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: June 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 August 2, 2013 there were 64,530,468 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 June 30, 2013 and December 31, 2012	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2013 and 2012	2
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2013 and 2012	3
Consolidated Statements of Cash Flows for the Three and Six Months Ended June 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	23
Part II. Other Information
Item 1. Legal Proceedings	23
Item 1A. Risk Factors	23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26
Item 3. Defaults upon Senior Securities	26
Item 4. Mine Safety Disclosures	26
Item 5. Other Information	26
Item 6. Exhibits	27

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	June 30, 2013			December 31, 2012
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	8,113		$	14,904
Revenue receivable	14,007			17,742
Joint interest billing receivable	32,281			42,595
Other receivable	—			9,208
Derivative asset	1,999			830
Prepaid drilling costs	2,499			1,698
Other current assets	6,182			2,607
Total current assets	65,081			89,584
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,791,459			1,734,477
Unevaluated oil and gas properties	68,910			71,713
Accumulated depreciation, depletion and amortization	(1,508,820		)	(1,472,244		)
Oil and gas properties, net	351,549			333,946
Other property and equipment	12,627			12,370
Accumulated depreciation of other property and equipment	(8,144		)	(7,607		)
Total property and equipment	356,032			338,709
Derivative asset	388			—
Other assets, net of accumulated depreciation and amortization of $4,647 and $4,240, respectively	5,065			5,110
Deposit on acquisition	5,000			—
Total assets	$	431,566		$	433,403
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	39,923		$	58,960
Advances from co-owners	11,911			20,459
Oil and gas revenue payable	26,042			26,175
Accrued interest and preferred stock dividend	6,209			6,190
Asset retirement obligation	3,823			2,351
Derivative liability	205			233
Other accrued liabilities	6,408			6,535
Total current liabilities	94,521			120,903
Bank debt	65,000			50,000
10% Senior Notes	150,000			150,000
Asset retirement obligation	25,487			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 62,993 and 62,768 shares, respectively	63			63
Paid-in capital	278,335			276,534
Accumulated other comprehensive income	1,418			521
Accumulated deficit	(183,259		)	(189,528		)
Total stockholders’ equity	96,558			87,591
Total liabilities and stockholders’ equity	$	431,566		$	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						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Revenues:
Oil and gas sales	$	38,076		$	33,376		$	74,052		$	69,373
Gas gathering revenue	26			37			59			81
	38,102			33,413			74,111			69,454
Expenses:
Lease operating expenses	8,837			9,085			18,556			18,750
Production taxes	1,481			(1,917		)	2,509			(768		)
Depreciation, depletion and amortization	14,536			15,762			27,407			30,992
Ceiling test write-down	—			53,485			—			73,596
General and administrative	6,351			5,999			11,067			11,578
Accretion of asset retirement obligation	328			517			660			1,017
Interest expense	3,116			2,413			5,980			4,683
	34,649			85,344			66,179			139,848
Other income (expense):
Other income	62			123			256			272
Derivative income (expense)	594			(375		)	157			(375		)
	656			(252		)	413			(103		)
Income (loss) from operations	4,109			(52,183		)	8,345			(70,497		)
Income tax expense (benefit)	(840		)	1,049			(491		)	61
Net income (loss)	4,949			(53,232		)	8,836			(70,558		)
Preferred stock dividend	1,287			1,288			2,567			2,570
Net income (loss) available to common stockholders	$	3,662		$	(54,520	)	$	6,269		$	(73,128	)
Earnings per common share:
Basic
Net income (loss) per share	$	0.06		$	(0.87	)	$	0.10		$	(1.17	)
Diluted
Net income (loss) per share	$	0.06		$	(0.87	)	$	0.10		$	(1.17	)
Weighted average number of common shares:
Basic	62,963			62,363			62,899			62,289
Diluted	63,130			62,363			63,084			62,289

