10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2015

¨ 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 July 31, 2015 there were 65,820,632 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, 2015 and December 31, 2014	1
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2015 and 2014	2
Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2015 and 2014	3
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2015 and 2014	4
Notes to Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	14
Item 3. Quantitative and Qualitative Disclosures About Market Risk	21
Item 4. Controls and Procedures	22
Part II. Other Information
Item 1. Legal Proceedings	22
Item 1A. Risk Factors	23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	24
Item 3. Defaults upon Senior Securities	25
Item 4. Mine Safety Disclosures	25
Item 5. Other Information	25
Item 6. Exhibits	25

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	June 30, 2015			December 31, 2014
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	141,016		$	18,243
Revenue receivable	7,750			16,485
Joint interest billing receivable	49,112			46,778
Other receivable	13,915			—
Derivative asset	6,247			8,631
Prepaid drilling costs	102			847
Other current assets	6,735			5,566
Total current assets	224,877			96,550
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,279,721			2,222,753
Unevaluated oil and gas properties	29,743			109,119
Accumulated depreciation, depletion and amortization	(1,040,886		)	(1,648,060		)
Oil and gas properties, net	268,578			683,812
Other property and equipment	15,087			14,953
Accumulated depreciation of other property and equipment	(10,998		)	(10,313		)
Total property and equipment	272,667			688,452
Other assets, net of accumulated depreciation and amortization of $8,997 and $7,847, respectively	5,528			5,893
Total assets	$	503,072		$	790,895
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	62,761		$	102,954
Advances from co-owners	30,665			12,819
Oil and gas revenue payable	24,192			22,333
Accrued interest and preferred stock dividend	12,832			12,764
Asset retirement obligation	1,405			2,756
Derivative liability	572			—
Accrued acquisition cost	5,655			17,690
Other accrued liabilities	6,722			5,394
Total current liabilities	144,804			176,710
Bank debt	—			75,000
10% Senior Notes	350,000			350,000
Asset retirement obligation	53,218			52,214
Other long-term liability	510			62
Commitments and contingencies
Stockholders’ equity (deficit):
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	1			1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 64,957 and 64,721 shares, respectively	65			65
Paid-in capital	288,767			285,957
Accumulated other comprehensive income	3,564			5,420
Accumulated deficit	(337,857		)	(154,534		)
Total stockholders’ equity (deficit)	(45,460		)	136,909
Total liabilities and stockholders’ equity (deficit)	$	503,072		$	790,895

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,
	2015			2014		2015			2014
Revenues:
Oil and gas sales	$	32,550		$	60,581	$	66,001		$	120,547
Expenses:
Lease operating expenses	11,191			12,168		22,093			24,426
Production taxes	948			1,492		1,904			2,969
Depreciation, depletion and amortization	18,345			21,702		38,999			42,130
Ceiling test write-down	65,495			—		174,406			—
General and administrative	6,519			6,467		11,858			12,709
Accretion of asset retirement obligation	823			708		1,682			1,499
Interest expense	8,596			7,380		16,470			15,016
	111,917			49,917		267,412			98,749
Gain on sale of oil and gas properties	21,531			—		21,531			—
Other income	40			215		197			404
Income (loss) from operations	(57,796		)	10,879		(179,683		)	22,202
Income tax expense	2,000			—		1,073			—
Net income (loss)	(59,796		)	10,879		(180,756		)	22,202
Preferred stock dividend	1,287			1,287		2,567			2,567
Income (loss) available to common stockholders	$	(61,083	)	$	9,592	$	(183,323	)	$	19,635
Earnings per common share:
Basic
Net income (loss) per share	$	(0.94	)	$	0.15	$	(2.83	)	$	0.30
Diluted
Net income (loss) per share	$	(0.94	)	$	0.15	$	(2.83	)	$	0.30
Weighted average number of common shares:
Basic	64,891			64,103		64,833			63,940
Diluted	64,891			64,167		64,833			63,996

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,
	2015			2014		2015			2014
Net income (loss)	$	(59,796	)	$	10,879	$	(180,756	)	$	22,202
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $2,046, $0, $1,099, and $0, respectively	(3,454		)	860		(1,856		)	(2,558		)
Comprehensive income (loss)	$	(63,250	)	$	11,739	$	(182,612	)	$	19,644

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,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(180,756	)	$	22,202
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense	1,073			—
Depreciation, depletion and amortization	38,999			42,130
Ceiling test writedown	174,406			—
Accretion of asset retirement obligation	1,682			1,499
Share-based compensation expense	2,828			2,716
Amortization costs and other	1,162			1,094
Gain on sale of oil and gas properties	(21,531		)	—
Payments to settle asset retirement obligations	(1,186		)	(1,149		)
Changes in working capital accounts:
Revenue receivable	8,735			455
Prepaid drilling costs	745			134
Joint interest billing receivable	(1,171		)	8,589
Accounts payable and accrued liabilities	(36,051		)	8,614
Advances from co-owners	17,846			15,438
Other	(1,155		)	1,022
Net cash provided by operating activities	5,626			102,744
Cash flows provided by (used in) investing activities:
Investment in oil and gas properties	(62,451		)	(76,993		)
Investment in other property and equipment	(134		)	(468		)
Sale of oil and gas properties	257,698			600
Net cash provided by (used in) investing activities	195,113			(76,861		)
Cash flows used in financing activities:
Net payments for share based compensation	432			1,039
Deferred financing costs	(829		)	(109		)
Payment of preferred stock dividend	(2,569		)	(2,565		)
Proceeds from bank borrowings	70,000			10,000
Repayment of bank borrowings	(145,000		)	(12,500		)
Net cash used in financing activities	(77,966		)	(4,135		)
Net increase in cash and cash equivalents	122,773			21,748
Cash and cash equivalents, beginning of period	18,243			9,153
Cash and cash equivalents, end of period	$	141,016		$	30,901
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest	$	18,626		$	18,700
Income taxes (refunds)	$	(26	)	$	—

See accompanying Notes to Consolidated Financial Statements.

4

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Basis of Presentation

The consolidated financial information for the three and six month periods ended June 30, 2015 and 2014, 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, 2015 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, 2014 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, 2014.

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

Note 2—Acquisitions and Divestitures

Acquisition:

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

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. If the $14 million in drilling, completion and lease acquisition costs is not fully funded by December 31, 2015, any remaining balance becomes payable at the election of our joint venture partner. At June 30, 2015, $5.7 million of the cash funding for future drilling, completion and lease acquisition costs remained outstanding. The liability is reflected as accrued acquisition costs in the Consolidated Balance Sheet.

Divestiture:

On June 4, 2015, the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime (the “Sold Assets”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1, 2015. At closing, the Company received $257.7 million in cash and recognized a receivable of $13.9 million related to the remainder of the adjusted purchase price to be received within 180 days as further discussed below.

In connection with the sale, the Company entered into a Contract Operating Services Agreement ("COSA") whereby the Company will retain a minimal working interest in the Sold Assets and will provide certain services as a contract operator for a period of one year from the closing date of the sale, subject to renewal for two additional one-year terms. During the 180 day period following the closing of the sale, for each of the first 14 wells spud by the Company as contract operator under the COSA, the Company will receive $1 million of the $13.9 million remaining purchase price as discussed above. If at the end of the 180 day period any portion of the purchase price remains outstanding, the Company will receive the balance in full.

At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227 Bcfe, which represented approximately 57% of the Company's estimated proved reserves. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $21.5 million. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

5

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, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(61,083	)	64,891	$	(0.94	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(61,083	)	64,891	$	(0.94	)
For the Six Months Ended June 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(183,323	)	64,833	$	(2.83	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(183,323	)	64,833	$	(2.83	)
For the Three Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	9,592		64,103
Attributable to participating securities	(273		)
BASIC EPS	$	9,319		64,103	$	0.15
Net income available to common stockholders	$	9,592		64,103
Effect of dilutive securities:
Stock options	—			64
Attributable to participating securities	(273		)	—
DILUTED EPS	$	9,319		64,167	$	0.15
For the Six Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	19,635		63,940
Attributable to participating securities	(571		)
BASIC EPS	$	19,064		63,940	$	0.30
Net income available to common stockholders	$	19,635		63,940
Effect of dilutive securities:
Stock options	—			56
Attributable to participating securities	(571		)	—
DILUTED EPS	$	19,064		63,996	$	0.30

An aggregate of 0.4 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three and six month periods ended June 30, 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods. Options to purchase 1.4 million and 1.5 million shares of common stock were outstanding during the three and six month periods ended June 30, 2015, 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

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three and six month periods ended June 30, 2014, respectively, because the inclusion would have been anti-dilutive. Options to purchase 0.9 million and 1.1 million shares of common stock were outstanding during the three and six months ended June 30, 2014, 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.

Note 5—Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017 (the “Existing Notes”). On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no independent assets or operations and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission.

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, 2015, $11.7 million had been accrued in connection with the September 1, 2015 interest payment and the Company was in compliance with all of the covenants contained in the Notes. Pursuant to the asset sale covenant of the Notes, if we do not use certain of the proceeds of the Woodford and Mississippian Lime divestiture to repay senior indebtedness or to acquire additional assets or make capital expenditures in the oil and gas business within one year of the divestiture, we will be required to use such proceeds to make an offer to the holders of the Notes to repurchase the Notes at a purchase price of 100% of their principal amount, without premium, plus accrued but unpaid interest.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 10% Senior Notes due 2017 remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of June 30, 2015 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is 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. In connection with the most recent redetermination related to the Sold Assets, the borrowing base was reduced to $70 million (subject to the aggregate commitments of the lenders then in effect) effective June 4, 2015. The aggregate commitments of the lenders is currently $70 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next scheduled borrowing base redetermination, which was scheduled to occur by September 30, 2015, has been waived and additional interim borrowing base redeterminations have been scheduled to occur by September 1, 2015 and December 1, 2015. 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 Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.75% to 1.75% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.75% to 2.75% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%.  For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

8

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 4.0 to 1.0 as of the last day of the fiscal quarters ending June 30, 2015 through December 31, 2016 and 3.5 to 1.0 as of the last day of any fiscal quarter ending thereafter, in each case determined on a rolling four quarter basis, and to provide that the amount of total debt for the four consecutive fiscal quarter periods ending June 30, 2015, September 30, 2015 and December 31, 2015 shall be reduced by the amount of unencumbered and unrestricted net cash proceeds received by the Company from the Sold Assets (such reduction amount not to exceed $130,000,000 for so long as the Company has not redeemed, in whole or in part, its 10% Senior Notes due 2017), and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of June 30, 2015, the Company was in compliance with all such 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,
	2015			2014
Asset retirement obligation, beginning of period	$	54,970		$	48,536
Liabilities incurred	397			224
Liabilities settled	(1,186		)	(1,149		)
Accretion expense	1,682			1,499
Revisions in estimates	554			742
Divestiture of oil and gas properties	(1,794		)	—
Asset retirement obligation, end of period	54,623			49,852
Less: current portion of asset retirement obligation	(1,405		)	(2,959		)
Long-term asset retirement obligation	$	53,218		$	46,893

Note 7—Ceiling Test

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

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At March 31, 2015 and June 30, 2015, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.20 per Mcf of natural gas, $81.33 and $71.27 per barrel of oil and $3.52 and $3.35 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $108.9 million and $65.5 million during the three months ended March 31, 2015 and June 30, 2015, respectively. The Company’s cash flow hedges in place at June 30, 2015 increased the ceiling test write-down by approximately $1 million.

Note 8—Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment

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are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At June 30, 2015, all of the Company's derivative instruments were designated as effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $4,181,000 and ($2,170,000), oil hedges of ($288,000) and ($672,000) and Ngl hedges of $136,000 and zero for the three months endedJune 30, 2015 and 2014, respectively. For the six month periods ended June 30, 2015 and 2014, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $6,505,000 and ($5,139,000), oil hedges of ($261,000) and ($1,106,000) and Ngl hedges of $157,000zero, respectively.

As of June 30, 2015, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July 2015 - December 2015	Swap	40,000 Mmbtu	$3.62
July 2015 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2015 - September 2015	Swap	5,000 Mmbtu	$2.89
Crude Oil:
July 2015 - December 2015	Swap (LLS)	500 Bbls	$56.68
Propane:
July 2015 - December 2015	Swap	250 Bbls	$25.62

LLS - Louisiana Light Sweet

At June 30, 2015, the Company had recognized accumulated other comprehensive income of approximately $3.6 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of June 30, 2015, the Company would reclassify approximately $3.6 million, net of taxes, of accumulated other comprehensive income into earnings during the next 12 months. These gains are expected to be reclassified to oil and gas sales based on the schedule of oil and gas volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at June 30, 2015 and December 31, 2014:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
June 30, 2015	Derivative asset	$	6,247
June 30, 2015	Derivative liability	$	(572	)
December 31, 2014	Derivative asset	$	8,631

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended June 30, 2015 and 2014:

Instrument	Amount of 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, 2015	$	(1,471	)	Oil and gas sales	$	4,029
Commodity Derivatives at June 30, 2014	$	(1,982	)	Oil and gas sales	$	(2,842	)

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Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the six months ended June 30, 2015 and 2014 :

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, 2015	$	3,446		Oil and gas sales	$	6,401
Commodity Derivatives at June 30, 2014	$	(8,803	)	Oil and gas sales	$	(6,245	)

Note 9 – Fair Value Measurements

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

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

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

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

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at June 30, 2015 were in the form of swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of June 30, 2015 and December 31, 2014 (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:
June 30, 2015	$	—	$	5,675	$	—
December 31, 2014	$	—	$	8,631	$	—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at June 30, 2015 and December 31, 2014. The fair value of the Notes was approximately $327 million and $301 million as of June 30, 2015 and December 31, 2014, respectively, as compared to the book value of $350 million as of each date. The fair value of the Notes was determined based upon a market quote provided by an independent broker, which represents a Level 2 input.

Note 10—Income Taxes

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs recognized, the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $101.2 million as of June 30, 2015.

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Note 11 - Other Comprehensive Income

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

	Gains and Losses on Cash Flow Hedges
Balance as of March 31, 2015	$7,018
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,471	)
Income tax effect	547
Net of tax	(924	)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,029	)
Income tax effect	1,499
Net of tax	(2,530	)
Net other comprehensive loss	(3,454	)
Balance as of June 30, 2015	$3,564

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

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	3,446
Income tax effect	(1,282	)
Net of tax	2,164
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(6,401	)
Income tax effect	2,381
Net of tax	(4,020	)
Net other comprehensive loss	(1,856	)
Balance as of June 30, 2015	$3,564

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The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of March 31, 2014	($2,834)		($1,680)		($4,514)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,982	)	—		(1,982	)
Income tax effect	737		(737	)	—
Net of tax	(1,245	)	(737	)	(1,982	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	2,842		—		2,842
Income tax effect	(1,057	)	1,057		—
Net of tax	1,785		1,057		2,842
Net other comprehensive income	540		320		860
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of December 31, 2013	($688)		($408)		($1,096)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(8,803	)	—		(8,803	)
Income tax effect	3,275		(3,275	)	—
Net of tax	(5,528	)	(3,275	)	(8,803	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	6,245		—		6,245
Income tax effect	(2,323	)	2,323		—
Net of tax	3,922		2,323		6,245
Net other comprehensive loss	(1,606	)	(952	)	(2,558	)
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

Note 12 - Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 will become effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not expect the adoption of ASU 2015-03 will have a material impact on our consolidated financial statements.

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Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in 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 through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in East Texas through 2013, we have invested a majority of our capital into growing our longer life assets. During the eleven year period ended December 31, 2014, we have realized a 94% drilling success rate on 976 gross wells drilled. Comparing 2014 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 348% and estimated proved reserves by 377%.

On June 4, 2015, we completed the sale of a majority of our interests in the Woodford and Mississippian Lime (the “Sold Assets”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1, 2015. At closing, the Company received $257.7 million in cash and recognized a receivable of $13.9 million related to the remainder of the adjusted purchase price to be received within 180 days of the closing of the sale. Net proceeds from the sale were used to repay all borrowings outstanding under our bank credit facility and increase cash on hand to improve liquidity.

From January 1, 2015 through the closing date of June 4, 2015, the Sold Assets produced approximately 45.6 MMcfe per day and generated net operating cash flow of approximately $11.7 million. At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227 Bcfe.

In response to the decline in commodity prices that began in late 2014, we have significantly reduced our capital expenditures in 2015 as compared to 2014. In addition and as discussed above, we recently completed the largest divestiture in the Company’s history in order to significantly strengthen our liquidity position, reduce our indebtedness under our bank credit facility and focus our future development efforts primarily on the Cotton Valley play in the Carthage Field in East Texas. As of June 30, 2015, we had $141 million of cash on hand and had no borrowings outstanding under our $70 million bank credit facility. We are presently evaluating various deleveraging and refinancing options with respect to our 10% Senior Notes due 2017, as well as considering plans to resume drilling activity in the Cotton Valley play in the fourth quarter of 2015. We plan to fund the remainder of our 2015 capital expenditures with cash flows from operations and cash on hand.

Critical Accounting Policies

Reserve Estimates

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

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Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization.

Full Cost Method of Accounting

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

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

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

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

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

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

Future Abandonment Costs

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

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Derivative Instruments

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

Our hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX and OPIS Mt. Belvieu prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX or OPIS Mt. Belvieu prices at which the hedges will be settled. At June 30, 2015, our derivative instruments were designated as effective cash flow hedges.

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

Results of Operations

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2015		2014		2015		2014
Production:
Oil (Bbls)	151,223		230,214		298,437		472,497
Gas (Mcf)	7,167,270		7,695,979		15,082,774		14,880,109
Ngl (Mcfe)	1,584,284		1,658,276		3,160,826		2,789,558
Total Production (Mcfe)	9,658,892		10,735,539		20,034,222		20,504,649
Sales:
Total oil sales	$	8,587,332	$	23,468,058	$	15,540,233	$	47,608,714
Total gas sales	19,927,230		28,802,856		41,577,325		58,360,191
Total ngl sales	4,035,571		8,310,268		8,883,616		14,578,674
Total oil, gas, and ngl sales	$	32,550,133	$	60,581,182	$	66,001,174	$	120,547,579
Average sales prices:
Oil (per Bbl)	$	56.79	$	101.94	$	52.07	$	100.76
Gas (per Mcf)	2.78		3.74		2.76		3.92
Ngl (per Mcfe)	2.55		5.01		2.81		5.23
Per Mcfe	3.37		5.64		3.29		5.88

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $4,181,000 and ($2,170,000), oil hedges of ($288,000) and ($672,000) and Ngl hedges of $136,000 and zero for the three months endedJune 30, 2015 and 2014, respectively. The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $6,505,000 and ($5,139,000), oil hedges of ($261,000) and ($1,106,000) and Ngl hedges of $157,000 and zero for the six months endedJune 30, 2015 and 2014, respectively.

Net income (loss) available to common stockholders totaled ($61,083,000) and $9,592,000 for the quarters ended June 30, 2015 and 2014, respectively, while net income (loss) available to common stockholders totaled ($183,323,000) and $19,635,000 for the six months ended June 30, 2015 and 2014, respectively. The primary fluctuations were as follows:

Production Total production decreased10% and 2% during the three and six month periods ended June 30, 2015, respectively, as compared to the 2014 periods. The decrease in total production was primarily the result of normal production declines at our Gulf Coast fields and the divestment of a majority of our Oklahoma assets on June 4, 2015. Partially offsetting these decreases

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was the successful drilling program in our Carthage field. Due to the current low commodity price environment, our capital expenditures budget for 2015 is significantly reduced as compared to 2014. As a result of the substantial decrease in capital spending, combined with our Oklahoma divestment, we expect our total production in 2015 to decrease as compared to 2014.

Gas production during the three month period ended June 30, 2015decreased7% from the comparable period in 2014. The decrease was primarily the result of normal production declines at our Gulf Coast fields and the divestment of a majority of our Oklahoma assets on June 4, 2015. Partially offsetting these decreases was the successful drilling program in our Carthage field. Gas production during the six month period ended June 30, 2015increased1% from the comparable period in 2014 as the result of the successful drilling program in our Carthage field, mostly offset by normal production declines at our Gulf Coast fields and the effect of our Oklahoma divestment. We expect our average daily gas production to decrease during 2015 as compared to 2014 due to our Oklahoma divestment, only partially offset by the successful drilling program in our Carthage field and the completion of our Thunder Bayou discovery.

Oil production during the three and six month periods ended June 30, 2015decreased34% and 37%, respectively, from the 2014 periods due primarily to normal production declines at our Gulf Coast fields, downtime at certain of our Gulf of Mexico properties and the divestment of our Eagle Ford properties in September 2014. As a result of normal production declines at certain of our legacy Gulf Coast fields, we expect our average daily oil production to decrease during 2015 as compared to 2014.

Ngl production during the three month period ended June 30, 2015decreased4% from the respective 2014 period due to production declines at our Gulf Coast fields and the liquids rich portion of our Oklahoma acreage position as well as our Oklahoma divestment. Offsetting these decreases was the successful drilling program in our Carthage field. Ngl production during the six month period ended June 30, 2015increased13% from the respective 2014 period due to the successful drilling program in our Carthage field. Partially offsetting this increase were decreases as a result of production declines at our Gulf Coast fields and the liquids rich portion of our Oklahoma acreage position as well as the effect of our Oklahoma divestment. We expect our average daily Ngl production to decrease during 2015 as compared to 2014 primarily due to the divestment of the liquids rich portion of our Oklahoma acreage position.

