Gulf of Mexico Acquisition. In addition, during the third quarter of 2013, we recognized approximately $1,009,000 in general and administrative expenses associated with benefits due under the compensation agreements of the Company's Executive Vice-President and General Counsel, who passed away unexpectedly in September 2013. We capitalized $3,526,000 and $9,682,000, respectively, of general and administrative costs during the three and nine month periods ended September 30, 2013 compared to $3,276,000 and $9,582,000, respectively, during the 2012 periods. We expect our general and administrative expenses in the fourth quarter of 2013 to decrease from third quarter amounts.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and nine months ended September 30, 2013 totaled $22,107,000, or $2.03 per Mcfe, and $48,978,000, or $1.76 per Mcfe, respectively, as compared to $14,736,000, or $1.73 per Mcfe, and $45,203,000, or $1.80 per Mcfe, respectively, during the comparable 2012 periods. The increase in the per unit DD&A rate for the three month 2013 period is primarily the result of the purchase price of the assets acquired in the Gulf of Mexico Acquisition. As a result of the impact of the Gulf of Mexico Acquisition, we expect our DD&A rate to increase during the remainder of 2013.

At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of $35,391,000 and $108,987,000 during the three and nine months ended September 30, 2012, respectively. Our cash flow hedges in place at September 30, 2012decreased the ceiling test write-down by approximately $2,100,000.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $8,071,000 and $14,051,000 during the three and nine months ended September 30, 2013, respectively, as compared to $2,338,000 and $7,021,000, respectively, during the 2012 periods. During the three and nine month periods ended September 30, 2013, our capitalized interest totaled $1,757,000 and $4,525,000, respectively, as compared to $1,869,000 and $5,452,000, respectively, during the 2012 periods. The increases in interest expense were a result of the issuance of $200 million of 10% senior notes due 2017, which were used to finance the Gulf of Mexico Acquisition in addition to increased borrowings outstanding under our bank credit facility during the 2013 periods as compared to the prior year periods. As a result, we expect interest expense to remain higher than 2012 levels.

Income tax expense (benefit) during the three and nine months ended September 30, 2013 totaled $17,000 and ($474,000), respectively, as compared to $1,435,000 and $1,496,000, respectively, during the 2012 periods. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of the ceiling test write-downs recognized in 2012, 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 $47,183,000 as of September 30, 2013.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, issuances of equity and debt securities, joint ventures and sales of assets. At September 30, 2013 we had a working capital deficit of approximately $11 million as compared to a working capital deficit of approximately $31 million as of December 31, 2012. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage our working capital deficit and liquidity position. To the extent our capital expenditures during the remainder of 2013 exceed our cash flow and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of assets to fund a portion of our drilling budget.

Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and natural gas that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Lower prices and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants

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in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as oil and natural gas prices.

Source of Capital: Operations

Net cash flow from operations decreased from $67.7 million during the nine months ended September 30, 2012 to $32.9 million during the 2013 period. The decrease in operating cash flow during 2013 as compared to 2012 was primarily attributable to the decrease in our accounts payable to vendors, advances from co-owners and revenue receivable offset by the reduction in accounts receivable from our joint partners.

Source of Capital: Debt

On August 19, 2010, we issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Existing Notes”) in a public offering. On July 3, 2013, we closed a private offering of $200 million aggregate principal amount of 10% Senior Notes due 2017. The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of their face value plus accrued interest from March 1, 2013.  The New Notes have terms that, subject to certain exceptions, are substantially identical to the Existing Notes. The net proceeds from the offering were used to finance the $188.2 million aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013.

At September 30, 2013, the estimated fair value of the Notes was $350.9 million, based upon a market quote provided by an independent broker. The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At September 30, 2013, $2.9 million had been accrued in connection with the March 1, 2014 interest payment and we were in compliance with all of the covenants contained in the Notes.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A. and IberiaBank. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3, 2016. As of September 30, 2013 we had $75 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. The borrowing base at September 30, 2013 was $200 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders at September 30, 2013 was $150 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions.

The next borrowing base redetermination is scheduled to occur by March 31, 2014. We or the lenders may request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 80% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

We are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX on a tiered rolling four quarter basis, of 3.5 to 1.0 and a minimum ratio of consolidated current assets to

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consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits us to repurchase up to $10 million of our common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase our Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of September 30, 2013, we were in compliance with all of the covenants contained in the Credit Agreement.

Source of Capital: Issuance of Securities

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

Source of Capital: Joint Ventures

In May 2010, we entered into a joint development agreement with WSGP Gas Producing, LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of our Woodford proved undeveloped reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program. We received approximately $57.4 million in cash at closing, net of $2.6 million in transaction fees, and an additional $14 million on November 30, 2011. In addition, since May 2010, WSGP has funded a share of our drilling costs under a drilling program. We achieved certain production performance metrics, as outlined in the joint development agreement, relative to the first 18 wells drilled under the drilling program. As a result, we received an additional $14 million during December 2011.

During February 2012, we amended the joint development agreement with WSGP to provide additional funding for a share of our drilling costs relative to our drilling programs in both our Woodford Shale and Mississippian Lime project areas. WSGP will continue to earn 50% of our undeveloped Woodford Shale acreage as they continue to fund a share of our drilling costs. As of September 30, 2013, approximately $53.2 million of drilling carry remained available.

Source of Capital: Divestitures

We do not budget 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 non-strategic 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 our Wyoming and South Texas assets. We cannot assure you that we will be able to sell any of our assets in the future.

On December 31, 2012, we sold our non-operated Arkansas assets for adjusted net proceeds of $8.5 million. In January 2013, we sold 50% of our saltwater disposal systems and related surface assets in the Woodford for net proceeds of approximately $10 million.

Use of Capital: Exploration and Development

Our 2013 capital budget, which includes capitalized interest and general and administrative costs and excludes acquisitions, is expected to range between $100 million and $110 million, of which $81.3 million was incurred during the first nine months of 2013. Because we operate the majority of our drilling activities, we expect to be able to control the timing of a substantial portion of our capital investments. During the nine months ended September 30, 2013, we funded our capital expenditures with cash flow from operations, cash on hand, proceeds from asset sales and borrowings under our bank credit facility. To the extent our capital expenditures during the remainder of 2013 exceed our cash flow and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of assets to fund a portion of our drilling budget.

Use of Capital: Acquisitions

On July 3, 2013, the Company closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $188.2 million, subject to customary adjustments to reflect an effective date of January 1, 2013. The Acquired Assets include 16 wells located on 7 platforms.