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013		2012			2013		2012
Net income (loss)	$	4,949	$	(53,232	)	$	8,836	$	(70,558	)
Change in fair value of derivative instruments,accounted for as hedges, net of income tax expense (benefit) of $840, ($1,049), $531 and ($597), respectively.	4,807		(1,772		)	897		(1,008		)
Comprehensive income (loss)	$	9,756	$	(55,004	)	$	9,733	$	(71,566	)

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Six Months Ended
	June 30,
	2013			2012
Cash flows from operating activities:
Net income (loss)	$	8,836		$	(70,558	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	(491		)	61
Depreciation, depletion and amortization	27,407			30,992
Ceiling test writedown	—			73,596
Accretion of asset retirement obligation	660			1,017
Share based compensation expense	1,780			3,838
Amortization costs and other	406			395
Non-cash derivative (income) expense	(157		)	375
Payments to settle asset retirement obligations	(94		)	(2,450		)
Changes in working capital accounts:
Revenue receivable	3,735			3,384
Prepaid drilling and pipe costs	(801		)	2,548
Joint interest billing receivable	10,314			8,962
Accounts payable and accrued liabilities	(19,195		)	4,602
Advances from co-owners	(8,548		)	(11,341		)
Other	(3,237		)	(3,153		)
Net cash provided by operating activities	20,615			42,268
Cash flows used in investing activities:
Investment in oil and gas properties	(52,740		)	(75,825		)
Investment in other property and equipment	(257		)	—
Deposit on acquisition	(5,000		)	—
Sale of oil and gas properties	18,914			275
Sale of unevaluated oil and gas properties	—			6,083
Net cash used in investing activities	(39,083		)	(69,467		)
Cash flows provided by financing activities:
Net payments for share based compensation plans	20			(383		)
Deferred financing costs	(774		)	(12		)
Payment of preferred stock dividend	(2,569		)	(2,570		)
Proceeds from bank borrowings	40,000			45,000
Repayment of bank borrowings	(25,000		)	(27,500		)
Net cash provided by financing activities	11,677			14,535
Net decrease in cash and cash equivalents	(6,791		)	(12,664		)
Cash and cash equivalents, beginning of period	14,904			22,263
Cash and cash equivalents, end of period	$	8,113		$	9,599
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	8,321		$	7,871
Income taxes	$	40		$	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 six month periods ended June 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 June 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 from several third party sellers certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $191.8 million, subject to customary adjustments to reflect an effective date of January 1, 2013 (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets include 14 producing wells and two wells awaiting completion, which are 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 "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 $0.5 million of deferred financing costs related to the New Notes in the second quarter 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.

In connection with the Gulf of Mexico Acquisition, the Company obtained a bridge commitment from a group of lenders to arrange certain senior unsecured bridge loans in an aggregate amount up to $185 million. As part of the agreement, the lenders under the bridge commitment were due a commitment fee of $0.3 million at the date of the agreement and $2.3 million if the Gulf of Mexico Acquisition closed. The bridge commitment was terminated upon the issuance of the New Notes and the closing of the Gulf of Mexico Acquisition, at which time the lenders under the bridge commitment were paid the commitment fee. The Company recognized $0.3 million of the commitment fee as an acquisition-related cost in general and administrative expenses in the second quarter of 2013 with the remaining $2.3 million to be recognized as an acquisition-related cost in general and administrative expenses in the third quarter of 2013.

The Gulf of Mexico Acquisition will be 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 Company also incurred $1 million of acquisition-related costs, including $0.3 million of the bridge commitment fee, which were recognized as general and administrative expenses in the second quarter 2013.