Prices Including the effects of our hedges, average gas prices per Mcf for the three and six month periods ended June 30, 2015 were $2.78 and $2.76 as compared to $3.74 and $3.92 for the respective 2014 periods. Average oil prices per Bbl for the three and six months ended June 30, 2015 were $56.79 and $52.07 as compared to $101.94 and $100.76 for the respective 2014 periods and average Ngl prices per Mcfe were $2.55 and $2.81 for the three and six months ended June 30, 2015, as compared to $5.01 and $5.23 for the respective 2014 periods. Stated on an Mcfe basis, unit prices received during the three and six months ended June 30, 2015 were 40% and 44%lower, respectively, than the prices received during the comparable 2014 periods.

Revenue Including the effects of hedges, oil and gas sales during the three months endedJune 30, 2015decreased46% to $32,550,000, as compared to oil and gas sales of $60,581,000 during the 2014 period. Including the effects of hedges, oil and gas sales during the six months endedJune 30, 2015decreased45% to $66,001,000, as compared to oil and gas sales of $120,547,000 during the 2014 period. These decreases were primarily the result of lower average realized prices for our production during 2015 as well as decreased production as discussed above.

Expenses Lease operating expenses for the three and six months ended June 30, 2015 totaled $11,191,000 and $22,093,000, respectively, as compared to $12,168,000 and $24,426,000 during the respective 2014 periods. Per unit lease operating expenses totaled $1.16 and $1.10 per Mcfe, respectively, during the three and six month periods ended June 30, 2015 as compared to $1.13 and $1.19 per Mcfe during the respective 2014 periods. The decrease in total and per unit lease operating expenses during the first six months of 2015 is primarily the result of a decrease in expensed workovers, as well as increased production from our onshore properties which typically incur lower per unit lease operating expenses. As a result of our Oklahoma divestment, we expect total lease operating expenses during 2015 to decrease as compared to 2014.

Production taxes for the three and six months ended June 30, 2015 totaled $948,000 and $1,904,000, respectively, as compared to $1,492,000 and $2,969,000, respectively, during the 2014 periods. Per unit production taxes totaled $0.10 per Mcfe during each of the three and six month periods ended June 30, 2015 as compared to $0.14 per Mcfe during the respective 2014 periods. The decrease in total production taxes was primarily due to lower commodity prices for our production during the 2015 periods as compared to the 2014 periods. Severance taxes for the majority of our properties that are subject to severance taxes are assessed on the value of oil and gas sales. As a result of the current commodity pricing environment and lower estimated production as a result of our Oklahoma divestment, we expect a decrease in our total and per unit production taxes during 2015 as compared to 2014.

General and administrative expenses during the three and six months ended June 30, 2015 totaled $6,519,000 and $11,858,000, respectively, as compared to $6,467,000 and $12,709,000 during the 2014 periods. General and administrative expenses decreased7% during the six months ended June 30, 2015 as compared to the comparable period of 2014 primarily due to lower employee related costs including share-based compensation during the 2015 periods. Included in general and administrative expenses for

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the three and six month periods ended June 30, 2015 were share-based compensation costs of $1,434,000 and $2,952,000, respectively, compared to $1,972,000 and $3,734,000, respectively, during the 2014 periods. We capitalized $2,357,000 and $4,597,000, respectively, of general and administrative costs during the three and six month periods ended June 30, 2015 compared to $3,590,000 and $7,969,000, respectively, during the 2014 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and six months ended June 30, 2015 totaled $17,996,000, or $1.86 per Mcfe, and $38,313,000, or $1.91 per Mcfe, respectively, as compared to $21,357,000, or $1.99 per Mcfe, and $41,460,000, or $2.02 per Mcfe, respectively, during the comparable 2014 periods. The decrease in the per unit DD&A rate is primarily the result of current year ceiling test write-downs. As a result of our Oklahoma divestment, which had a lower cost per unit as compared to our overall amortization base, we expect our DD&A rate to be higher for the remainder of 2015.

At March 31, 2015 and June 30, 2015, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.20 per Mcf of natural gas, $81.33 and $71.27 per barrel of oil and $3.52 and $3.35 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $108.9 million and $65.5 million during the three months ended March 31, 2015 and June 30, 2015, respectively.  See Note 7, “Ceiling Test” for further discussion of the ceiling test write-downs. We expect that the current commodity price environment will likely result in additional ceiling test write-downs during 2015.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $8,596,000 and $16,470,000 during the three and six months ended June 30, 2015, respectively, as compared to $7,380,000 and $15,016,000, respectively, during the 2014 periods. During the three and six month periods ended June 30, 2015, our capitalized interest totaled $1,379,000 and $3,376,000, respectively, as compared to $2,456,000 and $4,623,000, respectively, during the 2014 periods. The increase in interest expense was the result of lower capitalized interest on our unevaluated properties during 2015 as compared to 2014.

Income tax expense during the three and six months ended June 30, 2015 was $2,000,000 and $1,073,000, respectively, as compared to zero during the 2014 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.

Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, we recognized a gain on the sale of $21.5 million. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values. There was no gain or loss on the sale of oil and gas properties recorded in the comparable 2014 periods.

As a result of ceiling test write-downs, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $101,180,000 as of June 30, 2015.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities principally through cash flow from operations, bank borrowings, other credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At June 30, 2015 we had working capital of approximately $80.1 million as compared to a working capital deficit of approximately $80.2 million as of December 31, 2014. The improvement in our working capital is the result of proceeds received from our Oklahoma divestment, partially offset by the full repayment of our bank credit facility. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage our working capital and liquidity position. In response to the impact that the decline in commodity prices has had, and is expected to continue to have, on our cash flow, our 2015 capital expenditure budget of between $60 million and $70 million is significantly reduced as compared to 2014. During the six months ended June 30, 2015, we funded our capital expenditures with cash flow from operations, cash on hand and bank borrowings. As of June 30, 2015, we had $141 million of cash on hand and had no borrowings outstanding under our $70 million bank credit facility. We are presently evaluating various deleveraging and refinancing options with respect to our 10% Senior Notes due 2017, as well as evaluating plans to resume drilling activity in the Cotton Valley play in the fourth quarter of 2015. We plan to fund the remainder of our 2015 capital expenditures with cash flows from operations and cash on hand.

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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 $102.7 million during the six months ended June 30, 2014 to $5.6 million during the 2015 period. The decrease in operating cash flow during 2015 as compared to 2014 is primarily attributable to decreases in oil and gas revenues as well as the timing of payment of payables based on operational activity.

Source of Capital: Divestitures

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

In June 2015, we sold a majority of our interests in the Woodford and Mississippian Lime fields for $280 million, subject to customary post-closing purchase price adjustments, effective January 1, 2015. Net proceeds from the sale were used to repay all borrowings outstanding under our bank credit facility and increase our cash on hand. We are evaluating deleveraging and refinancing options with respect to our 10% Senior Notes due 2017.

Source of Capital: Debt

On August 19, 2010, we issued $150 million in principal amount of our 10% Senior Notes due 2017 (the “Existing Notes”). On July 3, 2013, we issued an additional $200 million in principal amount of our 10% Senior Notes due 2017 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The net proceeds from the offering of the New Notes were used to finance the $188.8 million aggregate cash purchase price of the acquisition of certain shallow water Gulf of Mexico shelf oil and gas properties, which also closed on July 3, 2013.

The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on March 1 and September 1. At June 30, 2015, $11.7 million had been accrued in connection with the September 1, 2015 interest payment and we were was in compliance with all of the covenants contained in the Notes. Pursuant to the asset sale covenant of the Notes, if we do not use certain of the proceeds of the Woodford and Mississippian Lime divestiture to repay senior indebtedness or to acquire additional assets or make capital expenditures in the oil and gas business within one year of the divestiture, we will be required to use such proceeds to make an offer to the holders of the Notes to repurchase the Notes at a purchase price of 100% of their principal amount, without premium, plus accrued but unpaid interest.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of our 10% Senior Notes due 2017 remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or with permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of June 30, 2015 we had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. In connection with the most recent redetermination related to the Sold Assets, the borrowing base was reduced to $70 million (subject to the aggregate commitments of the lenders then in effect) effective June 4, 2015. The aggregate commitments of the lenders is currently $70 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next scheduled borrowing

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base redetermination, which was scheduled to occur by September 30, 2015, has been waived and additional interim borrowing base redeterminations have been scheduled to occur by September 1, 2015 and December 1, 2015. 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 0.75% to 1.75% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.75% to 2.75% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%.  For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by 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 4.0 to 1.0 as of the last day of the fiscal quarters ending June 30, 2015 through December 31, 2016 and 3.5 to 1.0 as of the last day of any fiscal quarter ending thereafter, in each case determined on a rolling four quarter basis, and to provide that the amount of total debt for the four consecutive fiscal quarter periods ending June 30, 2015, September 30, 2015 and December 31, 2015 shall be reduced by the amount of unencumbered and unrestricted net cash proceeds received by the Company from the Sold Assets (such reduction amount not to exceed $130,000,000 for so long as the Company has not redeemed, in whole or in part, its 10% Senior Notes due 2017), and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits us to repurchase up to $10 million of the our 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, 2015, we were in compliance with all such covenants contained in the Credit Agreement.

Source of Capital: Issuance of Securities

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

Use of Capital: Exploration and Development

Our 2015 capital expenditure budget, which includes capitalized interest and general and administrative costs, is expected to range between $60 million and $70 million, of which $50.7 million was incurred during the first six months of 2015. 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, 2015, we funded our capital expenditures with cash flow from operations, cash on hand and bank borrowings. We do not believe our capital expenditures during the remainder of 2015 will exceed our cash flow from operations and cash on hand.

Use of Capital: Acquisitions

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

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

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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 the volatility of oil and natural gas prices and significantly depressed oil prices since the end of 2014, our estimate of the sufficiency of our existing capital sources, including availability under our senior secured bank credit facility and the result of any borrowing base redetermination, our ability to raise additional capital to fund cash requirements for future operations, the effects of a financial downturn or negative credit market conditions on our liquidity, business and financial condition, the declines in the values of our properties that have resulted in and may in the future result in additional ceiling test write-downs, our ability to replace reserves and sustain production, our ability to find oil and natural gas reserves that are economically recoverable, the uncertainties involved in prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, our ability to realize the anticipated benefits from our joint ventures or divestitures, the timing of development expenditures and drilling of wells, hurricanes, tropical storms and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracking operations 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.

Commodity Price Risk

Our revenues are derived from the sale of our crude oil, natural gas and natural gas liquids production. Based on projected sales volumes for the remainder of 2015, a 10% change in the prices we receive for our crude oil, natural gas and natural gas liquids production would have an approximate $1.2 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, 2015, we received$4.0 million and $6.4 million, respectively, from the counterparties to our derivative instruments in connection with net hedge settlements.

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

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

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As of June 30, 2015, we had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July 2015 - December 2015	Swap	40,000 Mmbtu	$3.62
July 2015 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2015 - September 2015	Swap	5,000 Mmbtu	$2.89
Crude Oil:
July 2015 - December 2015	Swap (LLS)	500 Bbls	$56.68
Propane:
July 2015 - December 2015	Swap	250 Bbls	$25.62

LLS - Louisiana Light Sweet

After executing the above transactions, the Company has approximately 9.7 Bcf of gas volumes at an average price of $3.51 per Mcf, 92,000 barrels of oil volumes at an average price of $56.68 per barrel, and 46,000 barrels of propane volumes at an average price of $25.62 per barrel hedged for the remainder 2015. Additionally, the Company has approximately 1.8 Bcf of gas volumes at $3.22 per Mcf hedged for the first half of 2016. For further discussion of our commodity derivative instruments, please see Item 1, Note 7 "Derivative Insruments" in this Form 10-Q.

Interest Rate Risk

Debt outstanding under our bank credit facility is subject to a floating interest rate. As of June 30, 2015, we had no borrowings outstanding under our credit facility.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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.

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Item 1A. RISK FACTORS

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

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Historically, the markets for oil and natural gas have been volatile and oil prices have been significantly depressed since the end of 2014. For example, for the five years ended June 30, 2015, the NYMEX-WTI oil price ranged from a high of $113.39 per Bbl to a low of $43.39 per Bbl, while the NYMEX-Henry Hub natural gas price ranged from a high of $8.15 per MMBtu to a low of $1.82 per MMBtu. These markets will likely continue to be volatile in the future. The prices we will receive for our production, and the levels of our production, will depend on numerous factors beyond our control.

These factors include:

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

• the condition of the United States and worldwide economies;

• market uncertainty;

• the level of consumer product demand;

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

• the actions of the Organization of Petroleum Exporting Countries;

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

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

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

• the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2015 to decline compared to our estimated proved reserves at December 31, 2014. 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.

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

As of June 30, 2015, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $209.0 million. Based upon the current commitment level of our bank group, we have $70 million of additional availability under our bank credit facility, subject, however, to limitations on incurrence of indebtedness under the indenture governing our 10% senior notes due 2017, which we refer to as our 10% notes. In addition, we may also incur additional indebtedness in the future. Our high level of debt could have important consequences for you, including the following:

• it may be more difficult for us to satisfy our obligations with respect to our outstanding indebtedness, including our 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;

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• if we do not use certain of the proceeds of the Woodford and Mississippian Lime divestiture to repay senior indebtedness or to acquire additional assets or make capital expenditures in the oil and gas business within one year of the divestiture, we will be required to use such proceeds to make an offer to the holders of the Notes to repurchase the Notes at a purchase price of 100% of their principal amount, without premium, plus accrued but unpaid interest, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

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

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

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

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

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

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

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

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

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

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unevaluated properties periodically to determine whether impairment has occurred. The risk that we will be required to recognize further write-downs of the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unevaluated property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized ceiling test write-downs of approximately $108.9 million and $65.5 million during the three months ended March 31, 2015 and June 30, 2015, respectively. We expect that the current commodity price environment will likely result in additional ceiling test write-downs during 2015.

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

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The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended June 30, 2015.

	Total Number of Shares Purchased (1)	Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program	Maximum Number (or Approximate Dollar Value) of Shares that May be Purchased Under the Plans or Programs
April 1 - April 30, 2015	12,848	$	2.70	—	—
May 1 - May 31, 2015	—	—		—	—
June 1 - June 30, 2015	4,598	$	2.16	—	—
Total	17,446	$	2.56	—	—

 ________________________

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

We have not paid dividends on our common stock, in cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. We are currently restricted from paying dividends on our common stock by our bank credit facility, the indenture governing the 10% senior notes and, in some circumstances, by the terms of our Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

Item 3. DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4. MINE SAFETY DISCLOSURES

NONE.

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

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2.1*# Purchase and Sale Agreement dated as of June 4, 2015, by and between PetroQuest Energy, L.L.C. and WSGP Gas Producing, LLC.

10.1 Eleventh Amendment to Credit Agreement dated as of June 4, 2015, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank, Bank of America, N.A. and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on June 5, 2015).

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 the Purchase and Sale Agreement to the SEC upon request.

# Confidential treatment has been requested for portions of this exhibit. Omissions are designated with brackets containing asterisks. As part of our confidential treatment request, a complete version of this exhibit has been filed separately with the SEC.

26

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 5, 2015	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief Financial Officer (Authorized Officer and Principal Financial and Accounting Officer)

27

EX-2.1

Execution Version

CONFIDENTIAL INFORMATION, MARKED BY BRACKETS AND ASTERISKS ([***]), IN THIS EXHIBIT HAS BEEN OMITTED AND FILED SEPARATELY WITH THE SECURITIES AND EXCHANGE COMMISSION. CONFIDENTIAL TREATMENT HAS BEEN REQUESTED WITH RESPECT TO THIS OMITTED INFORMATION.

PURCHASE AND SALE AGREEMENT

BETWEEN

PETROQUEST ENERGY, L.L.C.

AS SELLER

AND

WSGP GAS PRODUCING, LLC

AS BUYER

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TABLE OF CONTENTS

	Page
ARTICLE 1 DEFINITIONS	1
1.1Definitions; References and Construction	1
ARTICLE 2 SALE OF ASSETS/PURCHASE PRICE	12
2.1Purchase and Sale of Assets	12
2.2Purchase Price	15
2.3Purchase Price Adjustments	15
2.4Preliminary Settlement Statement	16
2.5Final Settlement Statement	16
2.6Allocated Values	17
2.7Suspense Funds	17
2.8Assumed Liabilities	17
ARTICLE 3 [INTENTIONALLY OMITTED]	18
ARTICLE 4 ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES	18
4.1Opportunity for Review	18
4.2Seller’s Indemnity Obligation	18
4.3Buyer’s Indemnity Obligation	19
4.4Threshold, Aggregate Threshold, Cap	19
4.5Tax Treatment	19
4.6Notice of Claims	20
4.7Defense of Non-Party Claims	20
4.8Investigation and Knowledge	21
4.9Waiver of Certain Damages	21
4.10Extent of Indemnification	21
4.11Survival	21
4.12Environmental Liabilities	21
ARTICLE 5 DISCLAIMERS	22
ARTICLE 6 SELLER’S REPRESENTATIONS AND WARRANTIES	24
6.1Organization and Good Standing	24
6.2Authority; Authorization of Agreement	24
6.3No Violations	24
6.4Liability for Brokers’ Fees	25
6.5Legal Proceedings	25
6.6Bankruptcy	25
6.7Taxes	25
6.8Material Contracts	25
6.9[***]	26
6.10Preferential Rights	26
6.11Consents	26
6.12[***]	27
6.13Current Commitments	27

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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6.14[***]	27
6.15Production Imbalances	27
6.16[***]	27
6.17[***]	27
6.18[***]	28
6.19Liens	28
6.20Bankruptcy	28
6.21[***]	28
6.22[***]	28
6.23[***]	28
6.24[***]	28
ARTICLE 7 BUYER’S REPRESENTATIONS AND WARRANTIES	29
7.1Organization and Good Standing	29
7.2Authority; Authorization of Agreement	29
7.3No Violations	29
7.4Liability for Brokers’ Fees	29
7.5Claims, Disputes and Litigation	30
7.6Bankruptcy	30
7.7Financing; Resources and Other Capabilities	30
7.8Independent Evaluation	30
7.9Accredited Investor	30
ARTICLE 8 COVENANTS	30
8.1Release of Liens	30
8.2Consents	30
8.3Approvals of Governmental Authorities	31
8.4Efforts	32
8.5Governmental Bonds	33
8.6Records in Seller’s Possession	33
8.7Preferential Rights	34
ARTICLE 9 [INTENTIONALLY OMITTED]	34
ARTICLE 10 THE CLOSING	34
10.1Closing	34
10.2Obligations of Seller at Closing	34
10.3Obligations of Buyer at Closing	35
10.4Option Rights	35
10.5Employees	36
ARTICLE 11 [INTENTIONALLY OMITTED]	36
ARTICLE 12 TAXES	36
12.1Like Kind Exchange	36
12.2Cooperation on Tax Matters	36
12.3Property and Excise Taxes	37
12.4Severance Taxes	37
12.5Transfer Taxes	37

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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ARTICLE 13 MISCELLANEOUS	38
13.1Notices	38
13.2Transaction and Filing Costs	39
13.3    Amendments and Severability	39
13.4Successors and Assigns	39
13.5Headings	39
13.6Governing Law; Jurisdiction; Waiver of Trial by Jury	39
13.7No Partnership Created	40
13.8Public Announcements	40
13.9No Third Party Beneficiaries	40
13.10Waiver; Rights Cumulative	40
13.11Construction	41
13.12Conspicuousness of Provisions	41
13.13Execution in Counterparts	41
13.14Entire Agreement	41

EXHIBITS AND SCHEDULES

EXHIBIT A-1        Leases

EXHIBIT A-2        Wells

EXHIBIT A-3        Pooling Orders

EXHIBIT A-4        Marketing Agreements

EXHIBIT A-5        Salt Water Disposal Assets

EXHIBIT B        Excluded Assets

EXHIBIT C        Certificate of Non-Foreign Status

EXHIBIT D        Form of Assignment

EXHIBIT E        Contract Operating Services Agreement

SCHEDULE 2.4    Preliminary Settlement Statement

SCHEDULE 2.6    Purchase Price Allocation

SCHEDULE 6.3    Consents or Approvals

SCHEDULE 6.5    Legal Proceedings

SCHEDULE 6.7    Tax Matters

SCHEDULE 6.8    Material Contracts

SCHEDULE 6.9    Violation of Laws

SCHEDULE 6.10    Preferential Purchase Rights

SCHEDULE 6.12    Contested Royalties

SCHEDULE 6.13    Current Commitments

SCHEDULE 6.14    Environmental

SCHEDULE 6.15    Imbalances

SCHEDULE 6.16    Lease Termination Notices

SCHEDULE 6.18    Well Issues

SCHEDULE 8.1    Liens

SCHEDULE 8.5    Bonds

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PURCHASE AND SALE AGREEMENT

This Purchase and Sale Agreement (together with the Exhibits and Schedules made a part hereof, this “Agreement”), dated the 4th day of June, 2015 (the “Execution Date”), is made by and between PetroQuest Energy, L.L.C., a Louisiana limited liability company (“Seller”), and WSGP Gas Producing, LLC, a Delaware limited liability company (“Buyer”). Seller and Buyer are sometimes hereinafter referred to individually as a “Party” and collectively as the “Parties”:

WHEREAS, Seller desires to sell and Buyer desires to purchase the oil and gas leases, wells, royalty interests, operating rights and other properties, interests, assets and rights comprising the Assets;

NOW, THEREFORE, for a good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties agree as follows:

Article 1DEFINITIONS

1.1Definitions; References and Construction. In this Agreement, capitalized terms have the meanings provided in this Article 1, unless defined elsewhere in this Agreement. All defined terms include both the singular and the plural of such terms. All references to Sections refer to Sections in this Agreement, and all references to Exhibits or Schedules refer to Exhibits or Schedules made a part of this Agreement. When the term “herein” is used in this Agreement, reference is made to the entire Agreement and not to any particular Section or subparagraph of a Section. The word “including” shall mean including without limitation. The words “shall” and “will” are interchangeably used throughout this Agreement and shall accordingly be given the same meaning, regardless of which word is used.