We believe the acquisition of the Acquired Assets represents both a strategic and transformative transaction for us. This transaction builds upon our existing strategy of utilizing free cash flow from our shorter life, Gulf Coast Basin assets to develop our longer life resource assets. We plan to utilize a portion of the free cash flow generated from these acquired properties to accelerate the development of our Woodford Shale and Cotton Valley resource plays.

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.

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

Disclosure Regarding Forward Looking Statements

This 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 our ability to integrate our recently completed acquisitions with our operations and realize the anticipated benefits from the acquisitions, any unexpected costs or delays in connection with the acquisitions, our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices and significantly depressed natural gas prices since the middle of 2008, the uncertain economic conditions in the United States and globally, the declines in the values of our properties that have resulted and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracing operations in shale plays or our operations in the Gulf of Mexico, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

When used in this 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” and elsewhere in this 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.

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 2013, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have an approximate $3.7 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three and nine months ended September 30, 2013, we received $0.2 million and paid $0.3 million, respectively, to the counterparties to our derivative instruments in connection with net hedge settlements.

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

Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing hedge contracts are lenders under the Credit Agreement. To the extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement would serve as counterparties.

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As of September 30, 2013, we had entered into the following oil and gas contracts:

Production Period	Instrument Type	Daily Volumes		Weighted Average Price
Natural Gas:
October - December 2013	Three-Way Collar	10,000 Mmbtu		$2.00-$3.00-$4.09
October - December 2013	Swap	30,000 Mmbtu		$3.78
October - December 2013	Collar	5,000 Mmbtu		$4.00 - $4.75
2014	Swap	20,000 Mmbtu		$4.04
Crude Oil:
October - December 2013	Swap	1,350 Bbls	(1)	$102.45
January - June 2014	Swap	200 Bbls	(3)	$101.30
2014	Swap	750 Bbls	(2)	$97.47
Natural Gas Liquids:
October - December 2013	Swap	150 Bbls		$92.42

(1) 500 Bbls per day tied to LLS index.

(2) 400 Bbls per day tied to LLS index.

(3) 200 Bbls per day tied to LLS index.

After executing the above transactions, the Company has approximately 4.1 Bcf of gas volumes at an average floor price of $3.63 per Mcf, approximately 124,000 barrels of oil volumes at an average price of $102.45 and approximately 14,000 Bbls of NGL volumes at $92.42 hedged for 2013. Additionally, the Company has approximately 7.3 Bcf of gas volumes at an average floor price of $4.04 per Mcf and approximately 310,000 barrels of oil volumes at an average price of $97.91 hedged for 2014.

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 18% of our total debt as of September 30, 2013. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of September 30, 2013, and assuming a 10% increase in interest rates and no change in the amount of debt outstanding, the potential effect on interest expense for the remainder of 2013 is less than $0.1 million.

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.

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Part II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 1A. RISK FACTORS

Oil and natural gas prices are volatile, and natural gas prices have been significantly depressed since the middle of 2008. 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. Prices for natural gas have been significantly depressed since the middle of 2008 and future oil and natural gas prices are subject to large fluctuations in response to a variety of factors beyond our control.

These factors include:

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

• the condition of the United States and worldwide economies;

• market uncertainty;

• the level of consumer product demand;

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

• the actions of the Organization of Petroleum Exporting Countries;

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

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

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

• the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs. 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 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.

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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.

The aggregate principal amount of our outstanding indebtedness net of cash on hand as of September 30, 2013 was $405.6 million. We would also have been able to incur $75 million of secured indebtedness under our senior secured bank credit facility, subject, however, to limitations on incurrence of indebtedness under the indenture governing our 10% senior notes due 2017, which we refer to as our 10% notes. In addition, we may also incur additional indebtedness in the future. Specifically, 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 the 10% notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the agreements governing such indebtedness;

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

• we will need to use a substantial portion of our cash flows to pay interest on our debt, $35 million per year for interest on our 10% notes alone, and to pay quarterly dividends, if declared by our Board of Directors, on our Series B Preferred Stock of approximately $5.1 million per year, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

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

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

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

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

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 10% notes, and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 10% notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

We are subject to risks in connection with acquisitions, including the Gulf of Mexico Acquisition, and the integration of significant acquisitions may be difficult and may divert senior management's attention.

We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of substantially all the assets we acquired in the Gulf of Mexico Acquisition as well as other producing properties that we acquire requires an assessment of several factors, including:

• recoverable reserves;

• future oil and natural gas prices and their appropriate differentials;

• development and operating costs;

• potential for future drilling and production;

• validity of the sellers' title to the properties, which may be less than expected at the time of signing

• the purchase agreement; and

• potential environmental issues, litigation and other liabilities.

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The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the sellers may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities or title defects in excess of the amounts claimed by us before closing and acquire properties on an ''as is'' basis. Indemnification from the sellers will generally be effective only during a limited period of time, e.g., a 12-month period, after the closing and subject to certain dollar limitations and minimums. We may not be able to collect on such indemnification because of disputes with the sellers or their inability to pay. As a result, there is a risk that we could ultimately be liable for unknown obligations related to the Gulf of Mexico Acquisitions, or other past or future acquisitions, which could materially adversely affect our financial condition, results of operations or cash flows.

Significant acquisitions and other strategic transactions may involve other risks, including:

• diversion of our management's attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions;

• the challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with those of our operations while carrying on our ongoing business;

• difficulty associated with coordinating geographically separate organizations;

• an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and

• the challenge of attracting and retaining personnel associated with acquired operations.

The process of integrating assets, including the assets acquired in the Gulf of Mexico Acquisition, could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or if any significant business activities are interrupted as a result of the integration process, our business could suffer.

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

NONE

Item 3. DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4. MINE SAFETY DISCLOSURES

NONE.

Item 5. OTHER INFORMATION

NONE.

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Item 6. EXHIBITS

Exhibit 4.1, Second Supplemental Indenture, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K filed with the SEC on July 3, 2013).

Exhibit 4.2, Registration Rights Agreement, dated July 3, 2013, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and J.P. Morgan Securities LLC, as representative of the several initial purchasers named therein) (incorporated herein by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed with the SEC on July 3, 2013).

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

* Filed herewith.