5

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

Oil and gas properties	$	188,778
Unevaluated oil and gas properties	19,036
Asset retirement obligations	(16,049		)
Net assets to be acquired	$	191,765

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 June 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	3,662		62,963
Attributable to participating securities	(87		)
BASIC EPS	$	3,575		62,963	$	0.06
Net income available to common stockholders	3,662			62,963
Effect of dilutive securities:
Stock options	—			167
Attributable to participating securities	(87		)	—
DILUTED EPS	$	3,575		63,130	$	0.06
For the Six Months Ended June 30, 2013	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	6,269		62,899
Attributable to participating securities	(163		)
BASIC EPS	$	6,106		62,899	$	0.10
Net income available to common stockholders	$	6,269		62,899
Effect of dilutive securities:
Stock options				185
Attributable to participating securities	(163		)	—
DILUTED EPS	$	6,106		63,084	$	0.10
For the Three Months Ended June 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(54,520	)	62,363	$	(0.87	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(54,520	)	62,363	$	(0.87	)
For the Six Months Ended June 30, 2012	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(73,128	)	62,289	$	(1.17	)
Effect of dilutive securities:
Stock options	—			—
Restricted stock	—			—
DILUTED EPS	$	(73,128	)	62,289	$	(1.17	)

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 six month periods ended June 30, 2013 because the inclusion would have been anti-dilutive. Options to purchase 1,265,500 and 1,277,600 shares of common stock were outstanding during the three and six month periods ended June 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 834,000 and 897,000 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 six month periods ended June 30, 2012, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for the respective periods. In addition, options to purchase 1,226,400 and 1,115,800 shares of common stock were outstanding during the three and six months ended June 30, 2012, respectively, that would not have been 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.

Note 5—Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Notes”) in a public offering. 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 June 30, 2013, $5.0 million had been accrued in connection with the September 1, 2013 interest payment and the Company was in compliance with all of the covenants contained in the Notes. As discussed in Note 2, the Company issued $200 million in principal amount of the New Notes on July 3, 2013.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank and Whitney Bank. 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 June 30, 2013 the Company had $65.0 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 March 29, 2013 the borrowing base was increased from $130 million to $150 million (subject to the aggregate commitments of the lenders then in effect). As of June 30, 2013, the aggregate commitments of the lenders was $100 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. In connection with the Gulf of Mexico Acquisition, the Company entered into an amendment to the senior secured bank credit facility to, among other things, permit the Gulf of Mexico Acquisition, permit up to $200 million of additional debt to finance the Gulf of Mexico Acquisition, increase the borrowing base from $150 million to $200 million upon completion of the Gulf of Mexico Acquisition and increase the aggregate commitment of the lenders from $100 million to $150 million upon completion of the Gulf of Mexico Acquisition. The next borrowing base redetermination is scheduled to occur by September 30, 2013. 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 rolling four quarter basis, of 3.0 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. Effective with the closing of the Gulf of Mexico Acquisition on July 3, 2013, the maximum ratio of debt to EBITDAX, determined on a tiered rolling four quarter basis, was adjusted to 3.5 to 1.0. 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

8

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 June 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):

	Six Months Ended June 30,
	2013			2012
Asset retirement obligation, beginning of period	$	27,260		$	30,427
Liabilities incurred	498			840
Liabilities settled	(94		)	(2,450		)
Accretion expense	660			1,017
Revisions in estimated cash flows	986			(42		)
Asset retirement obligation, end of period	29,310			29,792
Less: current portion of asset retirement obligation	(3,823		)	(1,034		)
Long-term asset retirement obligation	$	25,487		$	28,758

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 six month periods ended June 30, 2013 and 2012 is as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	93	$	212	$	89	$	435
Non-Qualified Stock Options	66		164		135		328
Restricted stock	1,081		1,539		1,572		3,075
Restricted stock units	253		—		543		—
Share based compensation	$	1,493	$	1,915	$	2,339	$	3,838

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 June 30, 2012 and March 31, 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 $2.48 and $2.97 per Mcf of natural gas, $106.60 and $107.99 per barrel of oil and $7.93 and $8.74 per Mcfe of Ngl, respectively. 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 $53.5 million and $20.1 million during the three months ended June 30, 2012 and March 31, 2012, respectively. The Company’s cash flow hedges in place at June 30, 2012decreased the ceiling test write-down by approximately $1.2 million.

The Company recognized no such ceiling test write-down during the three and six months ended June 30, 2013.