“1031 Exchange” has the meaning set forth in Section 12.1.

“Accounting Referee” means PricewaterhouseCoopers, or similar nationally recognized firm.

“Adjusted Purchase Price” has the meaning set forth in Section 2.2(a).

“Adjustments” means the adjustments to the Base Purchase Price pursuant to Section 2.3.

“AFEs” has the meaning set forth in Section 6.13.

“Affiliate” means any Person that, directly or indirectly, through one or more entities, controls or is controlled by or is under common control with the Person specified. For the purpose of the immediately preceding sentence, the term “control” means the power to direct or cause the direction of the management and policies of such Person, whether through the ownership of voting securities or by contract or agency or otherwise.

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“Affiliate Assignment” means an assignment substantially in the form attached hereto as Exhibit D, assigning those Assets set forth on Exhibit A-5 to Buyer’s Affiliate USG Surface Facilities I, LLC.

“Aggregate Indemnity Deductible” means [***].

“Agreement” has the meaning set forth in the introductory paragraph

“Allocated Values” has the meaning set forth in Section 2.6(a).

“Assets” has the meaning set forth in Section 2.1.

“Assignment” means a document in the form of Exhibit D.

“Assumed Liabilities” has the meaning set forth in Section 2.8.

“Barrel” or “Bbl” means 42 U.S. gallons.

“Base Purchase Price” has the meaning set forth in Section 2.2(a).

“BLM” means the Bureau of Land Management, Department of the Interior, United States of America.

“Business Day” means a Day other than Saturday, Sunday or any other Day when federally chartered banks in the United States are required to be closed.

“Buyer” has the meaning set forth in the introductory paragraph.

“Buyer Group” means Buyer and its Affiliates together with its and their members, partners, officers, directors, managers, agents, representatives, consultants and employees.

“Certificate of Non-Foreign Status” means a certificate in the form of Exhibit C.

“Claims” means any and all written claims, demands, suits, causes of action, losses, damages, liabilities, fines, penalties, fees, expenses and costs (including reasonable attorneys’ fees and costs of litigation).

“Close” or “Closing” means the consummation of the sale of the Assets from Seller to Buyer, including execution and delivery of all documents and other legal consideration as provided for in this Agreement pursuant to Article 10.

“Closing Amount” has the meaning set forth in Section 2.2(a).

“Closing Date” has the meaning set forth in Section 10.1.

“Code” means the Internal Revenue Code of 1986, as amended.

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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“Contracts” has the meaning set forth in Section 2.1(c).

“Contract Operating Services Agreement” means that certain Contract Operating Services Agreement in the form of Exhibit E, to be executed by the Partiescontemporaneously with the execution of this Agreement.

“Cooperating Party” has the meaning set forth in Section 12.1

“Customary Post-Closing Consents” means consents and approvals from Governmental Authorities that are customarily obtained after Closing in connection with a transaction similar to the one contemplated by this Agreement.

“Day” means a calendar day consisting of 24 hours from midnight to midnight.

“DDA Properties” means all of Seller’s right, title and interest in and to the “Development Assets” as such term is defined in that certain Drilling and Development Agreement dated June 18, 2014, by and between Seller and USG Properties Woodford I, LLC (including any leases identified as “DDA Excluded Leases” set forth on Exhibit B), together with Seller’s right, title and interest in any royalties, overriding royalties, net profits interests, carried interests, or mineral fee interests to the extent attributable to the “Development Assets,” and any Hydrocarbon wells drilled pursuant to such Drilling and Development Agreement Agreement and any other real or personal property associated with the ownership and/or operation of any of the foregoing.

“Deferred Purchase Price” has the meaning set forth in Section 2.2(b).

“Deferred Period” has the meaning set forth in Section 2.2(b).

“Dollars” means United States Dollars.

“E&P Business” means the business and operations conducted by Seller in its ordinary course of business to the extent pertaining to the Assets.

“Effective Time” means January 1, 2015, at 12:01 a.m. local time where the Assets are located.

“Environmental Condition” shall mean (a) any condition existing on or prior to the Closing Date with respect to the air, soil, subsurface, surface waters, ground waters and/or sediments that causes any Asset to not be in material compliance with any Environmental Laws, or (b) any environmental release of Hazardous Substance which could reasonably be expected to result in any material liability to Seller (including with respect to any remedial or corrective action) arising under existing Environmental Laws.

“Environmental Laws” means any and all Laws relating to the prevention of pollution, the preservation and restoration of environmental quality, the protection of human health, wildlife or environmentally sensitive areas, the remediation of contamination, the generation, handling, treatment, storage, transportation, disposal or release into the environment of waste materials, or the regulation of or exposure to hazardous, toxic or other substances alleged to be

harmful. Environmental Laws include all applicable judicial and administrative Orders, consent decrees or directives issued by a Governmental Authority pursuant to theforegoing. Unless expressly included in and required by applicable requirements of statutes, regulations, judicial and administrative Orders, consent decrees or directives issued by a Governmental Authority included in Environmental Laws, Environmental Laws do not include good or desirable operating practices or standards that may be employed or adopted by other oil or gas well or pipeline operators or recommended but not required by a Governmental Authority. Furthermore, Environmental Laws do not include the Occupational Safety and Health Act or any other Law governing worker safety or workplace conditions.

“Environmental Liabilities” means any and all liabilities, responsibilities, claims, suits, losses, costs (including remediation, removal, response, abatement, clean-up, investigative, and/or monitoring costs and any other related costs and expenses), damages, natural resource damages, settlements, consulting fees, expenses, assessments, liens, penalties, fines, orphan share, prejudgment and post-judgment interest, court costs, and reasonable attorney fees incurred or imposed (a) pursuant to any order, notice of responsibility, directive (including requirements embodied in Environmental Laws), injunction, judgment or similar ruling or act (including settlements) by any Governmental Authority to the extent arising out of any violation of, or remedial obligation under, any Environmental Law that is attributable to (or for which any liability or responsibility is incurred or imposed as a result of) the ownership or operation of the Assets prior to, at or after the Closing Date, or (b) pursuant to any claim or cause of action by a Governmental Authority or other Person for personal injury, death, property damage, damage to natural resources, remediation or response costs, or similar costs or expenses to the extent arising out of a release of Hazardous Materials or any violation of, or any remediation obligation under, any Environmental Laws that is attributable to (or for which any liability or responsibility is incurred or imposed as a result of) the ownership or operation of the Assets prior to, at or after the Closing Date, or (c) as a result of Environmental Conditions; provided, however, that Environmental Liabilities shall not include any Claims for which Seller is required to indemnify Buyer pursuant to Article 4.

“Equipment” has the meaning set forth in Section 2.1(f).

“Exchange Party” has the meaning set forth in Section 12.1.

“Excise Taxes” has the meaning set forth in Section 12.3.

“Excluded Assets” means (a) those assets, interests, rights and contracts described on Exhibit B; (b) any Assets subject to a Hard Consent which are excluded from the Assets pursuant to Section 8.2; (c) all trade credits, all accounts, receivables and all other proceeds, income or revenues attributable to the Assets with respect to any period of time prior to the Effective Time; (d) all claims and causes of action of Seller arising under or with respect to any Contracts that are attributable to periods of time prior to the Effective Time (including claims for adjustments or refunds); (e) all rights and interests relating to the Assets, (i) under any existing policy or agreement of insurance, (ii) under any bond or (iii) to any insurance or condemnation proceeds or awards arising, in each case, from acts, omissions or events, or damage to or destruction of property; (f) all Hydrocarbons produced and sold from the Assets with respect to all periods prior to the Effective

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Time; (g) any Tax refunds or Tax carry-forwards amounts attributable to the Assets prior to the Effective Time or to Seller’s business generally; (h) all personal computers, network equipment and associated peripherals and telephone equipment (including cellular telephones); (i) vehicles; (j) all of Seller’s proprietary computer software (including the CC 9000 security software), patents, trade secrets, copyrights, names, trademarks, logos and other intellectual property; (k) to the extent not materially interfering with Buyer’s ownership and operation of the Assets, concurrent rights and interests with Buyer in, to and under the Contracts, Surface Contracts and Permits, to the extent, and only to the extent, necessary to own, operate and/or develop the Retained Depths and/or any of the other Excluded Assets.

“Excluded Records” has the meaning set forth in Section 2.1(h).

“Excluded Working Interest” means [***].

“Execution Date” has the meaning set forth in the introductory paragraph.

“Final Settlement Statement” has the meaning set forth in Section 2.5.

“Governmental Authority” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission, body or other authority exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal, including any tribal authority having jurisdiction.

“Hard Consent” has the meaning set forth in Section 8.2(b).

“Hazardous Materials” shall mean any substance or material that is, or if released or disposed of would be, designated, classified, characterized or regulated as a “hazardous substance”, “hazardous waste”, “hazardous material”, “toxic substance”, “pollutant” or “contaminant” under Environmental Laws.

“Hedges” means any swap, collar, floor, cap, option or other Contract that is intended to eliminate or reduce the risk of fluctuations in the price of Hydrocarbons.

“Hydrocarbons” means oil, gas, natural gas liquids, casinghead gas, coal bed methane, condensate and other gaseous and liquid hydrocarbons or any combination thereof.

“Imbalance” means over-production or under-production or over-deliveries or under-deliveries on account of (a) any imbalance at the wellhead between the amount of Hydrocarbons produced from a Well constituting part of the Assets and allocable to the interests of Seller, and the shares of production from the relevant Well that are actually taken by or delivered to or for the account of Seller and (b) any marketing imbalance between the quantity of Hydrocarbons constituting part of the Assets and required to be delivered by or to Seller under any Contracts relating to the purchase and sale, gathering, transportation, storage, treating, processing, or

4

[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

HOU:0103160/00024:1726362v2

marketing of Hydrocarbons and the quantity of Hydrocarbons actually delivered by or to Seller pursuant to the applicable Contracts.

“Indemnity Claim” has the meaning set forth in Section 4.6.

“Indemnity Claim Notice” has the meaning set forth in Section 4.6.

“Indemnity Obligations” mean the obligations of a Party to RELEASE, DEFEND, INDEMNIFY and HOLD HARMLESS the other Party from and against specified Claims as provided in this Agreement.

“Individual Indemnity Threshold” has the meaning set forth in Section 4.4(b).

“Knowledge” means (a) with respect to Seller, the actual knowledge of the following individuals [***] and (b) with respect to Buyer, the actual knowledge of the following individuals [***].

“Laws” means any and all laws, statutes, ordinances, permits, decrees, writs, injunctions, Orders, codes, judgments, principles of common law, rules or regulations that are promulgated, issued or enacted by a Governmental Authority having jurisdiction.

“Leases” has the meaning set forth in Section 2.1(a).

“Legal Proceedings” means any and all proceedings, suits and causes of action by or before any Governmental Authority and all arbitration proceedings.

“Lowest Cost Remediation Amount” means, with respect to an Environmental Condition, the lowest cost of response and/or remediation required or permitted under Environmental Law that completely addresses and resolves (for current use in the same manner as currently used) the identified Environmental Condition in its entirety.

“Material Adverse Effect” means a change, event, circumstance, development, state of facts or condition that (a) results, or would reasonably be expected to result, in a material adverse effect on the Assets (as currently owned and operated) or the results of operations of Seller with respect to the Assets, individually, or taken as a whole or (b) materially impairs, prevents, delays or makes impossible the consummation of the transactions contemplated by this Agreement; provided, however, that a Material Adverse Effect shall not include any material adverse effects resulting from: (i) entering into this Agreement or the announcement of the transactions contemplated by this Agreement; (ii) changes in general market, economic, financial or political conditions (including changes in commodity prices (including Hydrocarbons), fuel supply or transportation markets, interest or rates) in the area in which the Assets are located, the United States or worldwide; (iii) conditions (or changes in such conditions) generally affecting the oil and gas and/or gathering, processing or transportation industry whether as a whole or specifically in any area or areas where the Assets are located; (iv) acts of God, including storms or meteorological events; (v) orders, actions or failures to act of Governmental Authorities; (vi) civil unrest or similar

5

[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

HOU:0103160/00024:1726362v2

disorder, the outbreak of hostilities, terrorist acts or war; (vii) any actions taken or omitted to be taken (A) by or at the written request or with the prior written consent of Buyer or (B) as expressly permitted or prescribed hereunder; (viii) a change in Laws or in GAAP interpretation from and after the Execution Date; (ix) reclassification or recalculation of reserves in the ordinary course of business; and (x) natural declines in well performance.

“Material Contracts” has the meaning set forth in Section 6.8(a).

“MCF” means thousand cubic feet.

“Net Revenue Interest” means the interest (expressed as a percentage or decimal fraction) as set forth on Schedule 2.6, in and to Hydrocarbons produced from or allocated to a Well or Well Location.

“Non-Party” means any Person other than the Parties or their respective Affiliates.

“Oil and Gas Properties” has the meaning set forth in Section 2.1(b).

“Operating Expenses” shall mean Seller’s obligation for any and all costs and expenses (including lease operating expenses, drilling and completion costs, plugging and abandonment costs, seismic costs, workover costs, capital expenditures, costs of performing title due diligence (including the preparation of title opinions and mineral ownership reports), permitting costs, costs related to obtaining rights-of-ways or easements for operations, joint interest billings, overhead charges, Taxes and all insurance premiums or any other costs of insurance attributable to Seller’s and/or its Affiliates’ insurance and to coverage periods from and after the Effective Time but excluding in all cases, all costs and expenses of bonds, letters of credit or other surety instruments) which relate to the Assets and are incurred by Seller in connection with the ownership, operation, development or maintenance of the Assets in the ordinary course of business, but excluding liabilities, losses, costs, and expenses attributable to:

(i)claims, investigations, administrative proceedings, arbitration or litigation directly or indirectly arising out of or resulting from actual or claimed personal injury or other torts, illness or death; property damage (other than damage to structures, fences, irrigation systems and other fixtures, crops, livestock, and other personal property in the ordinary course of business);

(ii)violation of any Law (or private cause or right of action under any Law);

(iii)environmental damage or liabilities, including obligations to remediate any contamination of groundwater, surface water, soil, sediments, or Equipment under applicable Environmental Law;

(iv)title and environmental claims (including claims that Leases have terminated);

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(v)claims of improper calculation or payment of royalties (including overriding royalties and other burdens on production) related to deduction of post-production costs or use of posted or index prices or prices paid by Affiliates;

(vi)gas balancing and other production balancing obligations for which there is an adjustment to the Base Purchase Price hereunder;

(vii)overhead, except to the extent due and owing pursuant to a joint operating agreement associated with the Assets;

(viii)any claims for indemnification, contribution, or reimbursement from any third Person with respect to liabilities, losses, costs, and expenses of the type described in preceding clauses (i) through (vii), whether such claims are made pursuant to contract or otherwise.

“Operative Documents” means those documents referenced in Sections 10.2 and 10.3.

“Option Leases” has the meaning set forth in Section 10.4(a).

“Option Period” has the meaning set forth in Section 10.4(a).

“Option Properties” has the meaning set forth in Section 10.4(a).

“Order” means any order, judgment, injunction, non-appealable final order, ruling or decree of any court or other Governmental Authority.

“Party” or “Parties” has the meaning set forth in the introductory paragraph.

“Permits” has the meaning set forth in Section 2.1(e).

“Permitted Encumbrances” means with respect to any Asset any and all of the following:

(a)consents to assignment and similar contractual provisions affecting such Asset including Customary Post-Closing Consents to the extent such consents are addressed pursuant to Section 8.2;

(b)preferential rights to purchase and similar contractual provisions affecting such Asset insofar as the same have been waived or complied with in accordance with the terms thereof;

(c)required notices to and filings with any Governmental Authority in connection with the consummation of the transaction contemplated by this Agreement;

(d)rights reserved to or vested in a Governmental Authority having jurisdiction to control or regulate such Asset in any manner whatsoever and all Laws of such Governmental

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Authorities, provided that the foregoing does not reduce the Net Revenue Interest or increase the Working Interest of the associated Well(s) and/or Well Locations;

(e)easements, rights-of-way, permits, licenses, servitudes, surface leases, sub-surface leases, equipment, pipelines, utility lines and structures on, over or through such Asset that do not (i) materially detract from the value of or materially affect or impair the ownership, use or operation of such Asset or (ii) reduce the Net Revenue Interest or increase the Working Interest of the associated Well(s) and/or Well Locations;

(f)liens for Taxes or assessments not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller;

(g)liens of operators relating to obligations not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller;

(h)any (i) undetermined or inchoate liens or charges constituting or securing the payment of expenses that were incurred incidental to maintenance, development, production or operation of such Asset or for the purpose of developing, producing or processing Hydrocarbons therefrom or therein, and (ii) materialman’s, mechanics’, repairmen’s, employees’, contractors’ or other similar liens or charges relating to obligations not yet delinquent or, if delinquent, that are being contested in good faith in the normal course of business, the responsibility for which is retained by Seller;

(i)conventional rights of reassignment upon final intention to abandon or release an Asset;

(j)any liens or security interests created by Law or reserved in oil and gas leases for royalty, bonus or rental, or created to secure compliance with the terms of the agreements, instruments and documents or records that create or reserve such Asset;

(k)any obligations or duties affecting such Asset to any Governmental Authority with respect to any franchise, grant, license or permit of record or contained in the Records;

(l)the terms and conditions of the Leases;

(m)the Contracts set forth on Schedule 6.8;

(n)zoning and planning ordinances and municipal regulations; and

(o)the terms and conditions of this Agreement.

“Person” means an individual, group, partnership, corporation, limited liability company, trust or other entity.

“Preferential Right” has the meaning set forth in Section 6.10.

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“Preferential Right Property” has the meaning set forth in Section 8.7(a).

“Preliminary Settlement Statement” has the meaning set forth in Section 2.4.

“Prime Rate” means the rate of interest published and updated from time to time by the Wall Street Journal as the “prime” rate.

“Property Taxes” has the meaning set forth in Section 12.3.

“Purchase Price Allocation” has the meaning set forth in Section 2.6(b).

“Records” has the meaning set forth in Section 2.1(h).

“Retained Depths” means the oil, gas and/or mineral leases, covering those depths that are excluded as set forth on Exhibit B.

“Retained Liabilities” means the following obligations:

(a)any and all obligations, liabilities and Claims in any way relating to the ownership and/or operation of the Assets, excluding, in each case, Environmental Liabilities, arising during, related to or otherwise attributable to the period prior to the Effective Time;

(b)all obligations and amounts owed to any employees of Seller relating to the employment of such individuals by Seller or the termination of employment of such individuals by Seller;

(c)all obligations and liabilities owed to any employees of Seller arising under any employee benefit or welfare plan maintained by Seller;

(d)all Claims asserted by any employee of Seller for bodily injury or death prior to the Effective Time;

(e)all Claims asserted by any Non-Parties for bodily injury to or death of such Non-Parties or damage to property owned by such Non-Parties to the extent resulting or arising from, or attributable to, the use, ownership or operation of the Assets and attributable to periods prior to the Effective Time;

(f)all Hedges of Seller;

(g)the disposal or transportation of any Hazardous Material to any location not on the Assets or lands pooled or unitized therewith to the extent resulting or arising from, or attributable to, the use, ownership or operation of the Assets and attributable to periods prior to the Closing Date;

(h)the responsibility for the disposition of and the liabilities and obligations with respect to the Legal Proceedings relating to the Assets and filed prior to the Effective Time, including those described on Schedule 6.5; and

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(i)all Claims relating to any Taxes imposed on or with respect to Seller or any of its Affiliates other than Taxes allocated to Buyer pursuant to Sections 12.3, 12.4 and 12.5;

provided, however, nothing herein related to the definition of Retained Liabilities (or any obligations of Seller related thereto (including Indemnity Obligations)) shall affect or restrict Seller’s rights against Buyer under any prior agreement between Seller or its Affiliates, on the one hand, and Buyer or its Affiliates, on the other hand, (including rights off contribution, offset or indemnity).

“Seller” has the meaning set forth in the introductory paragraph.

“Seller Bonds” has the meaning set forth in Section 8.5.

“Seller Employees” has the meaning set forth in Section 10.5.

“Seller Group” means Seller and its Affiliates, together with its and their members, partners, officers, directors, managers agents, representatives, consultants and employees.

“Shallow Depth Properties” means the Retained Depths, together with Seller’s right, title and interest in any royalties, overriding royalties, net profits interests, carried interests, or mineral fee interests to the extent attributable to the Retained Depths, and any Hydrocarbon wells producing from the Retained Depths and any other real or personal property associated with the ownership and/or operation of any of the foregoing.

“Specified Representations and Warranties” means the representations and warranties of Seller set forth in Sections 6.1, 6.2, 6.3, 6.4, 6.6 and 6.12.

“Surface Contracts” has the meaning set forth in Section 2.1(d).