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SIGNATURE

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

		PETROQUEST ENERGY, INC.
Date:	November 6, 2013	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief (Authorized Officer and Principal Financial Officer)

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EX-31.1

EXHIBIT 31.1

I, Charles T. Goodson, certify that:

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

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

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

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

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

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

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

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

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

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

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

/s/ Charles T. Goodson                            

Charles T. Goodson

Chief Executive Officer

November 6, 2013

EX-31.2

EXHIBIT 31.2

I, J. Bond Clement, certify that:

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

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

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

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

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

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

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

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

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

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

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

/s/ J. Bond Clement                        

J. Bond Clement

Chief Financial Officer

November 6, 2013

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending September 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Charles T. Goodson

Charles T. Goodson

Chief Executive Officer

November 6, 2013

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending September 30, 2013 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

November 6, 2013

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

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Derivative Instruments

9 Months Ended

Sep. 30, 2013

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, natural gas or natural gas liquids (Ngl) 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). At September 30, 2013, the Company designated all but three of its derivative instruments as effective cash flow hedges. The Company does not have master netting arrangements with any of its counterparties. Accordingly, derivative assets and liabilities are recorded on a gross basis in the consolidated balance sheet.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $767,000 and $1,482,000, Ngl hedges of $5,000 and $312,000 and oil hedges of ($538,000) and $491,000 for the three months endedSeptember 30, 2013 and 2012, respectively. For the nine month periods ended September 30, 2013 and 2012, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $422,000 and $6,867,000, Ngl hedges of $5,000 and $544,000 and oil hedges of ($684,000) and $853,000, respectively.

As of September 30, 2013, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes		Weighted Average Price
Natural Gas:
October - December 2013	Three-Way Collar	10,000 Mmbtu		$2.00-$3.00-$4.09
October - December 2013	Swap	30,000 Mmbtu		$3.78
October - December 2013	Collar	5,000 Mmbtu		$4.00 - $4.75
2014	Swap	20,000 Mmbtu		$4.04
Crude Oil:
October - December 2013	Swap	1,350 Bbls	(1)	$102.45
January - June 2014	Swap	200 Bbls	(3)	$101.30
2014	Swap	750 Bbls	(2)	$97.47
Natural Gas Liquids:
October - December 2013	Swap	150 Bbls		$92.42

(1) 500 Bbls per day tied to LLS index.

(2) 400 Bbls per day tied to LLS index.

(3) 200 Bbls per day tied to LLS index.

At September 30, 2013, the Company had accumulated other comprehensive income of approximately $1.3 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of September 30, 2013, the Company would realize a $1.1 milliongain, net of taxes, during the next 12 months. This gain is expected to be reclassified based on the schedule of volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	2,274
September 30, 2013	Derivative asset (long-term)	$	305
September 30, 2013	Derivative liability (short-term)	$	(445	)
December 31, 2012	Derivative asset (short-term)	$	830

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Loss Recognized in Other Comprehensive Income			Location of Gain Reclassified into Income	Amount of Gain Reclassified into Income
Commodity Derivatives at September 30, 2013	$	(78	)	Oil and gas sales	$	436
Commodity Derivatives at September 30, 2012	$	(2,423	)	Oil and gas sales	$	2,285

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012 :

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2013	$	819		Oil and gas sales	$	(18	)
Commodity Derivatives at September 30, 2012	$	(3,431	)	Oil and gas sales	$	8,264

Derivatives not designated as hedging instruments:

The following tables reflect the fair value of the Company’s non-designated derivative instruments in the consolidated financial statements (in thousands):

Effect of Non-designated Derivative Instruments on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	49
September 30, 2013	Derivative liability (short-term)	$	(80	)
December 31, 2012	Derivative liability (short-term)	$	(233	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	45
Commodity Derivatives at September 30, 2012	$	(340	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	202
Commodity Derivatives at September 30, 2012	$	(715	)

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Consolidated Statements of Operations (Unaudited) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Revenues:
Oil and gas sales	$ 55,578	$ 33,913	$ 129,630	$ 103,286
Gas gathering revenue	9	38	68	119
Total revenues	55,587	33,951	129,698	103,405
Expenses:
Lease operating expenses	12,652	9,658	31,208	28,408
Production taxes	1,248	880	3,757	112
Depreciation, depletion and amortization	22,475	15,032	49,882	46,024
Ceiling test writedown	0	35,391	0	108,987
General and administrative	9,132	5,963	20,199	17,541
Accretion of asset retirement obligation	543	525	1,203	1,542
Interest expense	8,071	2,338	14,051	7,021
Total expenses	54,121	69,787	120,300	209,635
Other income (expense):
Other income	176	257	432	529
Derivative income (expense)	45	(340)	202	(715)
Other operating income (expense), net	221	(83)	634	(186)
Income (loss) from operations	1,687	(35,919)	10,032	(106,416)
Income tax expense (benefit)	17	1,435	(474)	1,496
Net income (loss)	1,670	(37,354)	10,506	(107,912)
Preferred stock dividend	1,287	1,285	3,854	3,855
Net income (loss) available to common stockholders	$ 383	$ (38,639)	$ 6,652	$ (111,767)
Basic
Net income (loss) per share (in usd per share)	$ 0.01	$ (0.62)	$ 0.10	$ (1.79)
Diluted
Net income (loss) per share (in usd per share)	$ 0.01	$ (0.62)	$ 0.10	$ (1.79)
Weighted average number of common shares:
Basic (shares)	63,096	62,492	62,936	62,356
Diluted (shares)	63,242	62,492	63,105	62,356

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Acquisition

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Acquisition

Acquisition

On July 3, 2013, the Company acquired certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $188.2 million, subject to customary adjustments to reflect an effective date of January 1, 2013 (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets included 16 wells located on seven platforms.

The aggregate cash purchase price of the Gulf of Mexico Acquisition was financed with the net proceeds from the sale in a private offering under Rule 144A and Regulation S of the Securities Act of 1933, as amended (the "Securities Act"), of $200 million aggregate principal amount of the Company's 10% Senior Notes due 2017.  The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes"). The New Notes have terms that, subject to certain exceptions, are substantially identical to the Company's existing $150 million aggregate principal amount of 10% Senior Notes due 2017. The Company recorded $0.9 million of deferred financing costs related to the New Notes in the second and third quarters of 2013 and an additional $4.0 million of deferred financing costs related to the underwriting fee paid to the initial purchasers of the New Notes on the closing date of July 3, 2013. The Company also incurred $3.9 million of acquisition-related costs, including $2.6 million related to a bridge commitment fee, which were recognized as general and administrative expenses.