9

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 or 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). At June 30, 2013, the Company designated all but one 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 ($877,000) and $3,230,000, Ngl hedges of zero and $232,000 and oil hedges of ($1,000) and $415,000 for the three months endedJune 30, 2013 and 2012, respectively. For the six month periods ended June 30, 2013 and 2012, oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($345,000) and $5,385,000 , Ngl hedges of zero and $232,000 and oil hedges of ($146,000) and $362,000, respectively.

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

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July - December 2013	Three-Way Collar	10,000 Mmbtu	$2.00-$3.00-$4.09
July - December 2013	Swap	30,000 Mmbtu	$3.78
July - December 2013	Collar	5,000 Mmbtu	$4.00 - $4.75
2014	Swap	10,000 Mmbtu	$4.08
Crude Oil:
July - December 2013	Swap	500 Bbls	$100.87
2014	Swap	250 Bbls	$92.50

At June 30, 2013, the Company had accumulated other comprehensive income of approximately $1.4 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of June 30, 2013, the Company would realize a $1.2 milliongain, net of taxes, during the next 12 months. This gain is expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

All of the Company’s commodity derivative instruments are designated as effective cash flow hedges with the exception of the three-way collar. 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 June 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
June 30, 2013	Derivative asset (short-term)	$	1,999
June 30, 2013	Derivative asset (long-term)	$	388
June 30, 2013	Derivative liability (short-term)	$	(129	)
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 June 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 June 30, 2013	$	4,807		Oil and gas sales	$	(878	)
Commodity Derivatives at June 30, 2012	$	(1,772	)	Oil and gas sales	$	3,877

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the six months ended June 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 June 30, 2013	$	897		Oil and gas sales	$	(491	)
Commodity Derivatives at June 30, 2012	$	(1,008	)	Oil and gas sales	$	5,979

Derivatives not designated as hedging instruments:

The Company’s three-way collar has not been designated as an effective cash flow hedge and therefore both realized and unrealized (mark-to-market) gains or losses on this derivative are recorded as derivative income (expense) in the statement of operations. 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 June 30, 2013 and December 31, 2012:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
June 30, 2013	Derivative liability (short-term)	$	(76	)
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 June 30, 2013 and 2012:

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at June 30, 2013	$	594
Commodity Derivatives at June 30, 2012	$	(375	)

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

Instrument	Amount of Unrealized Gain (Loss) Recognized in Derivative Expense
Commodity Derivatives at June 30, 2013	$	157
Commodity Derivatives at June 30, 2012	$	(375	)

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;

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

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at June 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. 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 June 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 June 30, 2013	$	—	$	2,182	$	—
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 June 30, 2013 and December 31, 2012. The estimated fair value of the Notes was $153.0 million and $155.3 million as of June 30, 2013 and December 31, 2012, respectively, as compared to the book value of $150 million as of each date. 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 expenses 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 $47.9 million as of June 30, 2013.

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 June 30, 2013 (in thousands):

	Gains and Losses on Cash Flow Hedges			Change in Valuation Allowance			Total
Balance as of March 31, 2013	$	(2,128	)	$	(1,261	)	$	(3,389	)
Other comprehensive income before reclassifications	3,018			1,261			4,279
Amounts reclassified from accumulated other comprehensive income	528			—			528
Net other comprehensive income	3,546			1,261			4,807
Balance as of June 30, 2013	$	1,418		$	—		$	1,418

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

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of December 31, 2012	$	521	$	—	$	521
Other comprehensive income before reclassifications	612		—		612
Amounts reclassified from accumulated other comprehensive income	285		—		285
Net other comprehensive income	897		—		897
Balance as of June 30, 2013	$	1,418	$	—	$	1,418

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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 June 30, 2013, 90% of our estimated proved reserves and 73% of our first six 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.

During February 2012, we amended our JDA to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry was expanded to provide for development in both the Mississippian Lime and Woodford Shale plays whereby we will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry is subject to extensions in one-year intervals and as of June 30, 2013, approximately $54.5 million remained available. See “Liquidity and Capital Resources-Source of Capital: Joint Ventures.”