“Suspense Funds” means those proceeds from the sale of Hydrocarbons attributable to the Assets and payable to owners of working interests, royalties, overriding royalties and other similar interests that are held by Seller in suspense as of the Closing Date including royalty proceeds held in suspense.

“Tax” or “Taxes” means any taxes, assessments, fees and other governmental charges imposed by any Taxing Authority, including without limitation income, profits, gross receipts, net proceeds, alternative or add-on minimum, ad valorem, value added, turnover, sales, use, property, personal property (tangible and intangible), environmental, stamp, leasing, lease, user, excise, duty, franchise, capital stock, transfer, registration, license, withholding, social security (or similar), unemployment, disability, payroll, employment, fuel, excess profits, occupational, premium, windfall profit, severance, estimated, or other charge of any kind whatsoever, including any interest, penalty, or addition thereto, and including any liability for any of the foregoing items that arises by reason of transferee or successor liability.

“Tax Return” means any return, declaration, report, claim for refund, or information return or statement relating to Taxes, including any schedule or attachment thereto.

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“Taxing Authority” means, with respect to any Tax, the governmental entity or political subdivision thereof that imposes such Tax, and the agency (if any) charged with the collection of such Tax for such entity or subdivision, including any governmental or quasi-governmental entity or agency that imposes, or is charged with collecting, social security or similar charges or premiums.

“Transfer Taxes” has the meaning set forth in Section 12.5.

“Treasury” means the United States Department of the Treasury.

“Units” has the meaning set forth in Section 2.1(b).

“Wells” has the meaning set forth in Section 2.1(a).

“Well Location” means the Oil and Gas Property relating to each “PUD”, “PRB”, or “POS” listed on Schedule 2.6.

“Working Interest” means the percentage of costs and expenses associated with the exploration, drilling, development, operation and abandonment of any Well or Well Location required to be borne with respect thereto as set forth on Schedule 2.6.

ARTICLE 2SALE OF ASSETS/PURCHASE PRICE

2.1Purchase and Sale of Assets. Subject to and in accordance with the terms and conditions of this Agreement, Seller agrees to sell and assign to Buyer, and Buyer agrees to purchase and acquire from Seller, all of Seller’s right, title and interest in and to the following (such right, title and interest of Seller in and to the following (less and except the Excluded Assets and the Excluded Working Interest), collectively, the “Assets”):

(a)all oil and gas leases, oil, gas and mineral leases, mineral servitudes, subleases and other leaseholds, royalties, overriding royalties, net profits interests, carried interests, mineral fee interests, farmout rights and operating and record title rights (as such terms are commonly used by the BLM) that are described on Exhibit A-1 (in each case, subject to the depth limitations set forth on Exhibit A-1), and including all other right, title and interest of Seller in and to the lands covered by or described in the instruments described on Exhibit A-1 (subject to the depth limitations set forth on Exhibit A-1), whether or not such rights, titles and interests are listed on Exhibit A-1 (collectively, the “Leases”); and any and all Hydrocarbon, source water, CO₂, disposal or injection wells (whether producing, inactive, temporarily or permanently abandoned, shut-in or otherwise) on the Leases or Units, including the interests in the wells described on Exhibit A-2 (collectively, the “Wells”);

(b)all pooled, communitized or unitized acreage, whether voluntarily formed or established by order of the Oklahoma Corporation Commission or under communitization agreements with the Bureau of Indian Affairs, that includes all or part of any Leases or the Wells, including those formed pursuant to the pooling orders set forth on Exhibit A-3 (the “Units”), and

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all tenements, hereditaments and appurtenances belonging to the Leases, Wells and Units (together with the Leases, Wells, and Units, the “Oil and Gas Properties”);

(c)all contracts, agreements and instruments existing as of the Closing Date by which the Oil and Gas Properties are bound or subject or that relate to or are otherwise applicable with respect to the Oil and Gas Properties, including operating agreements, unitization, pooling, and communitization agreements, declarations and orders, area of mutual interest agreements, joint venture agreements, farm in and farm out agreements, exploration agreements, participation agreements, marketing agreements (including those marketing agreements set forth on Exhibit A-4), exchange agreements, transportation agreements, gathering agreements, agreements for the sale and purchase of Hydrocarbons, processing and treating agreements, including the contracts, agreements and instruments listed on Schedule 6.8, but provided the term “Contracts” does not include (i) the Leases and the Surface Contracts, (ii) any joint operating agreement to the extent relating to the Excluded Working Interest and (iii) any Pre-Pooling Letter Agreement (the foregoing, subject to such exclusions, the “Contracts”);

(d)to the extent assignable, all surface fee interests, easements, permits, licenses, servitudes, rights-of-way, surface leases and other rights to use the surface appurtenant to, and used or held for use in connection with, the Oil and Gas Properties, including those instruments set forth on Exhibit A-5 (the foregoing, the “Surface Contracts”);

(e)to the extent assignable, all permits, water rights (including water withdrawal, storage, discharge, treatment, injection and disposal rights), licenses, registrations, consents, orders, approvals, variances, exemptions, waivers, franchises, rights and other authorizations issued by any Governmental Authority that are primarily related to the use, ownership or operation of any of the Oil and Gas Property or Equipment (the “Permits”);

(f)all equipment, machinery, fixtures, facilities, gathering systems, pipelines, flow lines, tank batteries, and materials, abandoned property, junk and other tangible personal property, fixtures and improvements used or held for use in connection with the ownership or operation of the Oil and Gas Properties or the Surface Contracts, together with any movables and immovables located on the Oil and Gas Properties or the Surface Contracts (the foregoing, subject to such exclusions, the “Equipment”);

(g)all Hydrocarbons produced from or attributable to the Oil and Gas Properties after the Effective Time; all oil, condensate and scrubber liquids inventories and ethane, propane, iso-butane, nor-butane and gasoline inventories from the Oil and Gas Properties in storage as of the Effective Time (including pipeline inventories and linefill); all Imbalances as of the Effective Time, together with all proceeds of any thereof; and all make-up rights attributable to the period of time from and after the Effective Time with respect to take-or-pay arrangements;

(h)to the extent assignable, the data and records of Seller (including lease files; land files; well files; gas and oil sales contract files; gas processing files; division order files; abstracts; title opinions; land surveys; logs; maps; engineering data and reports; geological and geophysical data and files; technical evaluations and technical outputs; and other books, records,

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data, files and accounting records) to the extent relating to the Oil and Gas Properties or the other Assets, excluding:

(1)    all corporate, financial, Tax and legal data and records of Seller that relate to Seller’s business generally;

(2)    any data and records to the extent disclosure or transfer is prohibited, or subjected to payment of a fee or other consideration, by any license agreement or other agreement with a Person other than Affiliates of Seller, or by applicable Law, and for which no consent to transfer has been received or for which Buyer has not agreed in writing to pay the fee or other consideration, as applicable;

(3)    all legal records and legal files of Seller, including, but not limited to, all work product of, and attorney-client communications with, Seller’s legal counsel (other than Leases, Surface Contracts, title opinions, Contracts and Seller’s working files for any Claims included in the Assumed Liabilities);

(4)    any data and records relating to the sale of the Assets, including bids received from and records of negotiations with Non-Parties;

(5)    any data and records constituting or relating solely to the Excluded Assets;

(6)    to the extent not assignable without the payment of fees or other penalties to Persons other than Affiliates of Seller or the securing of a licensor’s consent, unless Buyer has secured such consent in writing, all seismic, geological, geochemical or geophysical data licensed by Seller and interpretations of such data; and

(7)    employee information, internal valuation data, business plans, reserve reports, business studies, and transaction proposals pertaining to the sale of the Assets and related correspondence.

(The data and records referred to in Clauses (1) through (7) shall hereinafter be referred to as the “Excluded Records” and, subject to such exclusions, the data and records described in this Section 2.1(h) shall be referred to as the “Records”);

(i)All (A) trade credits, accounts receivable, notes receivable, take-or-pay amounts receivable, and other receivables and general intangibles, attributable to the Assets with respect to periods of time from and after the Effective Time; (B) liens and security interests in favor of Seller, whether choate or inchoate, under any Law or Contract to the extent arising from, or relating to, the ownership, operation, or sale or other disposition on or after the Effective Time of any of the Assets or to the extent arising in favor of Seller as the operator or non-operator of any Oil and Gas Property; and (C) indemnity, contribution, and other such rights in favor of Seller or its Affiliates, to the extent relating to obligations or liabilities assumed by Buyer pursuant to this

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Agreement or otherwise borne or paid by Buyer or with respect to which Buyer has an obligation to indemnify Seller;

(j)All rights of Seller to audit the records of any Person and to receive refunds or payments of any nature, and all amounts of money relating thereto, whether before, on, or after the Effective Time, to the extent relating to the obligations assumed by Buyer pursuant to this Agreement or with respect to which Buyer has an obligation to indemnify Seller; and

(k)To the extent assignable, all franchises, licenses, permits, approvals, consents, certificates and other authorizations, and other rights granted by third Persons, and all certificates of convenience or necessity, immunities, privileges, grants, and other such rights that relate to, or arise from, the Assets or the ownership or operation thereof.

The Assets shall not include the Excluded Assets or the Excluded Working Interest.

2.2Purchase Price.

(a)The total purchase price, subject to adjustment in accordance with the terms of this Agreement, to be paid to Seller by Buyer for the Assets is $280,000,000 (the “Base Purchase Price”), with $14,000,000 of the Base Purchase Price (the “Deferred Purchase Price”) to be paid to Seller post-Closing in accordance with Section 2.2(b). The Base Purchase Price shall be adjusted as set forth in Section 2.3 (as so adjusted, the “Adjusted Purchase Price”). The estimate set forth on Schedule 2.4 (which shall take into account the Deferred Purchase Price as set forth in Section 2.2(b)) constitutes the Dollar amount to be paid by Buyer to Seller at Closing by wire transfer of immediately available funds to an account designated by Seller (the “Closing Amount”).

(b)During the 180 day period following the Closing Date (the “Deferred Period”), for each of the first 14 Wells spudded by Seller (or an Affiliate of Seller) as contract operator under the Contract Operating Services Agreement, Buyer shall pay Seller, within 10 Business Days of Buyer’s receipt of a written invoice from Seller following the spud date, $1,000,000 of the Deferred Purchase Price by wire transfer of immediately available funds to an account designated by Seller. If, at the end of the Deferred Period, any portion of the Deferred Purchase Price has not been paid to Seller, Buyer shall pay Seller, within 10 Business Days of Buyer’s receipt of a written invoice from Seller following the end of the Deferred Period, the remaining portion of the Deferred Purchase Price that has not been previously paid to Seller in accordance with this Section 2.2(b).

2.3Purchase Price Adjustments. The Base Purchase Price shall be adjusted, without duplication, as follows:

(a)Upward by the sum of the following:

(i)an amount equal to the value of all oil, condensate and scrubber liquids inventories and ethane, propane, iso-butane, nor-butane, and gasoline inventories from the Assets in storage as of the Effective Time, with the value to be based on $3.00 per MCF and $60.00 per Barrel, less amounts payable as royalties, overriding

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royalties and other burdens upon, measured by or payable in respect of such Hydrocarbons;

(ii)an amount equal to all Operating Expenses, paid by Seller that are attributable to the Assets from and after the Effective Time, whether paid before or after the Effective Time, including, without duplication of any other amounts set forth in this Section 2.3(a);

(iii)without duplication of any other amounts set forth in this Section 2.3(a), the amount of all Taxes, if any, allocated to Buyer pursuant to Article 12 but paid by Seller;

(iv)an amount equal to the value of Imbalances attributable to the Assets owing to Seller as of the Effective Time, with the value to be based on $3.00 per MCF and $60.00 per Barrel; and

(v)except as expressly provided otherwise herein, any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by the Parties.

(b)Downward by the sum of the following:

(i)an amount equal to all proceeds received by Seller for the sale of the Hydrocarbons produced from the Assets from and after the Effective Time less amounts actually paid by Seller as royalties, overriding royalties and other burdens measured by or payable out of such production, and less severance taxes actually paid by Seller applicable to such production, except as otherwise accounted for pursuant to Section 2.3(a)(i);

(ii)without duplication of any other amounts set forth in this Section 2.3(b), the amount of all Taxes, if any, allocated to Seller pursuant to pursuant to Article 12 but paid by Buyer;

(iii)an amount equal to the value of Imbalances attributable to the Assets owed by Seller as of the Effective Time, with the value to be based on $3.00 per MCF and $60.00 per Barrel;

(iv)the sum of the Allocated Values of the Assets subject to a Hard Consent being retained by Seller pursuant to Sections 8.2; and

(v)except as expressly provided otherwise herein, any other amount provided for elsewhere in this Agreement or otherwise agreed in writing by the Parties.

(c)To the extent applicable, the Adjustments pursuant to this Section 2.3 shall be determined in accordance with U.S. generally accepted accounting principles.

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2.4Preliminary Settlement Statement. A mutually agreed upon preliminary settlement statement (the “Preliminary Settlement Statement”) is attached hereto as Schedule 2.4 and sets forth an estimate of the Adjustments and the Adjusted Purchase Price through and including the Closing Date.

2.5Final Settlement Statement. No later than 180 Days after the Closing Date, Seller will deliver to Buyer a final settlement statement (the “Final Settlement Statement”) setting forth the actual amounts of Adjustments and the resulting Adjusted Purchase Price, together with associated back-up documentation. As soon as reasonably practicable, but in no event later than 30 Days after Buyer receives the Final Settlement Statement, Buyer may deliver to Seller a written report containing any changes that Buyer proposes to be made to such statement. If Buyer fails to timely deliver the written report to Seller containing changes Buyer proposes to be made to the Final Settlement Statement, the statement as delivered by Seller will be deemed to be correct and will be final and binding on the Parties and not subject to further audit or arbitration. As soon as reasonably practicable, but in no event later than 15 Days after Seller receives Buyer’s written report, the Parties shall meet and undertake to agree on the final adjustments to the Final Settlement Statement. If the Parties fail to agree on the final adjustments within such 15-Day period, either Party may submit the disputed items to the Accounting Referee for resolution. The Parties shall direct the Accounting Referee to resolve the disputes within 20 Days after having the relevant materials submitted for review. The decision of the Accounting Referee will be binding on and non-appealable by the Parties. The fees and expenses associated with the Accounting Referee will be borne equally by the Parties. Any amounts owed by one Party to the other as a result of the Final Settlement Statement, together with interest on such amount from (and including) the Closing Date to (and excluding) the date of payment at the Prime Rate, will be paid within five Business Days after the date when the amounts are agreed upon by the Parties or the Parties receive a decision of the Accounting Referee, and the Adjustments included in the Final Settlement Statement will be final and binding between the Parties and not subject to further audit or arbitration.

2.6Allocated Values.

(a)Schedule 2.6 sets forth the agreed allocation of the Base Purchase Price among the Assets (the “Allocated Values”).

(b)Seller and Buyer agree that for the purpose of making the requisite filings under Section 1060 of the Code and the Treasury regulations thereunder, the Base Purchase Price and any liabilities assumed by Buyer under this Agreement shall be allocated among the Assets, consistent with the Allocated Values set forth on Schedule 2.6 hereto (the “Purchase Price Allocation”). Seller and Buyer each agree to report, and to cause their respective Affiliates to report, the federal, state and local income Tax consequences of the transactions contemplated herein, and in particular to report the information required by Section 1060(b) of the Code, and to prepare Form 8594 (Asset Acquisition Statement under Section 1060) consistent with the Purchase Price Allocation as revised to take into account subsequent adjustments to the Base Purchase Price, including any adjustments pursuant to Section 2.3 or payments under Article 4 (treated as adjustments pursuant to Section 4.5). Neither Buyer nor Seller shall take any position inconsistent with such Purchase Price Allocation and neither Buyer nor Seller shall agree to any proposed

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adjustment to the Purchase Price Allocation by any Governmental Authority without first giving the other party prior written notice; provided, however, that nothing contained herein shall prevent Buyer or Seller from settling any proposed deficiency or adjustment by any Governmental Authority based upon or arising out of the Purchase Price Allocation, and neither Buyer nor Seller shall be required to litigate before any court any proposed deficiency or adjustment by any Governmental Authority challenging such Purchase Price Allocation.

2.7Suspense Funds. Seller shall retain the Suspense Funds and shall remain responsible for administering the Suspense Funds in accordance with all applicable Laws, rules and regulations and shall be liable for the payment thereof to the proper parties, and such obligations shall be deemed part of the Retained Liabilities.

2.8Assumed Liabilities. Upon Closing, Buyer assumes and hereby agrees to fulfill, perform, be bound by, pay and discharge (or cause to be fulfilled, performed, paid or discharged) all obligations and liabilities of any kind whatsoever of Seller arising from or relating to the Assets, or the use, ownership and/or operation thereof, that are attributable to periods before, on or after the Effective Time, including obligations to (a) furnish makeup gas and/or settle Imbalances according to the terms of applicable gas sales, processing, gathering or transportation Contracts included in the Assets, (b) pay working interests, royalties, overriding royalties and other interests, owners’ revenues or proceeds attributable to sales of Hydrocarbons, including those held in suspense (excluding the Suspense Funds) to the extent attributable to the Assets, (c) properly plug and abandon any and all wells and pipelines, including future wells, inactive wells or temporarily abandoned wells, drilled on the Assets, (d) to re-plug any well, wellbore or previously plugged Well on the Assets to the extent required or necessary under applicable Laws or under Contracts or Surface Contracts, (e) dismantle or decommission and remove any Equipment and other property of whatever kind located on the Assets related to or associated with operations and activities conducted by whomever on the Assets, (f) clean up and/or remediate the Assets in accordance with any Contracts, Surface Contracts and applicable Laws, including all Environmental Laws, and (g) perform all obligations applicable to or imposed on the lessee, owner, or operator under the Leases, Permits, Surface Contracts and/or the Contracts, or as required by Law (the “Assumed Liabilities”); provided, Buyer does not assume (and Assumed Liabilities shall not include): (i) the Retained Liabilities, (ii) any obligations or liabilities of Seller to the extent that they are attributable to or arise out of the ownership, use or operation of the Excluded Assets, (iii) any other Claims for which Seller is required to indemnify Buyer pursuant to Article 4; or (iv) any Environmental Liabilities arising during, related to or otherwise attributable to the period prior to the Closing Date.

ARTICLE 3[INTENTIONALLY OMITTED]

ARTICLE 4ALLOCATION OF RESPONSIBILITIES AND INDEMNITIES

4.1Opportunity for Review. Each Party represents that it has had an adequate opportunity to review the release and indemnity provisions in this Agreement, including the opportunity to submit the same to legal counsel for review and comment. Based upon the foregoing representation, the Parties agree to the provisions set forth below.

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4.2Seller’s Indemnity Obligation. [***]

[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 

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4.3Buyer’s Indemnity Obligation. [***]

4.4Threshold, Aggregate Threshold, Cap. [***]

4.5Tax Treatment. The Parties shall treat, for Tax purposes, any amounts paid under this Article 4 as an adjustment to the Adjusted Purchase Price.

[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. 

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4.6Notice of Claims. If a Claim is asserted against a Person for which a Party may have Indemnity Obligations under this Agreement (an “Indemnity Claim”), the indemnified Person shall give the indemnifying Party written notice of the underlying Claim setting forth the particulars associated with the underlying Claim (including a copy of the written underlying Claim, if any) as then known by the indemnified Person (“Indemnity Claim Notice”). The indemnified Person shall, to the extent practicable, give an Indemnity Claim Notice within such time as will allow the indemnifying Party a reasonable period in which to evaluate and timely respond to the underlying Claim; provided failure to do so shall not affect an indemnified Person’s rights hereunder except for, and only to the extent of, any incremental increase in the cost of the Indemnity Claim resulting from the failure to give notice.

4.7Defense of Non-Party Claims. Upon receipt of an Indemnity Claim Notice involving a Non-Party for which an indemnifying Party believes it may have an obligation of indemnity under this Agreement, the indemnifying Party shall, if it so elects in accordance with this Section 4.7 (without prejudice to its right to contest its obligation of indemnity under this Agreement), assume the defense of the Non-Party Claim with counsel selected by the indemnifying Party, and the indemnified Person shall cooperate in all reasonable respects. If any Non-Party Claim involves a fact pattern wherein each Party may have an obligation to indemnify the other Party, each Party may assume the defense of and hire counsel for that portion of the Non-Party Claim for which it may have an obligation of indemnity. In all instances, the indemnified Person may employ separate counsel and participate in the defense of any Non-Party Claim; provided, if the indemnifying Party has assumed the defense of a Non-Party Claim pursuant to this Section 4.7 and has agreed to indemnify the indemnified Person, the fees and expenses of counsel employed by the indemnified Person shall be borne solely by the indemnified Person. If the indemnifying Party elects by written notice to undertake the defense of the Non-Party Claim within 30 Days after receipt of the Indemnity Claim Notice, then (i) the indemnifying Party shall defend the indemnified Person against such Non-Party Claim, (ii) the indemnifying Party shall pay any judgment entered or settlement with respect to such Non-Party Claim, (iii) the indemnifying Party shall not consent to the entry of any judgment or enter into any settlement with respect to such Non-Party Claim that (A) does not include a provision whereby the plaintiff or claimant in the matter releases the indemnified Person from all liability with respect to such Non-Party Claim, or (B) would restrict such indemnified Person’s ability to conduct its business in the ordinary course, and (iv) the indemnified Person shall not consent to the entry of any judgment or enter into any settlement with respect to such Non-Party Claim without the indemnifying Party’s prior written consent. If the indemnifying Party has not elected to undertake the defense of a Non-Party Claim, or if the indemnifying Party assumes the defense of a Non-Party Claim pursuant to this Section 4.7 but fails to diligently defend against the Non-Party Claim within 30 Days following any written notice from such indemnified Person asserting such failure, then the indemnified Person shall have the right to defend, at the sole cost and expense of the indemnifying Party (to the extent the indemnified Person is entitled to indemnification hereunder), the Non-Party Claim by all appropriate proceedings. In such instances, the indemnified Person shall have full control of such defense and proceedings; provided, the indemnified Person shall not settle such Non-Party Claim without the written consent of the indemnifying Party; provided further, if the indemnifying Party fails to notify the indemnified Person

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in writing as to whether or not it consents to such settlement within 30 Days following its receipt of notice of such settlement from the indemnified Person, then such consent shall be deemed given. The indemnifying Party may participate in, but not control, any defense or settlement controlled by an indemnified Person pursuant to this Section 4.7, and the indemnifying Party shall bear its own costs and expenses with respect to such participation. Notwithstanding the other provisions of this Section 4.7, if the indemnifying Party disputes its potential liability to the indemnified Person under this Section 4.7 and if such dispute is resolved in favor of the indemnifying Party, the indemnifying Party shall not be required to bear the costs and expenses of the indemnified Person’s defense pursuant to this Section 4.7.