The Gulf of Mexico Acquisition is accounted for under the purchase method of accounting, which involves determining the fair value of the assets acquired and liabilities assumed. The following purchase price allocation is preliminary and based on management's best estimates of the fair value of the assets acquired and liabilities assumed as of the date of this Form 10-Q. The preliminary purchase price allocation is subject to change based on numerous factors, including the final adjusted purchase price and the final estimated fair value of the assets acquired and liabilities assumed. Any such adjustments to the preliminary estimates of fair value could be material.

The fair value of proved and unevaluated oil and gas properties was estimated using the income approach based on estimated reserve quantities, costs to produce and develop reserves, and forward prices for oil and gas, which represent Level 2 and Level 3 inputs. Asset retirement obligations were determined in accordance with applicable accounting standards.

The following table summarizes the estimated acquisition date fair values of the net assets acquired (in thousands):

Oil and gas properties	$	191,466
Unevaluated oil and gas properties	12,033
Asset retirement obligations	(15,319		)
Net assets to be acquired	$	188,180

The following unaudited summary pro forma statement of operations for the three and nine month periods ended September 30, 2013 and 2012 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts in millions, except per share amounts.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Revenues	$	55,587	$	46,384		$	162,494	$	132,303
Income (Loss) from Operations	4,318		(38,178		)	15,487		(121,955		)
Net Income (Loss) available to common stockholders	3,014		(40,898		)	12,107		(127,306		)
Basic Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)
Diluted Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of share-based compensation

A detail of share-based compensation expense for the three and nine month periods ended September 30, 2013 and 2012 is as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	86	$	211	$	175	$	646
Non-Qualified Stock Options	41		181		176		509
Restricted stock	1,182		1,379		2,754		4,454
Restricted stock units	604		—		1,147		—
Share based compensation	$	1,913	$	1,771	$	4,252	$	5,609

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Fair Value Measurements

9 Months Ended

Sep. 30, 2013

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 September 30, 2013 were in the form of a three-way collar, a zero cost collar and swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of September 30, 2013 and December 31, 2012 (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:
At September 30, 2013	$	—	$	2,103	$	—
At December 31, 2012	$	—	$	597	$	—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at September 30, 2013 and December 31, 2012. The estimated fair value of the Notes was $350.9 million and $155.3 million as of September 30, 2013 and December 31, 2012, respectively, as compared to the book value of $350 million and $150 million as of September 30, 2013 and December 31, 2012, respectively. The estimated fair value of the Notes was provided by independent brokers using the actual period end quotes for the Notes, which represent Level 2 inputs.

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Derivative Instruments (Details) (USD $)	9 Months Ended
	Sep. 30, 2013 MMBTU
Three-Way Collar | October - December 2013 | Natural Gas
Oil and gas contracts
Daily Volumes	10,000
Weighted Average Price	$ 3.00
Three-Way Collar | Minimum [Member] | October - December 2013 | Natural Gas
Oil and gas contracts
Weighted Average Price	$ 2.00
Three-Way Collar | Maximum [Member] | October - December 2013 | Natural Gas
Oil and gas contracts
Weighted Average Price	$ 4.09
Collar | October - December 2013 | Natural Gas
Oil and gas contracts
Daily Volumes	5,000
Collar | Minimum [Member] | October - December 2013 | Natural Gas
Oil and gas contracts
Weighted Average Price	$ 4.00
Collar | Maximum [Member] | October - December 2013 | Natural Gas
Oil and gas contracts
Weighted Average Price	$ 4.75
Swap | October - December 2013 | Natural Gas
Oil and gas contracts
Daily Volumes	30,000
Weighted Average Price	$ 3.78
Swap | October - December 2013 | Crude Oil
Oil and gas contracts
Daily Volumes	1,350
Weighted Average Price	$ 102.45	[1]
Swap | October - December 2013 | Natural Gas Liquids
Oil and gas contracts
Daily Volumes	150
Weighted Average Price	$ 92.42
Swap | January - June 2014 | Crude Oil
Oil and gas contracts
Daily Volumes	200
Weighted Average Price	$ 101.30	[1]
Swap | 2014 | Natural Gas
Oil and gas contracts
Daily Volumes	20,000
Weighted Average Price	$ 4.04
Swap | 2014 | Crude Oil
Oil and gas contracts
Daily Volumes	750
Weighted Average Price	$ 97.47	[1]
LLS Index | Swap | October - December 2013 | Crude Oil
Oil and gas contracts
Daily Volumes	500
LLS Index | Swap | January - June 2014 | Crude Oil
Oil and gas contracts
Daily Volumes	200
LLS Index | Swap | 2014 | Crude Oil
Oil and gas contracts
Daily Volumes	400

[1] Bbls per day tied to LLS index.

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Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2013	$	1,418
Other comprehensive income before reclassifications	196
Amounts reclassified from accumulated other comprehensive income	(274		)
Net other comprehensive loss	(78		)
Balance as of September 30, 2013	$	1,340

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2012	$	521
Other comprehensive income before reclassifications	808
Amounts reclassified from accumulated other comprehensive income	11
Net other comprehensive income	819
Balance as of September 30, 2013	$	1,340

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

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

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of September 30, 2013 and December 31, 2012 (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:
At September 30, 2013	$	—	$	2,103	$	—
At December 31, 2012	$	—	$	597	$	—

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Other Comprehensive Income (Details) (USD $) In Thousands, unless otherwise specified			3 Months Ended	9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Gains and Losses on Cash Flow Hedges	Sep. 30, 2013 Gains and Losses on Cash Flow Hedges
Accumulated other Comprehensive Income [Roll Forward]
Balance at beginning of period	$ 1,340	$ 521	$ 1,418	$ 521
Other comprehensive income before reclassifications			196	808
Amounts reclassified from accumulated other comprehensive income			(274)	11
Net other comprehensive income			(78)	819
Balance as of September 30, 2013	$ 1,340	$ 521	$ 1,340	$ 1,340