On July 3, 2013, we acquired from several third party sellers certain shallow water Gulf of Mexico shelf oil and gas properties (the “Acquired Assets”), for an aggregate cash purchase price of $191.8 million, subject to customary adjustments to reflect an effective date of January 1, 2013, (collectively, the "Gulf of Mexico Acquisition"). The Acquired Assets include 14 producing wells and 2 wells awaiting completion, which are 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

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quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.

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

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Future Abandonment Costs

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

Derivative Instruments

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

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

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Production:
Oil (Bbls)	115,697		116,037		241,420		257,312
Gas (Mcf)	6,731,754		6,945,466		13,168,349		13,674,781
Ngl (Mcfe)	1,256,814		763,302		2,321,461		1,356,437
Total Production (Mcfe)	8,682,750		8,404,990		16,938,330		16,575,090
Sales:
Total oil sales	$	12,024,212	$	12,831,097	$	25,168,522	$	28,340,054
Total gas sales	20,247,600		15,457,658		36,970,632		30,737,611
Total ngl sales	5,804,172		5,087,135		11,913,118		10,295,240
Total oil and gas sales	$	38,075,984	$	33,375,890	$	74,052,272	$	69,372,905
Average sales prices:
Oil (per Bbl)	$	103.93	$	110.58	$	104.25	$	110.14
Gas (per Mcf)	3.01		2.23		2.81		2.25
Ngl (per Mcfe)	4.62		6.66		5.13		7.59
Per Mcfe	4.39		3.97		4.37		4.19

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of ($877,000) and $3,230,000, Ngl hedges of zero and $232,000 and oil hedges of ($1,000) and $415,000 for the three months endedJune 30, 2013 and 2012, respectively. The above sales and average sales prices include increases (reductions) to revenue related

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to the settlement of gas hedges of ($345,000) and $5,385,000, Ngl hedges of zero and $232,000, and oil hedges of ($146,000) and $362,000, respectively.

Net income (loss) available to common stockholders totaled $3,662,000 and ($54,520,000) for the quarters ended June 30, 2013 and 2012, respectively, while net income (loss) available to common stockholders totaled $6,269,000 and ($73,128,000) for the six months ended June 30, 2013 and 2012, respectively. The primary fluctuations were as follows:

Production Total production increased3% and 2% during the three and six month periods ended June 30, 2013 as compared to the respective 2012 periods. Gas production during the three and six month periods ended June 30, 2013decreased3% and 4% from the comparable periods in 2012. The decrease in gas production was primarily the result of the sale of our Fayetteville Shale assets in Arkansas in December 2012 as well as normal production declines at our dry gas Oklahoma fields. Partially offsetting these decreases were increases in gas production as a result of the successful drilling programs in our La Cantera field and our liquids rich Woodford acreage. As a result of our recent Gulf of Mexico Acquisition and continued drilling in our longer-life basins, offset by the loss of production resulting from the sale of our Fayetteville assets, we expect our average daily gas production in 2013 to increase as compared to that of 2012.

Oil production during the six month period ended June 30, 2013decreased6% from the 2012 period due primarily to continued normal production declines in our onshore and offshore Gulf of Mexico and East Texas fields. Partially offsetting these decreases were increases from the continued success of our La Cantera field as well as our Carthage drilling programs. As a result of our recent Gulf of Mexico Acquisition, we expect our average daily oil production during 2013 to increase significantly as compared to 2012.

Ngl production during the three and six month periods ended June 30, 2013increased65% and 71% from the respective 2012 periods due to the success experienced in our La Cantera field and the liquids rich portion of our Oklahoma properties. Partially offsetting these increases were decreases as a result of normal production declines at our offshore Gulf of Mexico fields. As a result of ongoing drilling in our liquids rich Oklahoma assets and increased production from La Cantera, we expect our daily Ngl production in 2013 to increase as compared to 2012.