4.8Investigation and Knowledge. Buyer acknowledges that it has had the opportunity to conduct due diligence and investigation with respect to the Assets, and in no event shall Seller have any liability to Buyer with respect to any breach of Seller’s representations, warranties or covenants under this Agreement to the extent Buyer had Knowledge of such breach as of the Closing Date.

4.9Waiver of Certain Damages. EACH OF THE PARTIES EXPRESSLY WAIVES AND RELEASES, AND SHALL CAUSE ITS AFFILIATES TO WAIVE AND RELEASE, SPECIAL, INDIRECT, CONSEQUENTIAL, PUNITIVE, REMOTE, SPECULATIVE AND EXEMPLARY DAMAGES, INCLUDING DAMAGES FOR LOST PROFITS OF ANY KIND WITH RESPECT TO ANY DISPUTE ARISING UNDER, RELATED TO, OR IN CONNECTION WITH THIS AGREEMENT OR ANY OTHER AGREEMENT, CONTRACT OR INSTRUMENT CONTEMPLATED HEREIN OR IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREBY, EXCEPT, IN EACH CASE, TO THE EXTENT ANY SUCH PARTY SUFFERS SUCH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING OF SUCH DAMAGES) TO A THIRD PARTY, WHICH DAMAGES (INCLUDING COSTS OF DEFENSE AND REASONABLE ATTORNEY’S FEES INCURRED IN CONNECTION WITH DEFENDING AGAINST SUCH DAMAGES) SHALL NOT BE EXCLUDED BY THIS PROVISION AS TO RECOVERY HEREUNDER.

4.10Extent of Indemnification. WITHOUT LIMITING THE SCOPE OF THE INDEMNIFICATION, DISCLAIMER, RELEASE AND ASSUMPTION OBLIGATIONS SET FORTH IN THIS AGREEMENT, TO THE FULLEST EXTENT PERMITTED BY LAW, AN INDEMNIFIED PERSON SHALL BE ENTITLED TO INDEMNIFICATION HEREUNDER IN ACCORDANCE WITH THE TERMS HEREOF, REGARDLESS OF WHETHER THE CLAIM OR INDEMNIFIABLE LOSS GIVING RISE TO ANY SUCH INDEMNITY OBLIGATION IS THE RESULT OF THE SOLE, PARTIAL, ACTIVE, PASSIVE, CONCURRENT OR COMPARATIVE NEGLIGENCE, GROSS NEGLIGENCE, STRICT LIABILITY, OTHER LEGAL FAULT OR RESPONSIBILITY, OR VIOLATION OF ANY LAW OF OR BY ANY SUCH INDEMNIFIED PERSON.

4.11Survival. [***]

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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4.12Environmental Liabilities. [***] 

ARTICLE 5DISCLAIMERS

BUYERACKNOWLEDGES AND AGREES THAT, EXCEPT AS OTHERWISE EXPRESSLY PROVIDED IN ARTICLE 6 AND IN THE SPECIAL WARRANTY SET FORTH IN THE ASSIGNMENT, NEITHER SELLER NOR ANY AFFILIATE OF SELLER MAKES ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY, IMPLIED OR OTHERWISE WITH RESPECT TO THE ASSETS. EXCEPT AS OTHERWISE EXPRESSLY PROVIDED IN ARTICLE 6 AND IN THE SPECIAL WARRANTY SET FORTH IN THE ASSIGNMENT, SELLER, FOR ITSELF AND ITS AFFILIATES, HEREBY EXPRESSLY DISCLAIMS AND NEGATES ANY AND ALL REPRESENTATIONS AND WARRANTIES, EXPRESS, STATUTORY, IMPLIED OR OTHERWISE, AND PROJECTIONS, FORECASTS, STATEMENTS OR INFORMATION MADE, COMMUNICATED OR FURNISHED (ORALLY OR IN WRITING) TO BUYER OR ANY OF ITS AFFILIATES OR REPRESENTATIVES, ASSOCIATED WITH THE ASSETS.

EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 6, AND WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, SELLER EXPRESSLY DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, AS TO (a) TITLE TO ANY OF THE ASSETS, (b) THE CONTENTS, CHARACTER OR NATURE OF ANY REPORT OF ANY PETROLEUM ENGINEERING CONSULTANT OR ANY ENGINEERING, GEOLOGICAL OR SEISMIC DATA OR INTERPRETATION, RELATING TO THE ASSETS, (c) THE QUANTITY, QUALITY OR RECOVERABILITY OF HYDROCARBONS IN OR FROM THE ASSETS, (d) ANY ESTIMATES OF THE VALUE OF THE ASSETS OR FUTURE REVENUES GENERATED BY THE ASSETS, (e) THE PRODUCTION OF HYDROCARBONS FROM THE ASSETS, (f) THE MAINTENANCE, REPAIR, CONDITION, QUALITY, SUITABILITY, DESIGN OR MARKETABILITY OF THE ASSETS, (g) THE CONTENT, CHARACTER OR NATURE OF ANY INFORMATION MEMORANDUM, REPORTS, BROCHURES, CHARTS OR STATEMENTS PREPARED BY SELLERS OR THIRD PARTIES WITH RESPECT TO THE ASSETS, (h) ANY OTHER MATERIALS OR INFORMATION THAT MAY HAVE

BEEN MADE AVAILABLE TO BUYER OR ITS AFFILIATES OR ITS OR THEIR EMPLOYEES, AGENTS, CONSULTANTS, REPRESENTATIVES OR ADVISORS IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT OR ANY DISCUSSION OR PRESENTATION RELATING THERETO AND (i) ANY IMPLIED OR EXPRESS WARRANTY OF FREEDOM FROM PATENT OR TRADEMARK INFRINGEMENT. EXCEPT AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN ARTICLE 6 OR THE ASSIGNMENT, SELLER FURTHER DISCLAIMS ANY REPRESENTATION OR WARRANTY, EXPRESS, STATUTORY OR IMPLIED, OF MERCHANTABILITY, FREEDOM FROM LATENT

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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VICES OR DEFECTS, FITNESS FOR A PARTICULAR PURPOSE OR CONFORMITY TO MODELS OR SAMPLES OF MATERIALS OF ANY OF THE ASSETS, RIGHTS OF A PURCHASER UNDER APPROPRIATE STATUTES TO CLAIM DIMINUTION OF CONSIDERATION OR RETURN OF THE PURCHASE PRICE, IT BEING EXPRESSLY UNDERSTOOD AND AGREED BY THE PARTIES THAT BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS IN THEIR PRESENT STATUS, CONDITION AND STATE OF REPAIR, “AS IS” AND “WHERE IS” WITH ALL FAULTS OR DEFECTS (KNOWN OR UNKNOWN, LATENT, DISCOVERABLE OR UNDISCOVERABLE), AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH INSPECTIONS OF THE ASSETS AS BUYER DEEMS APPROPRIATE.

OTHER THAN AS AND TO THE LIMITED EXTENT EXPRESSLY REPRESENTED OTHERWISE IN SECTION 6.14, SELLER HAS NOT AND WILL NOT MAKE ANY REPRESENTATION OR WARRANTY REGARDING ANY MATTER OR CIRCUMSTANCE RELATING TO ENVIRONMENTAL LAWS, THE RELEASE OF HAZARDOUS SUBSTANCES INTO THE ENVIRONMENT OR THE PROTECTION OF HUMAN HEALTH, SAFETY, NATURAL RESOURCES OR THE ENVIRONMENT, OR ANY OTHER ENVIRONMENTAL CONDITION OF THE ASSETS, AND NOTHING IN THIS AGREEMENT OR OTHERWISE SHALL BE CONSTRUED AS SUCH A REPRESENTATION OR WARRANTY, AND SUBJECT TO BUYER’S LIMITED RIGHTS AS EXPRESSLY SPECIFIED IN THIS AGREEMENT FOR A BREACH OF SELLER’S REPRESENTATIONS SET FORTH IN SECTION 6.14, BUYER SHALL BE DEEMED TO BE OBTAINING THE ASSETS “AS IS” AND “WHERE IS” WITH ALL FAULTS FOR PURPOSES OF THEIR ENVIRONMENTAL CONDITION AND THAT BUYER HAS MADE OR CAUSED TO BE MADE SUCH ENVIRONMENTAL INSPECTIONS OF THE ASSETS AS BUYER DEEMS APPROPRIATE.

BUYER ACKNOWLEDGES THAT THE ASSETS HAVE BEEN USED FOR EXPLORATION, DEVELOPMENT, PRODUCTION, GATHERING AND TRANSPORTATION OF OIL AND GAS AND THERE MAY BE PETROLEUM, PRODUCED WATER, WASTES OR OTHER SUBSTANCES OR MATERIALS LOCATED IN, ON OR UNDER THE ASSETS OR ASSOCIATED WITH THE ASSETS. EQUIPMENT AND SITES INCLUDED IN THE ASSETS MAY CONTAIN ASBESTOS, NORM OR OTHER HAZARDOUS SUBSTANCES. NORM MAY AFFIX OR ATTACH ITSELF TO THE INSIDE OF WELLS, PIPELINES, MATERIALS AND EQUIPMENT AS SCALE, OR IN OTHER FORMS. THE WELLS, MATERIALS AND EQUIPMENT LOCATED ON THE ASSETS OR INCLUDED IN THE ASSETS MAY CONTAIN NORM AND OTHER WASTES OR HAZARDOUS SUBSTANCES. NORM CONTAINING MATERIAL AND/OR OTHER WASTES OR HAZARDOUS SUBSTANCES MAY HAVE COME IN CONTACT WITH VARIOUS ENVIRONMENTAL MEDIA, INCLUDING, WATER, SOILS OR SEDIMENT. SPECIAL PROCEDURES MAY BE REQUIRED FOR THE ASSESSMENT, REMEDIATION, REMOVAL, TRANSPORTATION OR DISPOSAL OF ENVIRONMENTAL MEDIA, WASTES, ASBESTOS, NORM AND OTHER HAZARDOUS SUBSTANCES FROM THE ASSETS. FOR THE AVOIDANCE OF DOUBT, NORM SHALL

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NOT CONSTITUTE THE BASIS OF A BREACH OF SELLER’S REPRESENTATIONS AND WARRANTIES SET FORTH IN SECTION 6.14.

ARTICLE 6SELLER’S REPRESENTATIONS AND WARRANTIES

Seller represents and warrants to Buyer the following:

6.1Organization and Good Standing.

(a)Seller is a limited liability company organized, validly existing and in good standing under the Laws of the State of Louisiana and has all requisite power and authority to own and/or dispose of the Assets.

6.2Authority; Authorization of Agreement. Seller has all requisite power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party. This Agreement constitutes, and the Operative Documents to which it is a party, when executed and delivered by Seller, shall constitute, the valid and binding obligations of Seller, enforceable against it in accordance with their respective terms, except as such enforceability may be limited by bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

6.3No Violations. Except for (i) Customary Post-Closing Consents and (ii) any consents or approvals listed on Schedule 6.3, Seller’s execution and delivery of this Agreement and the Operative Documents to which it is a party and the consummation of the transactions contemplated by this Agreement by it shall not:

(a)conflict with any of the terms, conditions or provisions of the organizational documents of Seller;

(b)violate any material provision of, or require any material filing, consent or approval under, any Laws applicable to Seller;

(c)conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit the acceleration of the performance required by, or require any consent, authorization or approval under any Material Contract or financing instrument; or

(d)result in the creation or imposition of any lien or encumbrance upon one or more of the Assets, except for the Permitted Encumbrances.

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6.4Liability for Brokers’ Fees. Seller has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Buyer or any Affiliate of Buyer shall, directly or indirectly, have any responsibility whatsoever.

6.5Legal Proceedings. Schedule 6.5 sets forth all Legal Proceedings pending or, to Seller’s Knowledge, threatened in writing, against Seller in respect of any of the Assets.

6.6Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Seller’s Knowledge, threatened against Seller.

6.7Taxes. [***]

6.8Material Contracts. [***]

6.9[***].

6.10Preferential Rights. Except as set forth on Schedule 6.10, there are no preferential rights to purchase that are applicable to the transaction contemplated hereby (each, a “Preferential Right”).

6.11Consents. Except as set forth on Schedule 6.3, there are no third party consent requirements that are applicable to the transaction contemplated hereby.

6.12[***].

6.13Current Commitments. Schedule 6.13 sets forth as of the Execution Date all authorities for expenditures in excess of $50,000 (“AFE’s”) (net to the interest of Seller) relating to the Oil and Gas Properties to drill or rework Wells or for other capital expenditures pursuant to any of the Material Contracts for which all of the activities anticipated in such AFE’s or commitments have not been completed as of the Execution Date.

6.14[***].

6.15Production Imbalances. Schedule 6.15 sets forth all Imbalances with respect to Oil and Gas Properties.

6.16[***].

6.17[***].

6.18[***].

6.19Liens. Except for Permitted Encumbrances, the Assets shall be conveyed to Buyer at the Closing free and clear of all liens and encumbrances by, through or under Seller.

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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6.20Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by, or to the Knowledge of Seller threatened against, Seller or the Assets.

6.21[***].

6.22[***].

6.23[***].

6.24[***]

ARTICLE 7BUYER’S REPRESENTATIONS AND WARRANTIES

Buyer represents and warrants to Seller the following:

7.1Organization and Good Standing. Buyer is a limited liability company duly organized, validly existing and in good standing under the Laws of the State of Delaware and has all requisite power and authority to own the Assets.

7.2Authority; Authorization of Agreement. Buyer has all requisite power and authority to execute and deliver this Agreement and the Operative Documents to which it is a party, to consummate the transactions contemplated by this Agreement and the Operative Documents to which it is a party and to perform all of its obligations under this Agreement and the Operative Documents to which it is a party. This Agreement constitutes, and the Operative Documents to which it is a party, when executed and delivered by Buyer, shall constitute, the valid and binding obligation of Buyer, enforceable against it in accordance with their terms, except as such enforceability may be limited by bankruptcy, insolvency or other Laws relating to or affecting the enforcement of creditors’ rights and general principles of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).

7.3No Violations. No consent is required to be obtained with respect to the consummation of the transactions contemplated by this Agreement by Buyer. Buyer’s execution and delivery of this Agreement and the Operative Documents, to which it is a party and the consummation of the transactions contemplated by this Agreement by it shall not:

(a)conflict with or require the consent of any Person under any of the terms, conditions or provisions of the organizational documents of Buyer;

(b)violate any provision of, or require any filing, consent or approval under any Laws applicable to Buyer; or

(c)conflict with, result in a breach of, constitute a default under or constitute an event that with notice or lapse of time, or both, would constitute a default under, accelerate or permit

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[***] Confidential information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information.

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the acceleration of the performance required by, or require any consent, authorization or approval under: (i) any material agreement or any mortgage, indenture, loan, credit agreement or other agreement evidencing indebtedness for borrowed money to which Buyer is a party or by which Buyer is bound, except (in each case) where such conflict, breach or default would not materially affect Buyer’s ability to consummate the transactions contemplated hereby or (ii) any order, judgment or decree of any Governmental Authority.

7.4Liability for Brokers’ Fees. Buyer has not incurred any liability, contingent or otherwise, for investment bankers’, brokers’ or finders’ fees relating to the transactions contemplated by this Agreement for which Seller or any Affiliate of Seller shall, directly or indirectly, have any responsibility whatsoever.

7.5Claims, Disputes and Litigation. There are no Legal Proceedings pending or, to Buyer’s Knowledge, threatened in writing against Buyer, that would prevent the consummation of the transactions contemplated by this Agreement.

7.6Bankruptcy. There are no bankruptcy, reorganization or receivership proceedings pending, being contemplated by or, to Buyer’s Knowledge, threatened against Buyer.

7.7Financing; Resources and Other Capabilities. Buyer has sufficient funds with which to pay the Adjusted Purchase Price and consummate the transactions contemplated by this Agreement. Buyer has the financial, technical and other capabilities to perform all of Buyer’s other obligations under this Agreement and all of the obligations assumed from Seller with respect to the Assets.

7.8Independent Evaluation. Buyer is sophisticated in the evaluation, purchase, ownership and operation of oil and gas properties and related facilities. In making its decision to enter into this Agreement and to consummate the transactions contemplated hereby, Buyer has (a) relied on the representations and warranties of Sellers set forth in Article 6 and in the other Operative Documents and (b) relied on its own independent investigation and evaluation of the Assets and the advice of its own legal, Tax, economic, environmental, engineering, geological and geophysical advisors and not on any comments, statements, projections or other material made or given by any representative, consultant or advisor of any Seller. Buyer acknowledges and affirms that on or prior to Closing, Buyer will have completed its independent investigation, verification, analysis, and evaluation of the Assets and made all such reviews and inspections of the Assets as it has deemed necessary or appropriate to consummate the transaction contemplated hereunder; provided, however, no such investigation, verification, analysis or evaluation (or absence thereof) shall reduce, modify, release or waive any of Seller’s obligations or liabilities hereunder or under any of the other Operative Documents.

7.9Accredited Investor. Buyer is an “accredited investor,” as such term is defined in Regulation D of the Securities Act of 1933, as amended, and will acquire the Assets for its own account and not with a view to a sale or distribution thereof in violation of the Securities Act of 1933, as amended, and the rules and regulations thereunder, any applicable state blue sky Laws or any other applicable securities Laws.

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ARTICLE 8COVENANTS

8.1Release of Liens. Concurrent with the Closing, Seller shall procure and deliver to Buyer a release or releases, in recordable form, executed by the applicable Person of those liens and security interests encumbering any of the Assets, including those set forth on Schedule 8.1, and secure any debt facilities maintained by Seller or any Affiliate.

8.2Consents.

(d)Following Closing, Seller shall send to each holder of a right to consent to assignment pertaining to the Assets and the transactions contemplated hereby set forth on Schedule 6.3, a notice seeking such holder’s consent to the transactions contemplated hereby. Seller shall use commercially reasonable efforts to procure the consents set forth on Schedule 6.3, and Buyer shall reasonably cooperate with Seller in seeking to obtain such consents, but, in each case, without being obligated to pay any consideration or waive or release any right or privilege to obtain such consent.

(e)For each consent to assignment set forth on Schedule 6.3, the failure to obtain such consent would cause or give rise to a Non-Party having a right to cause (i) the assignment of the Asset(s) affected thereby to Buyer to be void or voidable, (ii) the termination of a Lease or Surface Contract under the express terms thereof, or (iii) impose additional conditions on the proposed assignee that involve the payment of money, the posting of collateral security or the performance of other obligations by the assignee that would not be required in the absence of Seller’s assignment of the affected Asset (each, a “Hard Consent”), the affected Asset(s) shall be excluded from the Assets to be acquired by Buyer at Closing hereunder and the Purchase Price shall be reduced by the Allocated Value of the Asset(s) so excluded. In the event that a Hard Consent (with respect to any applicable Asset(s) excluded pursuant to this Section 8.2) that was not obtained prior to Closing is obtained within 180 days following Closing, then, Buyer shall purchase, within 10 days after such Hard Consent is obtained, such Asset(s) so excluded by Seller under the terms of this Agreement for the amount by which the Purchase Price was reduced at Closing due to the exclusion of such Asset(s) (as such amount is appropriately adjusted in accordance to Section 2.3with respect to such Asset(s)), and Seller shall assign to Buyer such Asset(s) pursuant to an assignment in form substantially similar to the Assignment. Any portion of the Assets which are excluded from Closing and retained by Seller pursuant to the terms of this Section 8.2shall be deemed to be Excluded Assets for all purposes under this Agreement unless and until such Assets are assigned to Buyer in accordance with the terms hereof.

(f)For all Customary Post-Closing Consents and all consents to assignment set forth in Schedule 6.3, other than Hard Consents, for which Seller is unable to obtain consent from the applicable holders of such consents, (i) the Asset(s) subject to such un-obtained consents shall be acquired by Buyer at Closing as part of the Assets and (ii) Seller shall defend and indemnify the Buyer Group from any and all Claims arising from the failure to obtain such consent, but, in each case, only up to the Allocated Value of the affected Asset; provided that, for the avoidance of doubt, the defense and indemnity obligations set forth in this Section 8.2, if applicable, shall not be subject to the limitations set forth in Section 4.4.