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Long-Term Debt (Details) (USD $)	9 Months Ended			0 Months Ended	9 Months Ended
	Sep. 30, 2013 determination	Jul. 03, 2013	Jul. 02, 2013	Jul. 03, 2013 Gulf of Mexico Acquisition [Member]	Sep. 30, 2013 Maximum [Member]	Sep. 30, 2013 Minimum [Member]	Sep. 30, 2013 Alternate Base Rate [Member] Maximum [Member]	Sep. 30, 2013 Alternate Base Rate [Member] Minimum [Member]	Sep. 30, 2013 Federal Funds Effective Rate [Member]	Sep. 30, 2013 Adjusted LIBO rate [Member] Maximum [Member]	Sep. 30, 2013 Adjusted LIBO rate [Member] Minimum [Member]	Sep. 30, 2013 Letters of credit [Member]	Sep. 30, 2013 10% Senior Notes [Member] Senior Notes [Member]	Jul. 03, 2013 10% Senior Notes [Member] Senior Notes [Member]	Dec. 31, 2012 10% Senior Notes [Member] Senior Notes [Member]	Aug. 19, 2010 10% Senior Notes [Member] Senior Notes [Member]
Long-Term Debt (Textual) [Abstract]
Principal amount														$ 200,000,000		$ 150,000,000
Interest rate of Senior Notes													10.00%		10.00%	10.00%
Price at which notes were issued (as a percent)														100.00%
Purchase price				188,200,000
Adjusted LIBO rate is equal to the rate at which dollar deposits	2,900,000
Revolving credit facility	300,000,000											25,000,000
Borrowings outstanding under the Credit Agreement	75,000,000
Current borrowing base		200,000,000	150,000,000
Aggregate commitments of the lenders	150,000,000
Number of additional borrowing base re-determinations each year that may be requested	2
Percent of amount outstanding held by lenders needed to approve borrowing base to remain the same or be reduced						66.67%
Agreement bear interest at the alternate base rate	Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%.
At least secured percentage value of oil and gas properties	80.00%
Adjusted LIBO rate	1.00%						1.50%	0.50%	0.50%	2.50%	1.50%
Accrued in connection with the interest payment	5,000,000
Commitment fees on a sliding scale					0.50%	0.375%
Maximum ratio of total debt to EBITDAX					3.5	1.0
Repurchase Company's common stock					$ 10,000,000
Borrower's Liquidity						20.00%

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Derivative Instruments (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Recognized in Other Comprehensive Income	$ (78)	$ (2,423)	$ 819	$ (3,431)
Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Recognized in Other Comprehensive Income	(78)	(2,423)	819	(3,431)
Oil and gas sales | Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain Reclassified into Income	$ 436	$ 2,285	$ (18)	$ 8,264

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Convertible Preferred Stock (Details) (USD $)	9 Months Ended
	Sep. 30, 2013 Rate	Dec. 31, 2012
Equity [Abstract]
Preferred stock, shares outstanding	1,495,000	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate	6.875%
Terms of applicable conversion terms	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. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.
Number of trading days	20 days
Number of consecutive trading days	30 days
Closing price as percentage of conversion price	130.00%
Series B Preferred Stock converted into common stock (in shares)	3.4433
Initial conversion price of common stock (in usd per share)	$ 14.52
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.
Conversion rate numerator for Preferred Stock	$ 50

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Derivative Instruments (Details Textual) (USD $)	3 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Gas hedges [Member]	Sep. 30, 2012 Gas hedges [Member]	Sep. 30, 2013 Gas hedges [Member]	Sep. 30, 2012 Gas hedges [Member]	Sep. 30, 2013 Natural Gas Liquids Hedges [Member]	Sep. 30, 2012 Natural Gas Liquids Hedges [Member]	Sep. 30, 2013 Natural Gas Liquids Hedges [Member]	Sep. 30, 2012 Natural Gas Liquids Hedges [Member]	Sep. 30, 2013 Crude Oil	Sep. 30, 2012 Crude Oil	Sep. 30, 2013 Crude Oil	Sep. 30, 2012 Crude Oil
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts			$ 767,000	$ 1,482,000	$ 422,000	$ 6,867,000	$ 5,000	$ 312,000	$ 5,000	$ 544,000	$ (538,000)	$ 491,000	$ (684,000)	$ 853,000
Accumulated other comprehensive income	1,340,000	521,000
Realization of gain, net of taxes	$ 1,100,000

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Oil and gas contracts

As of September 30, 2013, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes		Weighted Average Price
Natural Gas:
October - December 2013	Three-Way Collar	10,000 Mmbtu		$2.00-$3.00-$4.09
October - December 2013	Swap	30,000 Mmbtu		$3.78
October - December 2013	Collar	5,000 Mmbtu		$4.00 - $4.75
2014	Swap	20,000 Mmbtu		$4.04
Crude Oil:
October - December 2013	Swap	1,350 Bbls	(1)	$102.45
January - June 2014	Swap	200 Bbls	(3)	$101.30
2014	Swap	750 Bbls	(2)	$97.47
Natural Gas Liquids:
October - December 2013	Swap	150 Bbls		$92.42

Effect of Cash Flow Hedges on the Consolidated Balance Sheet

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	2,274
September 30, 2013	Derivative asset (long-term)	$	305
September 30, 2013	Derivative liability (short-term)	$	(445	)
December 31, 2012	Derivative asset (short-term)	$	830

Effect of Cash Flow Hedges on the Consolidated Statement of Operations

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Loss Recognized in Other Comprehensive Income			Location of Gain Reclassified into Income	Amount of Gain Reclassified into Income
Commodity Derivatives at September 30, 2013	$	(78	)	Oil and gas sales	$	436
Commodity Derivatives at September 30, 2012	$	(2,423	)	Oil and gas sales	$	2,285

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012 :

Instrument	Amount of Gain (Loss) Recognized in Other Comprehensive Income			Location of Gain (Loss) Reclassified into Income	Amount of Gain (Loss) Reclassified into Income
Commodity Derivatives at September 30, 2013	$	819		Oil and gas sales	$	(18	)
Commodity Derivatives at September 30, 2012	$	(3,431	)	Oil and gas sales	$	8,264

Effect of Non-designated Derivative Instruments

Effect of Non-designated Derivative Instruments on the Consolidated Balance Sheet at September 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2013	Derivative asset (short-term)	$	49
September 30, 2013	Derivative liability (short-term)	$	(80	)
December 31, 2012	Derivative liability (short-term)	$	(233	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the three months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	45
Commodity Derivatives at September 30, 2012	$	(340	)

Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations for the nine months ended September 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at September 30, 2013	$	202
Commodity Derivatives at September 30, 2012	$	(715	)

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Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Net of income taxes	$ (46)	$ 1,435	$ 485	$ 2,032

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Consolidated Statements of Cash Flows (Parenthetical) (Senior Notes [Member], 10% Senior Notes [Member])	Sep. 30, 2013	Dec. 31, 2012	Aug. 19, 2010
Senior Notes [Member] | 10% Senior Notes [Member]
Debt Instrument [Line Items]
Interest rate of Senior Notes	10.00%	10.00%	10.00%

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Convertible Preferred Stock

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Convertible Preferred Stock

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.