Prices Including the effects of our hedges, average gas prices per Mcf for the three and six month periods ended June 30, 2013 were $3.01 and $2.81 as compared to $2.23 and $2.25 for the 2012 periods. Average oil prices per Bbl for the three and six months ended June 30, 2013 were $103.93 and $104.25 as compared to $110.58 and $110.14 for the 2012 periods and average Ngl prices per Mcfe were $4.62 and $5.13 for the three and six months ended June 30, 2013, as compared to $6.66 and $7.59 for the 2012 periods. Stated on an Mcfe basis, unit prices received during the three and six months ended June 30, 2013 were 11% and 4%higher, respectively, than prices received during the comparable 2012 periods.

Revenue Including the effects of hedges, oil and gas sales during the three months endedJune 30, 2013increased14% to $38,076,000, as compared to oil and gas sales of $33,376,000 during the 2012 period. Including the effects of hedges, oil and gas sales during the six months endedJune 30, 2013increased7% to $74,052,000, as compared to oil and gas sales of $69,373,000 during the 2012 period. These increases were primarily the result of higher prices received for our oil and natural gas production during the 2013 periods.

Expenses Lease operating expenses for the three and six months ended June 30, 2013 totaled $8,837,000 and $18,556,000, respectively, as compared to $9,085,000 and $18,750,000 during the 2012 periods. Per unit lease operating expenses totaled $1.02 and $1.10 per Mcfe, respectively, during the three and six month periods ended June 30, 2013 as compared to $1.08 and $1.13 per Mcfe during the respective 2012 periods. The decrease in lease operating costs is primarily due to a decrease in expensed workovers during the 2013 periods as compared to the 2012 periods. As a result of the recent Gulf of Mexico Acquisition, we expect an increase in the overall amount of lease operating expenses during the remainder of 2013, but we expect per unit lease operating costs to approximate per unit amounts in 2012.

Production taxes for the three and six months ended June 30, 2013 totaled $1,481,000 and $2,509,000, respectively, as compared to ($1,917,000) and ($768,000), respectively, during the 2012 periods. The decreases during 2012 were the 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 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.

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General and administrative expenses during the three and six months ended June 30, 2013 totaled $6,351,000 and $11,067,000, respectively, as compared to $5,999,000 and $11,578,000 during the 2012 periods. Included in general and administrative expenses was non-cash share-based compensation expense as follows (in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Stock options:
Incentive Stock Options	$	93	$	212	$	89	$	435
Non-Qualified Stock Options	66		164		135		328
Restricted stock	1,081		1,539		1,572		3,075
Non-cash share based compensation	$	1,240	$	1,915	$	1,796	$	3,838

General and administrative expenses decreased4% during the six months ended June 30, 2013 as compared to the comparable period of 2012 primarily due to decreased non-cash share-based compensation expense during the 2013 period. We capitalized $3,045,000 and $6,156,000, respectively, of general and administrative costs during the three and six month periods ended June 30, 2013 compared to $3,158,000 and $6,306,000, respectively, during the 2012 periods. Included in general and administrative expenses for the 2013 periods are $996,000 of transaction-related costs with respect to our recent Gulf of Mexico Acquisition. We incurred additional transaction-related costs of approximately $2.3 million related to the commitment fee for the bridge commitment obtained in connection with the Gulf of Mexico Acquisition upon the closing of the transaction in July 2013, which will be recorded as general and administrative expenses in the third quarter of 2013. As a result of the transaction-related costs, we expect a significant increase in 2013 general and administrative expenses as compared to 2012 general and administrative expenses.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and six months ended June 30, 2013 totaled $14,259,000, or $1.64 per Mcfe, and $26,870,000, or $1.59 per Mcfe, respectively, as compared to $15,488,000, or $1.84 per Mcfe, and $30,467,000, or $1.84 per Mcfe, respectively, during the comparable 2012 periods. The decrease in the per unit DD&A rate is primarily the result of ceiling test write-downs recognized with respect to our evaluated oil and gas properties during 2012. As a result of the Gulf of Mexico Acquisition, we expect our DD&A rate to increase during the remainder of 2013.