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8.3Approvals of Governmental Authorities.

(a)    Seller and Buyer shall use their commercially reasonable efforts to take or cause to be taken all appropriate action, and to do, or cause to be done, all things necessary or reasonably advisable under applicable Laws to consummate and make effective the transactions contemplated by this Agreement, including using their commercially reasonable efforts to obtain, or cause to be obtained, all waivers, permits, consents, approvals, authorizations, qualifications and orders of all Governmental Authorities and officials and parties to contracts with the Parties that may be or become necessary for the performance of obligations pursuant to this Agreement and the consummation of the transactions contemplated by this Agreement and all Parties hereto will cooperate fully with the other Parties hereto in promptly seeking to obtain all such waivers, permits, consents, approvals, authorizations, qualifications and orders.

(b)    The Parties hereto shall cooperate and assist one another in connection with all actions to be taken pursuant to Section 8.3(a), including the preparation and making of the filings referred to therein and, if requested, amending or furnishing additional information hereunder. Each Party shall use its commercially reasonable efforts to provide or cause to be provided promptly to the other Party all necessary information and assistance as any Governmental Authority may from time to time require in connection with obtaining the relevant waivers, permits, consents, approvals, authorizations, qualifications, orders or expiration of waiting periods in relation to these filings or in connection with any other review or investigation of the transactions contemplated by this Agreement by a Governmental Authority. Each Party shall permit the other Party to review and discuss in advance, and shall consider in good faith the views of the other Party in connection with, any analyses, presentations, memoranda, briefs, written arguments, opinions, written proposals or other materials to be submitted to the Governmental Authorities with respect to such filings. In addition, neither Party shall agree to participate in any substantive meeting or discussion with any Governmental Authority in respect of any filing, review, investigation or other inquiry concerning this Agreement or the transactions contemplated by this Agreement, or enter into any agreements with any Governmental Authority, including, without limitation, extending any antitrust waiting periods, unless it consults with the other Party in advance and, to the extent permitted by such Governmental Authority, gives the other Party the opportunity to attend and participate thereat. Each Party shall keep the other apprised of the material content and status of any material communications with, and material communications from, any Governmental Authority with respect to the transactions contemplated by this Agreement. The Parties shall, and shall cause their respective Affiliates to use their commercially reasonable efforts to, provide each other with copies of all material, substantive correspondence, filings or communications between them or any of their respective representatives, on the one hand, and any Governmental Authority or members of its staff, on the other hand, with respect to this Agreement and the transactions contemplated by this Agreement; provided, however, that materials may be redacted (i) to remove references concerning the valuation of the Assets; (ii) as necessary to comply with contractual arrangements or applicable Laws; and (iii) as necessary to address reasonable attorney-client or other privilege or confidentiality concerns.

(c)    Notwithstanding the foregoing, nothing contained in this Agreement shall be construed so as to require Buyer or Seller, or any of their respective Affiliates, without its written

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consent, to sell, license, dispose of, hold separate or operate in any specified manner any assets or businesses of Buyer or Seller (or to require Buyer or Seller or any of their respective Affiliates to agree to any of the foregoing).

8.4Efforts. Each Party shall use commercially reasonable efforts to take all actions and to do all things necessary to consummate, make effective and comply with all of the terms of this Agreement. Without limiting the generality of the foregoing, from time to time after Closing, Seller and Buyer shall each execute, acknowledge and deliver to the other such further instruments as may be reasonably requested by the other Party, at such requesting Party’s cost, and as are commercially reasonable to be performed in order to accomplish more effectively the purposes of the transactions contemplated by this Agreement, including those post-Closing actions contemplated by Section 8.2. Promptly after Closing, Buyer shall: (a) record the Assignment and all state and federal assignments executed at the Closing in all applicable real property records and/or, if applicable, all state and federal Governmental Authorities and Buyer shall provide to Seller copies of such recorded documents; (b) actively pursue the approval of all Customary Post-Closing Consents from the applicable Governmental Authorities; and (c) except as otherwise provided for herein, actively pursue all other consents and approvals that may be required in connection with the assignment of the Assets to Buyer and the assumption of the rights, interests, obligations and liabilities assumed by Buyer hereunder that have not been obtained prior to Closing, provided that Seller shall reasonably cooperate with Buyer in obtaining such other consents and approvals. Promptly after Closing, Seller shall deliver all notices that are required to be delivered in connection with the assignment of the Assets to Buyer and the assumption of the rights, interests, obligations and liabilities assumed by Buyer hereunder.

8.5Governmental Bonds. Buyer acknowledges that none of the bonds, letters of credit and guarantees, if any, posted by any Seller or its Affiliates with Governmental Authorities and relating to the Assets (collectively, the “Seller Bonds”) are transferable to Buyer. As more particularly set forth in the Contract Operating Services Agreement, Seller shall use commercially reasonable efforts to retain and continue to maintain the Seller Bonds after Closing, at Buyer’s sole cost, to the extent necessary to operate the Assets. Except to the extent Seller is able to retain any Seller Bonds on behalf of Buyer in accordance with the terms of the Contract Operating Services Agreement, on or before 30 days following Closing, Buyer, at its sole cost, shall obtain replacement bonds, letters of credit and guarantees, including those described on Schedule 8.5, to the extent such replacements are necessary for Buyer’s ownership and/or operation of the Assets. Subject to the terms of the Contract Operating Services Agreement, following Closing, Buyer and Seller shall cooperate and use commercially reasonable efforts to cause the cancellation of the Seller Bonds; provided that any costs required for the cancellation of the Seller Bonds shall be borne solely by Sellers. Subject to the terms of the Contract Operating Services Agreement, in addition, promptly following Closing, Buyer shall, to the extent applicable, deliver to Seller evidence of the posting of bonds or other security with all applicable Governmental Authorities meeting the requirements of such authorities to own and, where appropriate, operate, the Assets.

8.6Records in Seller’s Possession. Seller shall retain originals of all Records following Closing and during the term of the Contract Operating Services Agreement, and shall provide Buyer, its Affiliates and each of their officers, employees and representatives with access to the Records

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during normal business hours for review and copying at Buyer’s expense during such time. Within 10 Business Days after the termination of the Contract Operating Services Agreement (except as provided below), Seller shall make available to Buyer the Records for pickup from Seller’s (and/or its Affiliates’) offices during normal business hours. Buyer shall retain and maintain the Records received from Seller for a period of 5 years after Closing. During such period of time, Buyer shall (a) provide Seller, its Affiliates and each of their officers, employees and representatives with access to the Records (to the extent that Seller has not retained the original or a copy) during normal business hours for review and copying at Seller’s expense, and (b) provide Seller, and its Affiliates and each of their officers, employees, and representatives with access, during normal business hours, to materials received or produced after the Closing relating to any indemnity claim made under Section 4.2for review and copying at Seller’s expense subject to such reasonable limitations as Buyer may place upon such review as a result of such materials being subject to legal privilege, confidentiality obligations, or Buyer’s trade secrets.

8.7Preferential Rights.

(a)At Closing, each portion of the Assets subject to a Preferential Right set forth on Schedule 6.10 (each, a “Preferential Right Property”), shall be excluded from the transactions hereunder, and the Base Purchase Price shall be reduced by the Allocated Value of the excluded Preferential Right Property.

(b)Following Closing, with respect to each Preferential Right set forth on Schedule 6.10, Seller shall send to the holder of each such right a written notice in material compliance with the contractual provisions applicable to such Preferential Right. Seller shall use commercially reasonable efforts to obtain waivers of all applicable Preferential Rights; provided, however, Seller shall not be obligated to pay any consideration to the holder of any Preferential Right in order to obtain the waiver thereof or compliance therewith.

(c)Following Closing, if the holder of a Preferential Right exercises a Preferential Right, Seller shall be entitled to all proceeds from such holder. If the holder of any Preferential Right Property (i) declines to exercise its Preferential Right or (ii) fails to consummate the purchase of the Preferential Right Property covered by such right and such holders’ rights to purchase such Preferential Right Property have expired, then Seller shall notify Buyer and Buyer shall purchase, on or before 10 Business Days following receipt of such notice, the Preferential Right Property under the terms of this Agreement for a price equal to the Allocated Value of such Preferential Right Property.

ARTICLE 9[INTENTIONALLY OMITTED]

ARTICLE 10THE CLOSING

10.1Closing. Contemporaneously with the execution of this Agreement, the closing of the transactions contemplated by this Agreement shall take place at the offices of Latham & Watkins LLP, 811 Main Street, Suite 3700 Houston, Texas 77002, on the 4thday of June, 2015 (the “Closing

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Date”). Seller has provided Buyer with wiring instructions designating the account or accounts to which the Closing Amount is to be delivered.

10.2Obligations of Seller at Closing. At Closing, Seller shall deliver or cause to be delivered to Buyer, unless waived by Buyer, the following:

(a)originals of the Assignment executed by Seller in sufficient counterparts and modified as necessary for recording in all applicable jurisdictions;

(b)originals of the Affiliate Assignment executed by Seller in sufficient counterparts and modified as necessary for recording in all applicable jurisdictions;

(c)assignments in form required by any Governmental Authority for the assignment of any Assets controlled by such Governmental Authority, duly executed by Seller, in sufficient duplicate originals to allow recording and/or filing in all appropriate offices;

(d)executed originals of the Contract Operating Services Agreement;

(e)executed originals of the Certificate of Non-Foreign Status;

(d)    certificates of good standing from the states of Oklahoma and Louisiana;

(f)letters-in-lieu of transfer or division orders executed by Seller relating to the Assets to reflect the transaction contemplated hereby, which letters shall be on forms prepared by Seller and reasonably satisfactory to Buyer;

(g)any other forms required by any Governmental Authority relating to the assignments of the Assets to Buyer; and

(h)duly executed releases and terminations of the mortgages, deeds of trust, assignments of production, financing statements, fixture filings, and other encumbrances and interests burdening the Assets (or any thereof), including those set forth on Schedule 8.1, which shall, in each case, be in form and substance reasonably satisfactory to Buyer and forms of which shall have been delivered to Buyer on or before the Closing Date,

Seller shall take such other actions and deliver such other documents as are contemplated by this Agreement or as may be reasonably requested by Buyer.

10.3Obligations of Buyer at Closing. At Closing, Buyer shall deliver or cause to be delivered to Seller, unless waived by Seller, the Closing Amount by wire transfer. Buyer shall also take such other actions and deliver such other documents as are contemplated by this Agreement or as may be reasonably requested by Seller.

10.4Option Rights.

(a)For a period of 180 days following Closing (the “Option Period”), Buyer shall have the option upon written notice to Seller to acquire, at no additional cost, all or a portion

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of Seller’s remaining interest in (but only to the extent Seller owns such interest as of the Closing Date) any oil, gas and/or mineral leases located in the State of Oklahoma (the “Option Leases”), together with any Hydrocarbon, disposal or injection wells located on the Option Leases and any associated equipment and other tangible personal property, fixtures and improvements used or held for use in connection with the ownership or operation of the foregoing, but excluding, in each case, the DDA Properties and the Shallow Depth Properties (collectively, the “Option Properties”). For the avoidance of doubt, the Option Properties do not include, and this Section 10.4 shall not apply to, any oil, gas and/or mineral leases, assets or other real or personal property acquired by Seller following the Closing Date.

(b)In the event Buyer elects to acquire all or a portion of the Option Properties, Buyer shall provide Seller written notice on or before the last day of the Option Period setting forth those Option Properties Buyer has elected to acquire. Within 10 Business Days following Buyer’s written notice, Seller shall assign the applicable Option Properties to Buyer using the form of Assignment attached hereto. Upon assignment, the Option Properties being assigned shall be deemed Assets for all purposes under this Agreement, including for purposes of the Assumed Liabilities. For any Option Properties for which Buyer fails to timely deliver notice in accordance with this Section 10.4 electing to acquire during the Option Period, Buyer shall have no further option to acquire such properties under the terms of this Agreement.

10.5Employees. Buyer or its Affiliates may offer employment, effective as of or after the Closing Date, to any Oklahoma based employees of Seller or any of its Affiliates who provide services in relation to the Assets (“Seller Employees”); provided, however, that the actual hiring date of any Seller Employees to be employed by Buyer, but required by Seller or its Affiliates for the provision of “Services” under the Contract Operating Services Agreement, shall not be earlier than the termination date of the Contract Operating Services Agreement without the mutual agreement of the Parties. Seller Employees hired by the Buyer or its Affiliates shall be treated as newly hired employees of the Buyer or its Affiliates for all purposes. Seller shall, and shall cause its Affiliates to, cooperate with the Buyer or its Affiliates to effect an orderly and cost effective transition of any such Seller Employees. Seller shall, and shall cause its Affiliates to, cooperate with the Buyer or its Affiliates by releasing Seller Employees from any covenants not to compete or any similar applicable agreements.

ARTICLE 11[INTENTIONALLY OMITTED]

ARTICLE 12TAXES

12.1Like Kind Exchange. Buyer and Seller agree that either party (the “Exchange Party”) may reasonably request cooperation of the other party (the “Cooperating Party”) in completing a like-kind exchange which will qualify for treatment as a tax deferred exchange pursuant to the provisions of Section 1031 of the Code (a “1031 Exchange”). The Cooperating Party shall provide reasonable cooperation requested by the Exchange Party in implementing the 1031 Exchange. This cooperation shall not subject Cooperating Party to any additional liability beyond its existing obligations under this Agreement. The Exchange Party shall indemnify the Cooperating Party

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against any and all costs and expenses incurred with respect to furnishing such cooperation and reimburse the Cooperating Party, upon demand, for any increased expense incurred by the Cooperating Party relating to this 1031 Exchange. Cooperating Party shall not be obligated to take title to any property, other than the Assets, in the case of Buyer. A 1031 Exchange shall not delay the Closing. The accomplishment of the 1031 Exchange is not a condition to the Exchange Party’s obligations under this Agreement, and the Exchanging Party shall in all events remain liable for its obligations under this Agreement, including upon the Exchange Party’s failure to locate an exchange property or to consummate a like-kind exchange for any reason or for no reason at all (other than on account of Cooperating Party’s material breach of this Agreement). Neither Party represents to the other that any particular tax treatment will be given to either Party as a result of the like-kind exchange.

12.2Cooperation on Tax Matters. Buyer and Seller shall cooperate fully, as and to the extent reasonably requested by the other party, in connection with the filing of any Tax Return and any audit, litigation or other proceeding with respect to Taxes. Such cooperation shall include the retention and (upon the other party’s request) the provision of records and information which are reasonably relevant to any such Tax Return, audit, litigation or other proceeding and making employees available on a mutually convenient basis to provide additional information and explanation of any material provided hereunder. Each of Buyer and Seller agrees (a) to retain all books and records with respect to Tax matters pertinent to the acquired Assets relating to any taxable period beginning before the Closing Date until the expiration of the statute of limitations (and, to the extent notified by Buyer or Seller, any extensions thereof) of the respective taxable periods, and to abide by all record retention agreements entered into with any Taxing Authority, and (b) to give the other party reasonable written notice prior to transferring, destroying or discarding any such books and records and, if the other Party so requests, each party shall allow the other Party the option of taking possession of such books and records prior to their disposal. Buyer and Seller further agree, upon request, to use their commercially reasonable efforts to obtain any certificate or other document from any Taxing Authority or any other Person as may be necessary to mitigate, reduce or eliminate any Tax that could be imposed with respect to the transactions contemplated.

12.3Property and Excise Taxes. All ad valorem, real property, personal property, and similar Taxes assessed on the Assets (“Property Taxes”) and excise Taxes associated with any of the Assets (“Excise Taxes”) are Seller’s obligation for periods before the Effective Time and Buyer’s obligation for periods from and after the Effective Time; provided that, if the taxable period with respect to such a Tax begins on or before and ends after the Effective Time, then such Tax shall be attributable to the portions of such taxable period before and after the Effective Time based on the relative number days in each portion of such taxable period. If either party pays Property Taxes or Excise Taxes for which the other party is responsible, and the amount of such payment is not taken into account as an adjustment to the Base Purchase Price under Section 2.3, then upon receipt of evidence of payment the nonpaying party will reimburse the paying party promptly for the nonpaying party’s share of such Taxes.

12.4Severance Taxes. Seller shall bear and pay all severance or other Taxes based upon or measured by Hydrocarbon production from the Assets, or the receipt of proceeds therefrom, to the extent attributable to production from the Assets before the Effective Time. Buyer shall bear

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and pay all such Taxes on production from the Assets from and after the Effective Time. Seller shall withhold and pay on behalf of Buyer all such Taxes on production from the Assets between the Effective Time and the Closing Date, and the amount of any such payment shall be reimbursed to Seller as an adjustment to the Base Purchase Price pursuant to Section 2.3. If either party pays any such Taxes owed by the other, and the amount of such payment is not taken into account as an adjustment to the Base Purchase Price under Section 2.3, then upon receipt of evidence of payment the nonpaying party will reimburse the paying party promptly for the nonpaying party’s share of such Taxes

12.5Transfer Taxes. Seller shall pay all state and local transfer, sales, use, stamp, registration or other similar Taxes (the “Transfer Taxes”) resulting from the acquisition of the Assets contemplated by this Agreement or any other transaction document. Upon receipt of invoice from Seller, Buyer shall promptly reimburse Seller for all Transfer Taxes paid by Seller. Buyer and Seller shall cooperate in good faith to minimize, to the extent permissible under applicable Law, the amount of any such Transfer Taxes.

ARTICLE 13MISCELLANEOUS

13.1Notices. All notices and other communications required or desired to be given hereunder must be in writing and sent (properly addressed as set forth below) by: (a) U.S. mail with all postage and other charges fully prepaid, (b) electronic mail with a PDF of the notice or other communication attached (with the original sent by U.S. mail the same day such electronic mail is sent), or (c) facsimile transmission. A notice shall be deemed effective on the date on which such notice is received by the addressee, if by mail, or on the date sent, if by facsimile (as evidenced by fax machine confirmation of receipt) or if by electronic mail (as evidenced by computer generated confirmation of receipt); provided, if such date is not a Business Day, then date of receipt shall be on the next date that is a Business Day. Each Party may change its address by notifying the other Party in writing of such address change.

If to Seller:

PetroQuest Energy, L.L.C.

1800 Hughes Landing Blvd., Suite 200

The Woodlands, Texas 77380

Attn: Tracy Price, Vice President of Business Development & Land

Telephone: (281) 465-3920

Facsimile: (281) 465-3999

Email: tprice@petroquest.com

With a copy to (which shall not constitute notice):

PetroQuest Energy, L.L.C.

400 East Kaliste Saloom Road, Suite 6000

Lafayette, Louisiana 70508

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Attn:    Ed Abels, Executive Vice President & General Counsel

Facsimile: (337) 232-0044

Email: eabels@petroquest.com

If to Buyer:

WSGP Gas Producing, LLC

601 Travis Street, Suite 1900

Houston, Texas 77002

Facsimile: 713-751-0375

Attn:    Larry Wall

Email: Larry.Wall@nexteraenergy.com

With a copy to (which shall not constitute notice):

Karina Amelang

601 Travis Street, Suite 1900

Houston, Texas 77002

Facsimile: 713-751-0375

Email: Karina.Amelang@nexteraenergy.com

13.2Transaction and Filing Costs. Buyer, at its sole cost, shall be responsible for recording and filing documents associated with the transfer of the Assets to it, including filing the assignments with appropriate federal, state and local Governmental Authorities as required by applicable Law. Buyer, at its sole cost, shall also be responsible for any and all stamp, documentary, real property transfer, sales, gross receipts, use or similar Taxes or assessments resulting from its acquisition of the Assets contemplated by this Agreement. As soon as practicable after recording or filing, Buyer shall furnish Seller with all recording data and evidence of all required filings including filings with the appropriate state counties and parishes.

13.3Amendments and Severability. No amendments or other modifications to this Agreement shall be effective or binding on either of the Parties unless the same are in writing, designated as an amendment or modification, and signed by both Seller and Buyer. The invalidity of any one or more provisions of this Agreement shall not affect the validity of this Agreement as a whole, and in case of any such invalidity, this Agreement shall be construed as if the invalid provision had not been included herein.

13.4Successors and Assigns. Except as set forth in this Section 13.4, this Agreement may not be assigned, either in whole or in part, without the express written consent of the non-assigning Party, such consent not to be unreasonably withheld, conditioned or delayed. The terms, covenants and conditions contained in this Agreement are binding upon and inure to the benefit of Seller and Buyer and their respective successors and permitted assigns. Notwithstanding the foregoing, (i) Buyer may assign either this Agreement or any of its rights or interests hereunder without the prior written approval of the other Party to a third-party accommodator or qualified

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intermediary in connection with any like-kind exchange, as described in Section 12.1, and (ii) either Party may assign this Agreement and its rights and obligations hereunder to any Affiliate of such Party; provided, however, that no such assignment shall relieve either Party of any of its obligations or liabilities under this Agreement.

13.5Headings. The titles and headings set forth in this Agreement have been included solely for ease of reference and may not be considered in the interpretation or construction of this Agreement.

13.6Governing Law; Jurisdiction; Waiver of Trial by Jury.

(a)THIS AGREEMENT IS GOVERNED BY THE LAWS OF THE STATE OF TEXAS, EXCLUDING ANY CHOICE OF LAW RULES THAT MAY DIRECT THE APPLICATION OF THE LAWS OF ANOTHER JURISDICTION.