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

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

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

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Basis of Presentation

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial information for the three and nine month periods ended September 30, 2013 and 2012, 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 September 30, 2013 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, 2012 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, 2012. Certain prior year amounts have been reclassified to conform to current year presentations.

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

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Derivative Instruments (Details 3) (Not Designated as Hedging Instrument [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Not Designated as Hedging Instrument [Member]
Effect of Non-designated Derivative Instruments on the Consolidated Balance Sheet
Commodity derivatives, assets fair value	$ 49
Commodity derivatives, liabilities fair value	$ (80)	$ (233)

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Acquisition (Details) (USD $)	9 Months Ended		0 Months Ended	3 Months Ended		0 Months Ended	6 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Jul. 03, 2013 10% Senior Notes [Member]	Sep. 30, 2013 10% Senior Notes [Member]	Aug. 19, 2010 10% Senior Notes [Member]	Jul. 03, 2013 Gulf of Mexico Acquisition [Member] well platform	Sep. 30, 2013 Gulf of Mexico Acquisition [Member] General and Administrative Expense [Member]	Sep. 30, 2013 Gulf of Mexico Acquisition [Member] General and Administrative Expense [Member] Bridge Loan [Member]
Business Acquisition [Line Items]
Purchase price						$ 188,200,000
Number of wells acquired						16
Number of platforms purchased						7
Principal amount			200,000,000		150,000,000
Interest rate of Senior Notes			10.00%
Payments of financing costs	487,000	33,000	4,000,000	900,000
Acquisition-related costs							3,900,000
Expected acquisition-related costs								$ 2,600,000

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Earnings Per Share (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
A reconciliation between basic and diluted earnings per share computations
Net income (loss) available to common stockholders	$ 383	$ (38,639)	$ 6,652	$ (111,767)
Attributable to participating securities	(8)		(151)
Net income or loss available to common stockholders, Loss (excluding income attributable to participating securities)	375		6,501
Net loss available to common stockholders (in shares)	63,096	62,492	62,936	62,356
Stock options, Effect of dilutive securities
Net loss available to common stockholders, Per Share Amount (in dollars per share)	$ 0.01	$ (0.62)	$ 0.10	$ (1.79)
Stock options, effect of dilutive securities, (in shares)	146		169
Dilutive Securities, Effect on Basic Earnings Per Share, Restricted Stock	(8)		(151)	0
Restricted stock, effect of dilutive securities (in shares)	0	0	0	0
DILUTED EPS, Loss	$ 375	$ (38,639)	$ 6,501	$ (111,767)
DILUTED EPS, Shares	63,242	62,492	63,105	62,356
DILUTED EPS, Per Share Amount (in dollars per share)	$ 0.01	$ (0.62)	$ 0.10	$ (1.79)

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Ceiling Test (Details) (USD $)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Ceiling Test (Textual) [Abstract]
Increase (Decrease) in ceiling test write-downs	$ 0	$ 35,391,000	$ 0	$ 108,987,000
Cash Flow Hedge, Decrease in Impairment of Gas and Oil Properties		$ (2,100,000)
Ceiling Test (Additional Textual) [Abstract]
Rate for discounting future cash flows			10.00%
Mcf of natural gas [Member]
Ceiling Test (Textual) [Abstract]
Average sales prices			2.22
Barrel of oil [Member]
Ceiling Test (Textual) [Abstract]
Average sales prices			104.83
Mcfe of Ngl [Member]
Ceiling Test (Textual) [Abstract]
Average sales prices			7.44

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 47.2

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Accumulated depreciation and amortization	$ 5,166	$ 4,240
Preferred stock, par value	$ 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	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	63,353,000	62,768,000
Common stock, shares outstanding	63,353,000	62,768,000
Senior Notes [Member] | 10% Senior Notes [Member]
Debt Instrument [Line Items]
Interest rate of Senior Notes	10.00%	10.00%

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Asset Retirement Obligation

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligation

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

	Nine Months Ended September 30,
	2013			2012
Asset retirement obligation, beginning of period	$	27,260		$	30,427
Liabilities incurred	498			867
Liabilities assumed	15,319			—
Liabilities settled	(2,415		)	(2,519		)
Accretion expense	1,203			1,542
Revisions in estimated cash flows	987			(42		)
Asset retirement obligation, end of period	42,852			30,275
Less: current portion of asset retirement obligation	(1,502		)	(1,034		)
Long-term asset retirement obligation	$	41,350		$	29,241

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Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]
Net income (loss)	$ 1,670	$ (37,354)	$ 10,506	$ (107,912)
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of $(46), $1,435, $485 and $2,032, respectively.	(78)	(2,423)	819	(3,431)
Comprehensive income (loss)	$ 1,592	$ (39,777)	$ 11,325	$ (111,343)

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 19,409	$ 14,904
Revenue receivable	31,561	17,742
Joint interest billing receivable	27,212	42,595
Other receivable	0	9,208
Derivative asset	2,323	830
Prepaid drilling costs	963	1,698
Other current assets	7,411	2,607
Total current assets	88,879	89,584
Oil and gas properties:
Oil and gas properties, full cost method	2,003,907	1,734,477
Unevaluated oil and gas properties	87,117	71,713
Accumulated depreciation, depletion and amortization	(1,530,928)	(1,472,244)
Oil and gas properties, net	560,096	333,946
Other property and equipment	13,340	12,370
Accumulated depreciation of other property and equipment	(8,512)	(7,607)
Total property and equipment	564,924	338,709
Derivative asset	305	0
Other assets, net of accumulated depreciation and amortization of $5,166 and $4,240, respectively	9,783	5,110
Total assets	663,891	433,403
Current liabilities:
Accounts payable to vendors	31,353	58,960
Advances from co-owners	7,144	20,459
Oil and gas revenue payable	45,438	26,175
Accrued interest and preferred stock dividend	4,175	6,190
Asset retirement obligation	1,502	2,351
Derivative liability	525	233
Other accrued liabilities	9,616	6,535
Total current liabilities	99,753	120,903
Bank debt	75,000	50,000
10% Senior Notes	350,000	150,000
Asset retirement obligation	41,350	24,909
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 63,353 and 62,768 shares, respectively	63	63
Paid-in capital	279,260	276,534
Accumulated other comprehensive income	1,340	521
Accumulated deficit	(182,876)	(189,528)
Total stockholders’ equity	97,788	87,591
Total liabilities and stockholders’ equity	$ 663,891	$ 433,403