At June 30, 2012 and March 31, 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 $2.48 and $2.97 per Mcf of natural gas, $106.60 and $107.99 per barrel of oil, and $7.93 and $8.74 per Mcfe of Ngl, respectively. 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 $53,485,000 and $20,111,000, respectively, during the three months ended June 30, 2012 and March 31, 2012. Our cash flow hedges in place at June 30, 2012decreased the ceiling test write-down by approximately $1,200,000.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $3,116,000 and $5,980,000 during the three and six months ended June 30, 2013, respectively, as compared to $2,413,000 and $4,683,000, respectively, during the 2012 periods. During the three and six month periods ended June 30, 2013, our capitalized interest totaled $1,316,000 and $2,768,000, respectively, as compared to $1,733,000 and $3,583,000, respectively, during the 2012 periods. The increase in interest expense was due to increased borrowings outstanding under our bank credit facility during the 2013 periods as compared to the prior year periods. Interest expense will increase significantly during the remainder of 2013 as a result of the issuance of $200 million of 10% senior notes due 2017, which were used to finance the Gulf of Mexico Acquisition.

Income tax expense (benefit) during the three and six months ended June 30, 2013 totaled ($840,000) and ($491,000), respectively, as compared to $1,049,000 and $61,000, 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 $47,854,000 as of June 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 June 30, 2013 we had a working capital deficit of approximately $29 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

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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 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 $42.3 million during the six months ended June 30, 2012 to $20.6 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 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 “Notes”) in a public offering. At June 30, 2013, the estimated fair value of the Notes was $153.0 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 June 30, 2013, $5.0 million had been accrued in connection with the September 1, 2013 interest payment and we were in compliance with all of the covenants contained in the Notes.

On July 3, 2013, we closed a private offering of $200 million aggregate principal amount of 10% Senior Notes due 2017 (the "New 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 Company's existing $150 million aggregate principal amount of 10% Senior Notes due 2017. The net proceeds from the offering were used to finance the $191.8 million aggregate cash purchase price of the Gulf of Mexico Acquisition, which also closed on July 3, 2013.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank and Whitney Bank. 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 June 30, 2013 we had $65 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 June 30, 2013 was $150 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders at June 30, 2013 was $100 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. Effective with the closing of the Gulf of Mexico Acquisition on July 3, 2013, the borrowing base was increased to $200 million and the aggregate commitments of the lenders was increased to $150 million, subject to certain conditions.

The next borrowing base redetermination is scheduled to occur by September 30, 2013. 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

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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, determined on a rolling four quarter basis, of 3.0 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. Effective with the closing of the Gulf of Mexico Acquisition on July 3, 2013, the maximum ratio of total debt to EBITDAX, determined on a tiered rolling four quarter basis, was adjusted to 3.5 to 1.0. 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 June 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 $250 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 June 30, 2013, approximately $54.5 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 $54.2 million was incurred during the first six 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 six months ended June 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.

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Use of Capital: Acquisitions

On July 3, 2013, the Company closed the Gulf of Mexico Acquisition for an aggregate cash purchase price of $191.8 million, subject to customary adjustments to reflect an effective date of January 1, 2013. The Acquired Assets include 14 producing wells and 2 wells awaiting completion, which are 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.

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 $4.2 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three and six months ended June 30, 2013, we paid $0.9 million and $0.5 million, respectively, to the counterparties to our derivative instruments in connection with net hedge settlements.

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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.