(b)THE PARTIES AGREE THAT ANY SUIT, ACTION OR PROCEEDING SEEKING TO ENFORCE ANY PROVISION OF, OR BASED ON ANY MATTER ARISING OUT OF OR IN CONNECTION WITH, THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY SHALL BE BROUGHT IN THE UNITED STATES DISTRICT COURT FOR THE SOUTHERN DISTRICT OF TEXAS, SO LONG AS SUCH COURT HAS SUBJECT MATTER JURISDICTION OVER SUCH SUIT, ACTION OR PROCEEDING (OR, IF REQUIREMENTS FOR FEDERAL JURISDICTION ARE NOT MET, STATE COURTS LOCATED IN HARRIS COUNTY, TEXAS), AND THAT ANY CAUSE OF ACTION ARISING OUT OF THIS AGREEMENT SHALL BE DEEMED TO HAVE ARISEN FROM A TRANSACTION OF BUSINESS IN THE STATE OF TEXAS, AND EACH OF THE PARTIES HEREBY IRREVOCABLY CONSENTS TO THE JURISDICTION OF SUCH COURTS (AND OF THE APPROPRIATE APPELLATE COURTS THEREFROM) IN ANY SUCH SUIT, ACTION OR PROCEEDING AND IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF THE VENUE OF ANY SUCH SUIT, ACTION OR PROCEEDING IN ANY SUCH COURT OR THAT ANY SUCH SUIT, ACTION OR PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM. PROCESS IN ANY SUCH SUIT, ACTION OR PROCEEDING MAY BE SERVED ON ANY PARTY ANYWHERE IN THE WORLD, WHETHER WITHIN OR WITHOUT THE JURISDICTION OF ANY SUCH COURT.

(c)WITH RESPECT TO ANY SUIT, ACTION OR PROCEEDING SEEKING TO ENFORCE ANY PROVISION OF, OR BASED ON ANY MATTER ARISING OUT OF OR IN CONNECTION WITH, THIS AGREEMENT OR THE TRANSACTION CONTEMPLATED HEREBY, THE PARTIES AGREE TO WAIVE TRIAL BY JURY.

13.7No Partnership Created. It is not the purpose or intention of this Agreement to create (and it should not be construed as creating) a joint venture, partnership or any type of association, and the Parties are not authorized to act as an agent or principal for each other with respect to any matter related hereto.

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13.8Public Announcements. Neither Seller nor Buyer (including any of their agents, employees or Affiliates in either case) may issue a public statement or press release with respect to the transaction contemplated hereby (including the price and other terms) without the prior written consent of the other Party, except as required by any applicable securities or other Laws or regulations or the applicable rules of any stock exchange having jurisdiction over the Parties or their respective Affiliates.

13.9No Third Party Beneficiaries. Nothing contained in this Agreement shall entitle anyone other than Seller and Buyer, their successors and permitted assigns or the express beneficiaries of indemnity provisions to any Claim, cause of action, remedy or right of any kind whatsoever; provided that only a Party and its respective successors and permitted assigns will have the right to enforce the provisions of this Agreement on its own behalf or on behalf of the express beneficiaries of the indemnity provisions (but shall not be obligated to do so).

13.10Waiver; Rights Cumulative. Any of the terms, covenants, representations, warranties or conditions hereof may be waived only by a written instrument executed by or on behalf of the Party waiving compliance. No course of dealing on the part of Seller or Buyer, or their respective officers, employees, agents or representatives or any failure by Seller or Buyer to exercise any of its rights under this Agreement shall operate as a waiver thereof or affect in any way the right of such Person at a later time to enforce the performance of such provision. No waiver by Seller or Buyer of any condition or any breach of any term, covenant, representation or warranty contained in this Agreement, in any one or more instances, shall be deemed to be or construed as a further or continuing waiver of any such condition or breach or a waiver of any other condition or of any breach of any other term, covenant, representation or warranty. The rights of Seller and Buyer under this Agreement shall be cumulative, and the exercise or partial exercise of any such right shall not preclude the exercise of any other right.

13.11Construction. The Parties acknowledge that they have had an adequate opportunity to review each and every provision contained in this Agreement and to submit the same to legal counsel for review and comment. Moreover, the Parties have participated jointly in the negotiation and drafting of this Agreement. Based on the foregoing, the Parties agree that the rule of construction that a contract be construed against the drafter, if any, not be applied in the interpretation or construction of this Agreement.

13.12Conspicuousness of Provisions. THE PARTIES ACKNOWLEDGE AND AGREE THAT THE PROVISIONS CONTAINED IN THIS AGREEMENT THAT ARE SET OUT IN “BOLD” AND/OR ALL CAPS SATISFY THE REQUIREMENT OF THE “EXPRESS NEGLIGENCE RULE” AND ANY OTHER REQUIREMENT AT LAW OR IN EQUITY THAT PROVISIONS CONTAINED IN A CONTRACT BE CONSPICUOUSLY MARKED OR HIGHLIGHTED.

13.13Execution in Counterparts. This Agreement may be executed in any number of counterparts, each of which shall be deemed to be an original, all of which when taken together shall constitute one and the same agreement.

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13.14Entire Agreement. This Agreement supersedes all prior and contemporaneous negotiations, understandings, letters of intent and agreements (whether oral or written) between the Parties with respect to the subject matter hereof and constitute the entire understanding and agreement between the Parties with respect thereto.

[signatures follow on next page]

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IN WITNESS WHEREOF, the Parties have executed this Agreement on the day and year first set forth above.

SELLER:

PETROQUEST ENERGY, L.L.C.

By: /s/ W. Todd Zehnder            

Name: W. Todd Zehnder        

Title: Chief Operating Officer    

BUYER:

WSGP GAS PRODUCING, LLC

By: /s/ Lawrence A. Wall, Jr.            

Name: Lawrence A. Wall, Jr.         

Title: President                

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EX-31.1

EXHIBIT 31.1

I, Charles T. Goodson, certify that:

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

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

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

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

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

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

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

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

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

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

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

/s/ Charles T. Goodson                            

Charles T. Goodson

Chief Executive Officer

August 5, 2015

EX-31.2

EXHIBIT 31.2

I, J. Bond Clement, certify that:

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

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

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

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

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

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

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

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

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

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

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

/s/ J. Bond Clement                        

J. Bond Clement

Chief Financial Officer

August 5, 2015

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending June 30, 2015 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ Charles T. Goodson

Charles T. Goodson

Chief Executive Officer

August 5, 2015

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

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-Q for the quarter ending June 30, 2015 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

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

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

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

August 5, 2015

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

XML

Other Comprehensive Income (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated other Comprehensive Income [Roll Forward]
Balance, beginning of period		$ (4,514)	$ 5,420	$ (1,096)
Change in fair value of derivatives		(1,982)		(8,803)
Income tax effect		0		0
Net of tax		(1,982)		(8,803)
Oil and gas sales		2,842		6,245
Income tax effect		0		0
Net of tax		2,842		6,245
Net other comprehensive income (loss)		860		(2,558)
Balance, end of period	$ 3,564	(3,654)	3,564	(3,654)
Gains and Losses on Cash Flow Hedges
Accumulated other Comprehensive Income [Roll Forward]
Balance, beginning of period	7,018	(2,834)	5,420	(688)
Change in fair value of derivatives	(1,471)	(1,982)	3,446	(8,803)
Income tax effect	547	737	(1,282)	3,275
Net of tax	(924)	(1,245)	2,164	(5,528)
Oil and gas sales	(4,029)	2,842	(6,401)	6,245
Income tax effect	1,499	(1,057)	2,381	(2,323)
Net of tax	(2,530)	1,785	(4,020)	3,922
Net other comprehensive income (loss)	(3,454)	540	(1,856)	(1,606)
Balance, end of period	$ 3,564	(2,294)	$ 3,564	(2,294)
Change in Valuation Allowance
Accumulated other Comprehensive Income [Roll Forward]
Balance, beginning of period		(1,680)		(408)
Change in fair value of derivatives		0		0
Income tax effect		(737)		(3,275)
Net of tax		(737)		(3,275)
Oil and gas sales		0		0
Income tax effect		1,057		2,323
Net of tax		1,057		2,323
Net other comprehensive income (loss)		320		(952)
Balance, end of period		$ (1,360)		$ (1,360)

XML

Derivative Instruments (Details) - 6 months ended Jun. 30, 2015	MMBTU bbl $ / shares
Swap | July 2015 - December 2015 | Natural Gas:
Oil and gas contracts
Daily Volumes | MMBTU	40,000
Weighted Average Price	$ 3.62
Swap | July 2015 - December 2015 | Propane:
Oil and gas contracts
Daily Volumes | bbl	250
Weighted Average Price	$ 25.62
Swap | July 2015 - June 2016 | Natural Gas:
Oil and gas contracts
Daily Volumes | MMBTU	10,000
Weighted Average Price	$ 3.22
Swap | July 2015 - September 2015 | Natural Gas:
Oil and gas contracts
Daily Volumes | MMBTU	5,000
Weighted Average Price	$ 2.89
Swap (LLS) | July 2015 - December 2015 | Crude Oil:
Oil and gas contracts
Daily Volumes | bbl	500
Weighted Average Price	$ 56.68

XML

Acquisitions and Divestitures - Acquisition (Fleetwood Joint Venture) (Details) a in Thousands, $ in Thousands	1 Months Ended
	Jun. 30, 2014 USD ($) a mi²	Jun. 30, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Cash funding for future drilling, completion and lease acquisition costs, outstanding		$ 5,655	$ 17,690
Fleetwood Joint Venture | Louisiana
Business Acquisition [Line Items]
Purchase price	$ 24,000
Average working interest in leasehold position	37.00%
Acres acquired in leasehold position | a	30
Square miles of proprietary 3D survey | mi²	200
Cash portion of acquisition	$ 10,000
Cash funding for future drilling	$ 14,000
Cash funding for future drilling, completion and lease acquisition costs, outstanding		$ 5,700

XML

Fair Value Measurements (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Net valuation of the Company's derivatives subject to fair value measurement on a recurring basis
Estimated fair value of the Notes	$ 327,000	$ 301,000
Book value of notes	350,000	350,000
Quoted Prices in Active Markets (Level 1)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	0	0
Significant Other Observable Inputs (Level 2)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	5,675	8,631
Significant Unobservable Inputs (Level 3)
Derivatives, Fair Value [Line Items]
Commodity derivatives at fair value	$ 0	$ 0

XML

Acquisitions and Divestitures

6 Months Ended

Jun. 30, 2015

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Acquisition:

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

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. If the $14 million in drilling, completion and lease acquisition costs is not fully funded by December 31, 2015, any remaining balance becomes payable at the election of our joint venture partner. At June 30, 2015, $5.7 million of the cash funding for future drilling, completion and lease acquisition costs remained outstanding. The liability is reflected as accrued acquisition costs in the Consolidated Balance Sheet.

Divestiture:

On June 4, 2015, the Company completed the sale of a majority of its interests in the Woodford and Mississippian Lime (the “Sold Assets”) for $280 million, subject to customary post-closing purchase price adjustments, effective January 1, 2015. At closing, the Company received $257.7 million in cash and recognized a receivable of $13.9 million related to the remainder of the adjusted purchase price to be received within 180 days as further discussed below.

In connection with the sale, the Company entered into a Contract Operating Services Agreement ("COSA") whereby the Company will retain a minimal working interest in the Sold Assets and will provide certain services as a contract operator for a period of one year from the closing date of the sale, subject to renewal for two additional one-year terms. During the 180 day period following the closing of the sale, for each of the first 14 wells spud by the Company as contract operator under the COSA, the Company will receive $1 million of the $13.9 million remaining purchase price as discussed above. If at the end of the 180 day period any portion of the purchase price remains outstanding, the Company will receive the balance in full.

At December 31, 2014, the estimated proved reserves attributable to the Sold Assets totaled approximately 227 Bcfe, which represented approximately 57% of the Company's estimated proved reserves. Under the full cost method of accounting, sales of oil and gas properties are accounted for as adjustments of capitalized costs with no gain or loss recognized, unless the adjustment significantly alters the relationship between capitalized costs and proved reserves. A significant alteration is generally not expected to occur for sales involving less than 25% of the total proved reserves. If the divestiture of the Sold Assets was accounted for as an adjustment of capitalized costs with no gain or loss recognized, the adjustment would have significantly altered the relationship between capitalized costs and proved reserves. Accordingly, the Company recognized a gain on the sale of $21.5 million. The carrying value of the properties sold was determined by allocating total capitalized costs within the full cost pool between properties sold and properties retained based on their relative fair values.

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Earnings Per Share (Details Textual) - shares shares in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	0.4		0.4
Convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	5.1	5.1	5.1	5.1
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	1.4	0.9	1.5	1.1

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
A reconciliation between basic and diluted earnings per share computations
Income (loss) available to common stockholders	$ (61,083)	$ 9,592	$ (183,323)	$ 19,635
Attributable to participating securities		(273)		(571)
Net income or loss available to common stockholders, Loss (excluding income attributable to participating securities)	$ (61,083)	$ 9,319	$ (183,323)	$ 19,064
Net loss available to common stockholders (in shares)	64,891	64,103	64,833	63,940
Stock options, Effect of dilutive securities		$ 0		$ 0
Net loss available to common stockholders, Per Share Amount	$ (0.94)	$ 0.15	$ (2.83)	$ 0.30
Stock options, effect of dilutive securities, (in shares)		64		56
Attributable to participating securities		$ (273)		$ (571)
Restricted stock, effect of dilutive securities (in shares)	0	0	0	0
DILUTED EPS, Loss	$ (61,083)	$ 9,319	$ (183,323)	$ 19,064
DILUTED EPS, Shares	64,891	64,167	64,833	63,996
DILUTED EPS, Per Share Amount	$ (0.94)	$ 0.15	$ (2.83)	$ 0.30

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Long-Term Debt (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Jun. 04, 2015	Dec. 31, 2014	Jul. 03, 2013	Aug. 19, 2010
Debt Instrument [Line Items]
Adjusted LIBO rate is equal to the rate at which dollar deposits	$ 11,700,000
Revolving credit facility	300,000,000
Borrowings outstanding under the Credit Agreement	0		$ 75,000,000
Letters of Credit Outstanding, Amount	0
Current borrowing base		$ 70,000,000
Aggregate commitments of the lenders	$ 70,000,000
At least secured percentage value of oil and gas properties	80.00%
Agreement bear interest at the alternate base rate	Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%.
Maximum
Debt Instrument [Line Items]
Commitment fees on a sliding scale	0.50%
Maximum ratio of total debt to EBITDAX (June 30, 2015 through December 31, 2016)	4.0
Maximum ratio of total debt to EBITDAX (thereafter)	3.5
Repurchase Company's common stock	$ 10,000,000
Minimum
Debt Instrument [Line Items]
Commitment fees on a sliding scale	0.375%
Current ratio	1.0
Borrower's liquidity	20.00%
Letters of Credit
Debt Instrument [Line Items]
Revolving credit facility	$ 25,000,000
Maturity date period minimum for refinanced debt after original maturity date	180 days
Alternate Base Rate | Maximum
Debt Instrument [Line Items]
Adjusted LIBO rate	1.75%
Alternate Base Rate | Minimum
Debt Instrument [Line Items]
Adjusted LIBO rate	0.75%
Adjusted LIBOR rate
Debt Instrument [Line Items]
Adjusted LIBO rate	1.00%
Variable rate, floor	0.00%
Adjusted LIBOR rate | Maximum
Debt Instrument [Line Items]
Adjusted LIBO rate	2.75%
Adjusted LIBOR rate | Minimum
Debt Instrument [Line Items]
Adjusted LIBO rate	1.75%
Federal Funds Effective Rate
Debt Instrument [Line Items]
Adjusted LIBO rate	0.50%
10% Senior Notes
Debt Instrument [Line Items]
Debt reduction by unencumbered and unrestricted net cash proceeds (maximum threshold)	$ 130,000,000
10% Senior Notes | Senior Notes
Debt Instrument [Line Items]
Principal amount				$ 200,000,000	$ 150,000,000
Interest rate of Senior Notes	10.00%		10.00%		10.00%

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Asset Retirement Obligation (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Changes to the Company's asset retirement obligation liability
Asset retirement obligation, beginning of period	$ 54,970	$ 48,536
Liabilities incurred	397	224
Liabilities settled	(1,186)	(1,149)
Accretion expense	1,682	1,499
Revisions in estimates	554	742
Divestiture of oil and gas properties	(1,794)	0
Asset retirement obligation, end of period	54,623	49,852
Less: current portion of asset retirement obligation	(1,405)	(2,959)	$ (2,756)
Long-term asset retirement obligation	$ 53,218	$ 46,893	$ 52,214

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Basis of Presentation

6 Months Ended

Jun. 30, 2015

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

Basis of Presentation

The consolidated financial information for the three and six month periods ended June 30, 2015 and 2014, 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, 2015 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, 2014 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, 2014.

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

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Ceiling Test (Details) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($) $ / mcf $ / bbl $ / Mcfe	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) $ / mcf $ / bbl $ / Mcfe	Jun. 30, 2014 USD ($)
Reserve Quantities [Line Items]
Rate for discounting future cash flows				10.00%
Average sales prices				3.20
Increase in ceiling test write-downs | $	$ (65,495)	$ (108,911)	$ 0	$ (174,406)	$ 0
Mcf of natural gas
Reserve Quantities [Line Items]
Average sales prices | $ / bbl		81.33		71.27
Barrel of oil
Reserve Quantities [Line Items]
Average sales prices		3.31
Mcfe of Ngl
Reserve Quantities [Line Items]
Average sales prices | $ / Mcfe		3.52		3.35
Commodity Derivatives | Cash Flow Hedging
Reserve Quantities [Line Items]
Increase in ceiling test write-downs | $				$ (1,000)

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Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 141,016	$ 18,243
Revenue receivable	7,750	16,485
Joint interest billing receivable	49,112	46,778
Other receivable	13,915	0
Derivative asset	6,247	8,631
Prepaid drilling costs	102	847
Other current assets	6,735	5,566
Total current assets	224,877	96,550
Oil and gas properties:
Oil and gas properties, full cost method	1,279,721	2,222,753
Unevaluated oil and gas properties	29,743	109,119
Accumulated depreciation, depletion and amortization	(1,040,886)	(1,648,060)
Oil and gas properties, net	268,578	683,812
Other property and equipment	15,087	14,953
Accumulated depreciation of other property and equipment	(10,998)	(10,313)
Total property and equipment	272,667	688,452
Other assets, net of accumulated depreciation and amortization of $8,997 and $7,847, respectively	5,528	5,893
Total assets	503,072	790,895
Current liabilities:
Accounts payable to vendors	62,761	102,954
Advances from co-owners	30,665	12,819
Oil and gas revenue payable	24,192	22,333
Accrued interest and preferred stock dividend	12,832	12,764
Asset retirement obligation	1,405	2,756
Derivative liability	572	0
Accrued acquisition cost	5,655	17,690
Other accrued liabilities	6,722	5,394
Total current liabilities	144,804	176,710
Bank debt	0	75,000
10% Senior Notes	350,000	350,000
Asset retirement obligation	53,218	52,214
Other long-term liability	$ 510	$ 62
Commitments and contingencies
Stockholders’ equity (deficit):
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares	$ 1	$ 1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 64,957 and 64,721 shares, respectively	65	65
Paid-in capital	288,767	285,957
Accumulated other comprehensive income	3,564	5,420
Accumulated deficit	(337,857)	(154,534)
Total stockholders’ equity (deficit)	(45,460)	136,909
Total liabilities and stockholders’ equity (deficit)	$ 503,072	$ 790,895

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Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net of income taxes	$ 2,046	$ 0	$ 1,099	$ 0

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Derivative Instruments (Details 2) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Recognized in Other Comprehensive Income	$ (3,454)	$ 860	$ (1,856)	$ (2,558)
Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Loss Recognized in Other Comprehensive Income	(1,471)	(1,982)	3,446	(8,803)
Oil and gas sales | Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified into Income	$ 4,029	$ (2,842)	$ 6,401	$ (6,245)

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Oil and gas contracts

As of June 30, 2015, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July 2015 - December 2015	Swap	40,000 Mmbtu	$3.62
July 2015 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2015 - September 2015	Swap	5,000 Mmbtu	$2.89
Crude Oil:
July 2015 - December 2015	Swap (LLS)	500 Bbls	$56.68
Propane:
July 2015 - December 2015	Swap	250 Bbls	$25.62

LLS - Louisiana Light Sweet

Effect of Cash Flow Hedges on the Consolidated Balance Sheet

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at June 30, 2015 and December 31, 2014:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
June 30, 2015	Derivative asset	$	6,247
June 30, 2015	Derivative liability	$	(572	)
December 31, 2014	Derivative asset	$	8,631

Effect of Cash Flow Hedges on the Consolidated Statement of Operations

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended June 30, 2015 and 2014:

Instrument	Amount of 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, 2015	$	(1,471	)	Oil and gas sales	$	4,029
Commodity Derivatives at June 30, 2014	$	(1,982	)	Oil and gas sales	$	(2,842	)

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the six months ended June 30, 2015 and 2014 :

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, 2015	$	3,446		Oil and gas sales	$	6,401
Commodity Derivatives at June 30, 2014	$	(8,803	)	Oil and gas sales	$	(6,245	)