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Acquisition (Schedule of Assets Acquired and Liabilities Assumed) (Details) (Gulf of Mexico Acquisition [Member], USD $) In Thousands, unless otherwise specified	Jul. 03, 2013
Gulf of Mexico Acquisition [Member]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Oil and gas properties	$ 191,466
Unevaluated oil and gas properties	12,033
Asset retirement obligations	(15,319)
Net assets to be acquired	$ 188,180

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Asset Retirement Obligation (Tables)

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation Disclosure [Abstract]

Changes to the Company's asset retirement obligation liability

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

	Nine Months Ended September 30,
	2013			2012
Asset retirement obligation, beginning of period	$	27,260		$	30,427
Liabilities incurred	498			867
Liabilities assumed	15,319			—
Liabilities settled	(2,415		)	(2,519		)
Accretion expense	1,203			1,542
Revisions in estimated cash flows	987			(42		)
Asset retirement obligation, end of period	42,852			30,275
Less: current portion of asset retirement obligation	(1,502		)	(1,034		)
Long-term asset retirement obligation	$	41,350		$	29,241

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Fair Value Measurements (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Estimated fair value of the Notes	$ 350,900,000	$ 155,300,000
Book value of notes	350,000,000	150,000,000
Quoted Prices in Active Markets (Level 1)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	0	0
Significant Other Observable Inputs (Level 2)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	2,103,000	597,000
Significant Unobservable Inputs (Level 3)
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Commodity derivatives	$ 0	$ 0

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Derivative Instruments (Details 1) (Designated as Hedging Instrument [Member], USD $) In Thousands, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Designated as Hedging Instrument [Member]
Derivatives, Fair Value [Line Items]
Derivative asset (short-term)	$ 2,274	$ 830
Derivative asset (long-term)	305
Derivative liability (short-term)	$ (445)

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Asset Retirement Obligation (Details) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 27,260	$ 30,427
Liabilities incurred	498	867
Liabilities assumed	15,319	0
Liabilities settled	(2,415)	(2,519)
Accretion expense	1,203	1,542
Revisions in estimated cash flows	987	(42)
Asset retirement obligation, end of period	42,852	30,275
Less: current portion of asset retirement obligation	(1,502)	(1,034)	(2,351)
Long-term asset retirement obligation	$ 41,350	$ 29,241	$ 24,909

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Share-Based Compensation (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Summary of share-based compensation
Share based compensation	$ 1,913	$ 1,771	$ 4,252	$ 5,609
Incentive Stock Options
Summary of share-based compensation
Share based compensation	86	211	175	646
Non-Qualified Stock Options
Summary of share-based compensation
Share based compensation	41	181	176	509
Restricted stock
Summary of share-based compensation
Share based compensation	1,182	1,379	2,754	4,454
Restricted stock units
Summary of share-based compensation
Share based compensation	$ 604	$ 0	$ 1,147	$ 0

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Long-Term Debt

9 Months Ended

Sep. 30, 2013

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of 10% Senior Notes due 2017 (the “ Existing Notes”) in a public offering. On July 3, 2013, the Company closed a private offering of $200 million aggregate principal amount of 10% Senior Notes due 2017. The Company subsequently registered the 10% Senior Notes due 2017 in an exchange offer completed in September 2013 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of their face value plus accrued interest from March 1, 2013.  The New Notes have terms that, subject to certain exceptions, are substantially identical to the Existing Notes. The net proceeds from the offering were used to finance the $188.2 million aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013.

The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At September 30, 2013, $2.9 million had been accrued in connection with the March 1, 2014 interest payment and the Company was in compliance with all of the covenants contained in the Notes.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A. and IberiaBank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 3, 2016. As of September 30, 2013 the Company had $75.0 million of borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. On July 3, 2013 the borrowing base was increased from $150 million to $200 million (subject to the aggregate commitments of the lenders then in effect). As of September 30, 2013, the aggregate commitments of the lenders was $150 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2014. The Company or the lenders may request two additional borrowing base re-determinations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 80% of the aggregate total value of the Company’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a tiered rolling four quarter basis, of 3.5 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of September 30, 2013, the Company was in compliance with all of the covenants contained in the Credit Agreement.

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Acquisition (Pro Forma) (Details) (Gulf of Mexico Acquisition [Member], USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Gulf of Mexico Acquisition [Member]
Business Acquisition [Line Items]
Revenues	$ 55,587	$ 46,384	$ 162,494	$ 132,303
Income (Loss) from Operations	4,318	(38,178)	15,487	(121,955)
Net Income (Loss) available to common stockholders	$ 3,014	$ (40,898)	$ 12,107	$ (127,306)
Basic Earnings per Share	$ 0.05	$ (0.65)	$ 0.19	$ (2.04)
Diluted Earnings per Share	$ 0.05	$ (0.65)	$ 0.19	$ (2.04)

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Derivative Instruments (Details 4) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Effect of Non-designated Derivative Instruments on the Consolidated Statement of Operations
Amount of Unrealized Loss Recognized in Other Income Expense	$ 45	$ (340)	$ 202	$ (715)

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Ceiling Test

9 Months Ended

Sep. 30, 2013

Ceiling Test [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 unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to ceiling test write-down of oil and gas properties in the quarter in which the excess occurs.

At September 30, 2012, 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 $2.22 per Mcf of natural gas, $104.83 per barrel of oil and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of the Company’s longer-lived estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of $35.4 million and $109.0 million during the three and nine months ended September 30, 2012, respectively. The Company’s cash flow hedges in place at September 30, 2012decreased the ceiling test write-down by approximately $2.1 million. The Company recognized no such ceiling test write-down during the three and nine months ended September 30, 2013.