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

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July - December 2013	Three-Way Collar	10,000 Mmbtu	$2.00-$3.00-$4.09
July - December 2013	Swap	30,000 Mmbtu	$3.78
July - December 2013	Collar	5,000 Mmbtu	$4.00 - $4.75
2014	Swap	10,000 Mmbtu	$4.08
Crude Oil:
July - December 2013	Swap	500 Bbls	$100.87
2014	Swap	250 Bbls	$92.50

During July 2013, we entered into the following additional oil contracts:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Oil:
July - December 2013	Swap	250 Bbls	$98.80
August - December 2013	Swap	250 Bbls	$103.70
September - December 2013	Swap	250 Bbls	$106.25
2014	Swap	200 Bbls	$97.80

After executing the above transactions, the Company has approximately 8.3 Bcf of gas volumes at an average floor price of $3.63 per Mcf and approximately 207,000 barrels of oil volumes at an average price of $102.10 hedged for 2013. Additionally, the Company has approximately 3.6 Bcf of gas volumes at $4.08 per Mcf and approximately 164,000 barrels of oil volumes at an average price of $94.86 hedged for 2014.

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 30% of our total debt as of June 30, 2013. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of June 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 $0.1 million.

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Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

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

Changes in Internal Control Over Financial Reporting

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

Part II

Item 1. LEGAL PROCEEDINGS

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;

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• 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.

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

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized ceiling test write-downs totaling $137.1 million during the year ended December 31, 2012. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

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 as of June 30, 2013, on a pro forma basis to reflect the issuance and sale of $200 million aggregate principal amount of new 10% senior notes due 2017, which we refer to as our new 10% notes, and the application of the net proceeds thereof, we would have had approximately $415 million of outstanding senior indebtedness. We would also have been able to incur $85 million of secured indebtedness under our senior secured bank credit facility, subject, however, to limitations on incurrence of indebtedness under the indenture governing our new 10% notes and the indenture governing our existing 10% senior notes due 2017, which we refer to as our existing 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 our new 10% notes and our existing 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;

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• 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 new 10% notes and on our existing 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 new 10% notes and our existing 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 new 10% notes and our existing 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.

Approximately forty-five percent of our production is exposed to the additional risk of severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise.

At June 30, 2013, giving effect to the Gulf of Mexico Acquisition, approximately 45% of our production and approximately 24% of our reserves are located in the Gulf of Mexico and along the Gulf Coast Basin. Operations in this area are subject to severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise. Some of these adverse conditions can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, certain of our Gulf Coast Basin properties have experienced damages and production downtime as a result of storms including Hurricanes Katrina and Rita, and more recently Hurricanes Gustav and Ike. In addition, according to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases may be contributing to global warming of the earth's atmosphere and to global climate change, which may exacerbate the severity of these adverse conditions. As a result, such conditions may pose increased climate-related risks to our assets and operations.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks; however, losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

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

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• potential environmental issues, litigation and other liabilities.

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 2.1*, Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and Hall-Houston Exploration II, L.P. (incorporated herein by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K filed with the SEC on June 20, 2013).

Exhibit 2.2*, Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and Hall-Houston Exploration III, L.P. (incorporated herein by reference to Exhibit 2.2 to the Company's Current Report on Form 8-K filed with the SEC on June 20, 2013).

Exhibit 2.3*, Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and Hall-Houston Exploration IV, L.P. (incorporated herein by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K filed with the SEC on June 20, 2013).

Exhibit 2.4*, Purchase and Sale Agreement dated as of June 19, 2013, between PetroQuest Energy, L.L.C. and GOM-H Exploration, LLC (incorporated herein by reference to Exhibit 2.3 to the Company's Current Report on Form 8-K filed with the SEC on June 20, 2013).

Exhibit 10.1, PetroQuest Energy, Inc. 2013 Incentive Plan (incorporated by reference to Appendix A to the Company's Definitive Proxy Statement on Schedule 14A filed with the SEC on April 9, 2013).

Exhibit 10.2, Sixth Amendment to Credit Agreement dated as of June 19, 2013, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IBERIABANK and Whitney Bank (incorporated herein by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K filed with the SEC on June 20, 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

* The registrant agrees to furnish supplementally a copy of any omitted schedule to these Purchase and Sale Agreements to the SEC upon request.

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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:	August 6, 2013	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief (Authorized Officer and Principal Financial Officer)

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