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Derivative Instruments (Details Textual) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Accumulated other comprehensive income	$ 3,564,000	$ (3,654,000)	$ 3,564,000	$ (3,654,000)	$ 5,420,000	$ (4,514,000)	$ (1,096,000)
Realization of gain, net of taxes			3,600,000
Gas hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	4,181,000	(2,170,000)	6,505,000	(5,139,000)
Oil hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	(288,000)	(672,000)	(261,000)	(1,106,000)
Ngl hedges
Derivatives, Fair Value [Line Items]
Gain or loss recognized in oil and gas contracts	$ 136,000	$ 0	$ 157,000	$ 0

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Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

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

	Gains and Losses on Cash Flow Hedges
Balance as of March 31, 2015	$7,018
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,471	)
Income tax effect	547
Net of tax	(924	)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,029	)
Income tax effect	1,499
Net of tax	(2,530	)
Net other comprehensive loss	(3,454	)
Balance as of June 30, 2015	$3,564

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

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	3,446
Income tax effect	(1,282	)
Net of tax	2,164
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(6,401	)
Income tax effect	2,381
Net of tax	(4,020	)
Net other comprehensive loss	(1,856	)
Balance as of June 30, 2015	$3,564

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of March 31, 2014	($2,834)		($1,680)		($4,514)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,982	)	—		(1,982	)
Income tax effect	737		(737	)	—
Net of tax	(1,245	)	(737	)	(1,982	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	2,842		—		2,842
Income tax effect	(1,057	)	1,057		—
Net of tax	1,785		1,057		2,842
Net other comprehensive income	540		320		860
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of December 31, 2013	($688)		($408)		($1,096)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(8,803	)	—		(8,803	)
Income tax effect	3,275		(3,275	)	—
Net of tax	(5,528	)	(3,275	)	(8,803	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	6,245		—		6,245
Income tax effect	(2,323	)	2,323		—
Net of tax	3,922		2,323		6,245
Net other comprehensive loss	(1,606	)	(952	)	(2,558	)
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

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Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Cash flows from operating activities:
Net income (loss)	$ (180,756)	$ 22,202
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense	1,073	0
Depreciation, depletion and amortization	38,999	42,130
Ceiling test writedown	174,406	0
Accretion of asset retirement obligation	1,682	1,499
Share-based compensation expense	2,828	2,716
Amortization costs and other	1,162	1,094
Gain on sale of oil and gas properties	21,531	0
Payments to settle asset retirement obligations	(1,186)	(1,149)
Changes in working capital accounts:
Revenue receivable	8,735	455
Prepaid drilling costs	745	134
Joint interest billing receivable	(1,171)	8,589
Accounts payable and accrued liabilities	(36,051)	8,614
Advances from co-owners	17,846	15,438
Other	(1,155)	1,022
Net cash provided by operating activities	5,626	102,744
Cash flows provided by (used in) investing activities:
Investment in oil and gas properties	(62,451)	(76,993)
Investment in other property and equipment	(134)	(468)
Sale of oil and gas properties	257,698	600
Net cash provided by (used in) investing activities	195,113	(76,861)
Cash flows used in financing activities:
Net payments for share based compensation	432	1,039
Deferred financing costs	(829)	(109)
Payment of preferred stock dividend	(2,569)	(2,565)
Proceeds from bank borrowings	70,000	10,000
Repayment of bank borrowings	(145,000)	(12,500)
Net cash used in financing activities	(77,966)	(4,135)
Net increase in cash and cash equivalents	122,773	21,748
Cash and cash equivalents, beginning of period	18,243	9,153
Cash and cash equivalents, end of period	141,016	30,901
Cash paid (received) during the period for:
Interest	18,626	18,700
Income taxes (refunds)	$ (26)	$ 0

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Accumulated depreciation and amortization	$ 8,997	$ 7,847
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000,000	5,000,000
Preferred stock, shares issued	1,495,000	1,495,000
Preferred stock, shares outstanding	1,495,000	1,495,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	150,000,000	150,000,000
Common stock, shares issued	64,957,000	64,721,000
Common stock, shares outstanding	64,957,000	64,721,000
10% Senior Notes | Senior Notes
Stated interest rate	10.00%	10.00%

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Income Taxes

6 Months Ended

Jun. 30, 2015

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company typically provides for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes. As a result of ceiling test write-downs recognized, the Company has incurred a cumulative three year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $101.2 million as of June 30, 2015.

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		65,820,632

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Other Comprehensive Income

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Other Comprehensive Income

Other Comprehensive Income

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

	Gains and Losses on Cash Flow Hedges
Balance as of March 31, 2015	$7,018
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,471	)
Income tax effect	547
Net of tax	(924	)
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(4,029	)
Income tax effect	1,499
Net of tax	(2,530	)
Net other comprehensive loss	(3,454	)
Balance as of June 30, 2015	$3,564

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

	Gains and Losses on Cash Flow Hedges
Balance as of December 31, 2014	$5,420
Other comprehensive income before reclassifications:
Change in fair value of derivatives	3,446
Income tax effect	(1,282	)
Net of tax	2,164
Amounts reclassified from accumulated other comprehensive income:
Oil and gas sales	(6,401	)
Income tax effect	2,381
Net of tax	(4,020	)
Net other comprehensive loss	(1,856	)
Balance as of June 30, 2015	$3,564

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the three month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of March 31, 2014	($2,834)		($1,680)		($4,514)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(1,982	)	—		(1,982	)
Income tax effect	737		(737	)	—
Net of tax	(1,245	)	(737	)	(1,982	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	2,842		—		2,842
Income tax effect	(1,057	)	1,057		—
Net of tax	1,785		1,057		2,842
Net other comprehensive income	540		320		860
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the six month period ended June 30, 2014 (in thousands):

	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance		Total
Balance as of December 31, 2013	($688)		($408)		($1,096)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	(8,803	)	—		(8,803	)
Income tax effect	3,275		(3,275	)	—
Net of tax	(5,528	)	(3,275	)	(8,803	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	6,245		—		6,245
Income tax effect	(2,323	)	2,323		—
Net of tax	3,922		2,323		6,245
Net other comprehensive loss	(1,606	)	(952	)	(2,558	)
Balance as of June 30, 2014	($2,294)		($1,360)		($3,654)

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Consolidated Statements of Operations (Unaudited) - USD ($) shares in Thousands, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues:
Oil and gas sales	$ 32,550	$ 60,581	$ 66,001	$ 120,547
Expenses:
Lease operating expenses	11,191	12,168	22,093	24,426
Production taxes	948	1,492	1,904	2,969
Depreciation, depletion and amortization	18,345	21,702	38,999	42,130
Ceiling test write-down	65,495	0	174,406	0
General and administrative	6,519	6,467	11,858	12,709
Accretion of asset retirement obligation	823	708	1,682	1,499
Interest expense	8,596	7,380	16,470	15,016
Expenses	111,917	49,917	267,412	98,749
Other income:
Gain on sale of oil and gas properties	21,531	0	21,531	0
Other income	40	215	197	404
Income (loss) from operations	(57,796)	10,879	(179,683)	22,202
Income tax expense	2,000	0	1,073	0
Net income (loss)	(59,796)	10,879	(180,756)	22,202
Preferred stock dividend	1,287	1,287	2,567	2,567
Income (loss) available to common stockholders	$ (61,083)	$ 9,592	$ (183,323)	$ 19,635
Basic
Net income per share (in usd per share)	$ (0.94)	$ 0.15	$ (2.83)	$ 0.30
Diluted
Net income per share (in usd per share)	$ (0.94)	$ 0.15	$ (2.83)	$ 0.30
Weighted average number of common shares:
Basic (shares)	64,891	64,103	64,833	63,940
Diluted (shares)	64,891	64,167	64,833	63,996

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Long-Term Debt

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

On August 19, 2010, the Company issued $150 million in principal amount of its 10% Senior Notes due 2017 (the “Existing Notes”). On July 3, 2013, the Company issued an additional $200 million in principal amount of its 10% Senior Notes due 2017 (the "New Notes" and together with the Existing Notes, the "Notes"). The New Notes were issued at a price equal to 100% of face value plus accrued interest from March 1, 2013 and are substantially identical to the Existing Notes. The Notes are guaranteed by certain of PetroQuest's subsidiaries. The subsidiary guarantors are 100% owned by PetroQuest and all guarantees are full and unconditional and joint and several. PetroQuest has no independent assets or operations and the subsidiaries not providing guarantees are minor, as defined by the rules of the Securities and Exchange Commission.

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, 2015, $11.7 million had been accrued in connection with the September 1, 2015 interest payment and the Company was in compliance with all of the covenants contained in the Notes. Pursuant to the asset sale covenant of the Notes, if we do not use certain of the proceeds of the Woodford and Mississippian Lime divestiture to repay senior indebtedness or to acquire additional assets or make capital expenditures in the oil and gas business within one year of the divestiture, we will be required to use such proceeds to make an offer to the holders of the Notes to repurchase the Notes at a purchase price of 100% of their principal amount, without premium, plus accrued but unpaid interest.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., IberiaBank, Bank of America, N.A. and The Bank of Nova Scotia. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on the earlier of June 4, 2020 or February 19, 2017 if any portion of the Company’s 10% Senior Notes due 2017 remains outstanding as of such date which has not been refinanced with either permitted refinancing debt or permitted second lien debt with a maturity date no earlier than 180 days after June 4, 2020, all as defined in the Credit Agreement. As of June 30, 2015 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

The borrowing base under the Credit Agreement is 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. In connection with the most recent redetermination related to the Sold Assets, the borrowing base was reduced to $70 million (subject to the aggregate commitments of the lenders then in effect) effective June 4, 2015. The aggregate commitments of the lenders is currently $70 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next scheduled borrowing base redetermination, which was scheduled to occur by September 30, 2015, has been waived and additional interim borrowing base redeterminations have been scheduled to occur by September 1, 2015 and December 1, 2015. 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 Borrower’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 0.75% to 1.75% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.75% to 2.75% depending on total commitments). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate (subject to a floor of 0.0%) plus 1%.  For the purposes of the definition of alternate base rate only, the adjusted LIBO rate for any day is based on the LIBO Rate at approximately 11:00 a.m. London time on such day. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees based on a sliding scale of 0.375% to 0.5% depending on total commitments.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 4.0 to 1.0 as of the last day of the fiscal quarters ending June 30, 2015 through December 31, 2016 and 3.5 to 1.0 as of the last day of any fiscal quarter ending thereafter, in each case determined on a rolling four quarter basis, and to provide that the amount of total debt for the four consecutive fiscal quarter periods ending June 30, 2015, September 30, 2015 and December 31, 2015 shall be reduced by the amount of unencumbered and unrestricted net cash proceeds received by the Company from the Sold Assets (such reduction amount not to exceed $130,000,000 for so long as the Company has not redeemed, in whole or in part, its 10% Senior Notes due 2017), and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of June 30, 2015, the Company was in compliance with all such covenants contained in the Credit Agreement.

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Earnings Per Share

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

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

For the Three Months Ended June 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(61,083	)	64,891	$	(0.94	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(61,083	)	64,891	$	(0.94	)
For the Six Months Ended June 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(183,323	)	64,833	$	(2.83	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(183,323	)	64,833	$	(2.83	)
For the Three Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	9,592		64,103
Attributable to participating securities	(273		)
BASIC EPS	$	9,319		64,103	$	0.15
Net income available to common stockholders	$	9,592		64,103
Effect of dilutive securities:
Stock options	—			64
Attributable to participating securities	(273		)	—
DILUTED EPS	$	9,319		64,167	$	0.15
For the Six Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	19,635		63,940
Attributable to participating securities	(571		)
BASIC EPS	$	19,064		63,940	$	0.30
Net income available to common stockholders	$	19,635		63,940
Effect of dilutive securities:
Stock options	—			56
Attributable to participating securities	(571		)	—
DILUTED EPS	$	19,064		63,996	$	0.30

An aggregate of 0.4 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three and six month periods ended June 30, 2015, respectively, because the inclusion would have been anti-dilutive as a result of the net loss reported for such periods. Options to purchase 1.4 million and 1.5 million shares of common stock were outstanding during the three and six month periods ended June 30, 2015, 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.

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three and six month periods ended June 30, 2014, respectively, because the inclusion would have been anti-dilutive. Options to purchase 0.9 million and 1.1 million shares of common stock were outstanding during the three and six months ended June 30, 2014, 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.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

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

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of June 30, 2015 and December 31, 2014 (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:
June 30, 2015	$	—	$	5,675	$	—
December 31, 2014	$	—	$	8,631	$	—

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Recently Issued Accounting Standards

6 Months Ended

Jun. 30, 2015

Accounting Changes and Error Corrections [Abstract]

Recently Issued Accounting Standards

Recently Issued Accounting Standards

In April 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2015-03, "Simplifying the Presentation of Debt Issuance Costs" ("ASU 2015-03") which changes the presentation of debt issuance costs in financial statements to present such costs as a direct deduction from the related debt liability rather than as an asset. ASU 2015-03 will become effective for public companies during interim and annual reporting periods beginning after December 15, 2015. Early adoption is permitted. We do not expect the adoption of ASU 2015-03 will have a material impact on our consolidated financial statements.

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Derivative Instruments

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At June 30, 2015, all of the Company's derivative instruments were designated as effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $4,181,000 and ($2,170,000), oil hedges of ($288,000) and ($672,000) and Ngl hedges of $136,000 and zero for the three months endedJune 30, 2015 and 2014, respectively. For the six month periods ended June 30, 2015 and 2014, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $6,505,000 and ($5,139,000), oil hedges of ($261,000) and ($1,106,000) and Ngl hedges of $157,000zero, respectively.

As of June 30, 2015, the Company had entered into the following commodity derivative instruments:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
July 2015 - December 2015	Swap	40,000 Mmbtu	$3.62
July 2015 - June 2016	Swap	10,000 Mmbtu	$3.22
July 2015 - September 2015	Swap	5,000 Mmbtu	$2.89
Crude Oil:
July 2015 - December 2015	Swap (LLS)	500 Bbls	$56.68
Propane:
July 2015 - December 2015	Swap	250 Bbls	$25.62

LLS - Louisiana Light Sweet

At June 30, 2015, the Company had recognized accumulated other comprehensive income of approximately $3.6 million related to the estimated fair value of its effective cash flow hedges. Based on estimated future commodity prices as of June 30, 2015, the Company would reclassify approximately $3.6 million, net of taxes, of accumulated other comprehensive income into earnings during the next 12 months. These gains are expected to be reclassified to oil and gas sales based on the schedule of oil and gas volumes stipulated in the derivative contracts.

Derivatives designated as hedging instruments:

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

Effect of Cash Flow Hedges on the Consolidated Balance Sheet at June 30, 2015 and December 31, 2014:

	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
June 30, 2015	Derivative asset	$	6,247
June 30, 2015	Derivative liability	$	(572	)
December 31, 2014	Derivative asset	$	8,631

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the three months ended June 30, 2015 and 2014:

Instrument	Amount of 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, 2015	$	(1,471	)	Oil and gas sales	$	4,029
Commodity Derivatives at June 30, 2014	$	(1,982	)	Oil and gas sales	$	(2,842	)

Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the six months ended June 30, 2015 and 2014 :

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, 2015	$	3,446		Oil and gas sales	$	6,401
Commodity Derivatives at June 30, 2014	$	(8,803	)	Oil and gas sales	$	(6,245	)

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Asset Retirement Obligation

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligation

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

	Six Months Ended June 30,
	2015			2014
Asset retirement obligation, beginning of period	$	54,970		$	48,536
Liabilities incurred	397			224
Liabilities settled	(1,186		)	(1,149		)
Accretion expense	1,682			1,499
Revisions in estimates	554			742
Divestiture of oil and gas properties	(1,794		)	—
Asset retirement obligation, end of period	54,623			49,852
Less: current portion of asset retirement obligation	(1,405		)	(2,959		)
Long-term asset retirement obligation	$	53,218		$	46,893

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Ceiling Test

6 Months Ended

Jun. 30, 2015

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Ceiling Test

Ceiling Test

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

In accordance with SEC requirements, the estimated future net cash flows from estimated proved reserves are based on an average of the first day of the month spot price for a historical 12-month period, adjusted for quality, transportation fees and market differentials. At March 31, 2015 and June 30, 2015, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $3.31 and $3.20 per Mcf of natural gas, $81.33 and $71.27 per barrel of oil and $3.52 and $3.35 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of approximately $108.9 million and $65.5 million during the three months ended March 31, 2015 and June 30, 2015, respectively. The Company’s cash flow hedges in place at June 30, 2015 increased the ceiling test write-down by approximately $1 million.

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Fair Value Measurements

6 Months Ended

Jun. 30, 2015

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

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

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at June 30, 2015 were in the form of swaps based on NYMEX pricing for oil and natural gas and OPIS Mt. Belvieu pricing for natural gas liquids. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of June 30, 2015 and December 31, 2014 (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:
June 30, 2015	$	—	$	5,675	$	—
December 31, 2014	$	—	$	8,631	$	—

The fair value of the Company's cash and cash equivalents and variable-rate bank debt approximated book value at June 30, 2015 and December 31, 2014. The fair value of the Notes was approximately $327 million and $301 million as of June 30, 2015 and December 31, 2014, respectively, as compared to the book value of $350 million as of each date. The fair value of the Notes was determined based upon a market quote provided by an independent broker, which represents a Level 2 input.

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Derivative Instruments (Details 1) - Commodity Derivatives - Designated as Hedging Instrument - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets
Derivatives, Fair Value [Line Items]
Derivative asset	$ 6,247	$ 8,631
Current Liabilities
Derivatives, Fair Value [Line Items]
Derivative liability	$ (572)

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Asset Retirement Obligation (Tables)

6 Months Ended

Jun. 30, 2015

Asset Retirement Obligation Disclosure [Abstract]

Changes to the Company's asset retirement obligation liability

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

	Six Months Ended June 30,
	2015			2014
Asset retirement obligation, beginning of period	$	54,970		$	48,536
Liabilities incurred	397			224
Liabilities settled	(1,186		)	(1,149		)
Accretion expense	1,682			1,499
Revisions in estimates	554			742
Divestiture of oil and gas properties	(1,794		)	—
Asset retirement obligation, end of period	54,623			49,852
Less: current portion of asset retirement obligation	(1,405		)	(2,959		)
Long-term asset retirement obligation	$	53,218		$	46,893

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Acquisitions and Divestitures - Divestiture (Woodford and Mississippian Lime) (Details) $ in Thousands, MMcfe in Millions		3 Months Ended		6 Months Ended
	Jun. 04, 2015 USD ($) well term	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)	Dec. 31, 2014 USD ($) MMcfe
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other receivable		$ 13,915		$ 13,915		$ 0
Gain on sale of oil and gas properties		21,531	$ 0	21,531	$ 0
Woodford and Mississippian Lime
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Net proceeds from sale of a majority of interests	$ 280,000
Cash received from sale	$ 257,700
Period the adjusted purchase price to be received within	180 days
Number of renewal terms for contract operator | term	2
Contract operator term for sold assets	1 year
Number of first spudded wells | well	14
Deferred sales proceeds	$ 1,000
Proved reserves | MMcfe						227
Estimated proved reserves attributable to Sold Assets (percent of total)						57.00%
Current Assets | Woodford and Mississippian Lime
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other receivable		$ 13,900		$ 13,900

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Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (59,796)	$ 10,879	$ (180,756)	$ 22,202
Change in fair value of derivative instruments, accounted for as hedges, net of income tax benefit of $2,046, $0, $1,099, and $0, respectively	(3,454)	860	(1,856)	(2,558)
Comprehensive income (loss)	$ (63,250)	$ 11,739	$ (182,612)	$ 19,644

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Convertible Preferred Stock

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Convertible Preferred Stock

Convertible Preferred Stock

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

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

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

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

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

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

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Convertible Preferred Stock (Details) - USD ($)	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014
Equity [Abstract]
Preferred stock, shares outstanding	1,495,000	1,495,000
Series B cumulative convertible perpetual preferred stock interest rate	6.875%
Number of trading days	20 days
Number of consecutive trading days	30 days
Closing price as percentage of conversion price	130.00%
Series B Preferred Stock converted into common stock (in shares)	3.4433
Initial conversion price of common stock (in usd per share)	$ 14.52
Applicable settlement terms	If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.
Trading day averaging period for determining conversion value	20 days
Conversion rate numerator for Preferred Stock	$ 50

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Income Taxes (Details) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Income Taxes (Textual) [Abstract]
Income taxes at a statutory rate	35.00%
Cumulative loss period	3 years
Valuation allowance	$ 101.2

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

A reconciliation between basic and diluted earnings per share computations

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

For the Three Months Ended June 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(61,083	)	64,891	$	(0.94	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(61,083	)	64,891	$	(0.94	)
For the Six Months Ended June 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(183,323	)	64,833	$	(2.83	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(183,323	)	64,833	$	(2.83	)
For the Three Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	9,592		64,103
Attributable to participating securities	(273		)
BASIC EPS	$	9,319		64,103	$	0.15
Net income available to common stockholders	$	9,592		64,103
Effect of dilutive securities:
Stock options	—			64
Attributable to participating securities	(273		)	—
DILUTED EPS	$	9,319		64,167	$	0.15
For the Six Months Ended June 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	19,635		63,940
Attributable to participating securities	(571		)
BASIC EPS	$	19,064		63,940	$	0.30
Net income available to common stockholders	$	19,635		63,940
Effect of dilutive securities:
Stock options	—			56
Attributable to participating securities	(571		)	—
DILUTED EPS	$	19,064		63,996	$	0.30