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Earnings Per Share

9 Months Ended

Sep. 30, 2013

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 follows:

For the Three Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	383		63,096
Attributable to participating securities	(8		)
BASIC EPS	$	375		63,096	$	0.01
Net income available to common stockholders	383			63,096
Effect of dilutive securities:
Stock options	—			146
Attributable to participating securities	(8		)	—
DILUTED EPS	$	375		63,242	$	0.01
For the Nine Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	6,652		62,936
Attributable to participating securities	(151		)
BASIC EPS	$	6,501		62,936	$	0.10
Net income available to common stockholders	$	6,652		62,936
Effect of dilutive securities:
Stock options				169
Attributable to participating securities	(151		)	—
DILUTED EPS	$	6,501		63,105	$	0.10
For the Three Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(38,639	)	62,492	$	(0.62	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(38,639	)	62,492	$	(0.62	)
For the Nine Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(111,767	)	62,356	$	(1.79	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(111,767	)	62,356	$	(1.79	)

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2013 because the inclusion would have been anti-dilutive. Options to purchase 1,199,000 and 1,245,000 shares of common stock were outstanding during the three and nine month periods ended September 30, 2013, respectively, and were not included in the computation of diluted earnings per share because the options' exercise prices were in excess of the average market price of the common shares.

An aggregate of 1,104,000 and 943,000 shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 30, 2012, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the respective periods.

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Cash flows from operating activities:
Net income (loss)	$ 10,506	$ (107,912)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	(474)	1,496
Depreciation, depletion and amortization	49,882	46,024
Ceiling test writedown	0	108,987
Accretion of asset retirement obligation	1,203	1,542
Share based compensation expense	3,105	5,609
Amortization costs and other	1,138	594
Non-cash derivative (income) expense	(202)	715
Payments to settle asset retirement obligations	(2,415)	(2,519)
Changes in working capital accounts:
Revenue receivable	(13,819)	141
Prepaid drilling and pipe costs	735	2,891
Joint interest billing receivable	13,612	20,312
Accounts payable and accrued liabilities	(11,781)	1,464
Advances from co-owners	(13,315)	(8,802)
Other	(5,266)	(2,866)
Net cash provided by operating activities	32,909	67,676
Cash flows used in investing activities:
Investment in oil and gas properties	(261,707)	(121,428)
Investment in other property and equipment	(970)	0
Sale of oil and gas properties	18,915	837
Sale of unevaluated oil and gas properties	0	6,083
Net cash used in investing activities	(243,762)	(114,508)
Cash flows provided by financing activities:
Net payments for share based compensation plans	(379)	(840)
Deferred financing costs	(487)	(33)
Payment of preferred stock dividend	(3,854)	(3,855)
Proceeds from issuance of 10% Senior Notes	200,000	0
Proceeds from bank borrowings	62,000	72,500
Repayment of bank borrowings	(37,000)	(37,500)
Net cash provided by financing activities	215,358	30,272
Net increase (decrease) in cash and cash equivalents	4,505	(16,560)
Cash and cash equivalents, beginning of period	14,904	22,263
Cash and cash equivalents, end of period	19,409	5,703
Cash paid during the period for:
Interest	19,479	15,628
Income taxes	11	15
Senior Notes [Member] | 10% Senior Notes [Member]
Cash flows provided by financing activities:
Deferred financing costs	$ 4,922	$ 0

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Earnings Per Share (Details Textual)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Convertible preferred stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5,148,000	5,148,000	5,148,000	5,148,000
Stock Options [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1,199,000		1,245,000
Series B Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		1,104,000		943,000

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Income Taxes

9 Months Ended

Sep. 30, 2013

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 expense and state income taxes. As a result of the 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 $47.2 million as of September 30, 2013.

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Share-Based Compensation

9 Months Ended

Sep. 30, 2013

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

Share-based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share-based compensation expense for the three and nine month periods ended September 30, 2013 and 2012 is as follows (in thousands):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	86	$	211	$	175	$	646
Non-Qualified Stock Options	41		181		176		509
Restricted stock	1,182		1,379		2,754		4,454
Restricted stock units	604		—		1,147		—
Share based compensation	$	1,913	$	1,771	$	4,252	$	5,609

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Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2013

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 follows:

For the Three Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	383		63,096
Attributable to participating securities	(8		)
BASIC EPS	$	375		63,096	$	0.01
Net income available to common stockholders	383			63,096
Effect of dilutive securities:
Stock options	—			146
Attributable to participating securities	(8		)	—
DILUTED EPS	$	375		63,242	$	0.01
For the Nine Months Ended September 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	6,652		62,936
Attributable to participating securities	(151		)
BASIC EPS	$	6,501		62,936	$	0.10
Net income available to common stockholders	$	6,652		62,936
Effect of dilutive securities:
Stock options				169
Attributable to participating securities	(151		)	—
DILUTED EPS	$	6,501		63,105	$	0.10
For the Three Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(38,639	)	62,492	$	(0.62	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(38,639	)	62,492	$	(0.62	)
For the Nine Months Ended September 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(111,767	)	62,356	$	(1.79	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(111,767	)	62,356	$	(1.79	)

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Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Equity [Abstract]

Other Comprehensive Income

Other Comprehensive Income

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of June 30, 2013	$	1,418
Other comprehensive income before reclassifications	196
Amounts reclassified from accumulated other comprehensive income	(274		)
Net other comprehensive loss	(78		)
Balance as of September 30, 2013	$	1,340

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2012	$	521
Other comprehensive income before reclassifications	808
Amounts reclassified from accumulated other comprehensive income	11
Net other comprehensive income	819
Balance as of September 30, 2013	$	1,340

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Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 01, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		64,484,346

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Acquisition (Tables)

9 Months Ended

Sep. 30, 2013

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the estimated acquisition date fair values of the net assets acquired (in thousands):

Oil and gas properties	$	191,466
Unevaluated oil and gas properties	12,033
Asset retirement obligations	(15,319		)
Net assets to be acquired	$	188,180

Summary pro forma statement of operations

The following unaudited summary pro forma statement of operations for the three and nine month periods ended September 30, 2013 and 2012 has been prepared to give effect to the Gulf of Mexico Acquisition as if it had occurred on January 1, 2012. The pro forma financial information is not necessarily indicative of the results that might have occurred had the transaction taken place on January 1, 2012 and is not intended to be a projection of future results. Future results may vary significantly from the results reflected in the following pro forma financial information because of normal production declines, changes in commodity prices, future acquisitions and divestitures, future development and exploration activities and other factors. Amounts in millions, except per share amounts.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2013		2012			2013		2012
Revenues	$	55,587	$	46,384		$	162,494	$	132,303
Income (Loss) from Operations	4,318		(38,178		)	15,487		(121,955		)
Net Income (Loss) available to common stockholders	3,014		(40,898		)	12,107		(127,306		)
Basic Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)
Diluted Earnings per Share	$	0.05	$	(0.65	)	$	0.19	$	(2.04	)