PETROQUEST ENERGY INC - FORM 10-Q

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EX-31.1 - EXHIBIT 31.1 - PETROQUEST ENERGY INC	pq9301510qex311.htm
EX-32.2 - EXHIBIT 32.2 - PETROQUEST ENERGY INC	pq9301510qex322.htm
EX-32.1 - EXHIBIT 32.1 - PETROQUEST ENERGY INC	pq9301510qex321.htm
EX-31.2 - EXHIBIT 31.2 - PETROQUEST ENERGY INC	pq9301510qex312.htm

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended: September 30, 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 October 30, 2015 there were 65,955,944 shares of the registrant’s common stock, par value $.001 per share, outstanding.

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PETROQUEST ENERGY, INC.

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	Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	1

Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2015 and 2014	2

Consolidated Statements of Comprehensive Income for the Three and Nine Months Ended September 30, 2015 and 2014	3

Consolidated Statements of Cash Flows for the Nine Months Ended September 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	22

Item 4. Controls and Procedures	23

Part II. Other Information

Item 1. Legal Proceedings	23

Item 1A. Risk Factors	23

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	26

Item 3. Defaults upon Senior Securities	26

Item 4. Mine Safety Disclosures	26

Item 5. Other Information	26

Item 6. Exhibits	27

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PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)



	September 30, 2015			December 31, 2014
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	158,572		$	18,243
Revenue receivable	8,667			16,485
Joint interest billing receivable	28,699			46,778
Derivative asset	5,659			8,631
Other current assets	6,936			6,413
Total current assets	208,533			96,550
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method	1,285,971			2,222,753
Unevaluated oil and gas properties	28,524			109,119
Accumulated depreciation, depletion and amortization	(1,095,002		)	(1,648,060		)
Oil and gas properties, net	219,493			683,812
Other property and equipment	15,383			14,953
Accumulated depreciation of other property and equipment	(11,367		)	(10,313		)
Total property and equipment	223,509			688,452
Other assets, net of accumulated depreciation and amortization of $9,514 and $7,847, respectively	4,929			5,893
Total assets	$	436,971		$	790,895
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	67,265		$	102,954
Advances from co-owners	24,850			12,819
Oil and gas revenue payable	28,800			22,333
Accrued interest and preferred stock dividend	4,056			12,764
Asset retirement obligation	5,378			2,756
Accrued acquisition cost	4,790			17,690
Other accrued liabilities	4,300			5,394
Total current liabilities	139,439			176,710
Bank debt	—			75,000
10% Senior Notes	350,000			350,000
Asset retirement obligation	43,217			52,214
Other long-term liability	396			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 65,068 and 64,721 shares, respectively	65			65
Paid-in capital	290,066			285,957
Accumulated other comprehensive income	3,554			5,420
Accumulated deficit	(389,767		)	(154,534		)
Total stockholders’ equity (deficit)	(96,081		)	136,909
Total liabilities and stockholders’ equity (deficit)	$	436,971		$	790,895

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2015			2014
Revenues:
Oil and gas sales	$	26,872		$	56,486		$	92,873		$	177,033
Expenses:
Lease operating expenses	10,070			13,019			32,163			37,445
Production taxes	399			1,709			2,303			4,678
Depreciation, depletion and amortization	13,687			22,294			52,686			64,424
Ceiling test write-down	40,212			—			214,618			—
General and administrative	4,686			6,319			16,544			19,028
Accretion of asset retirement obligation	825			724			2,507			2,223
Interest expense	8,526			7,050			24,996			22,066
	78,405			51,115			345,817			149,864
Gain on sale of oil and gas properties	828			—			22,359			—
Other income	88			198			285			602
Income (loss) from operations	(50,617		)	5,569			(230,300		)	27,771
Income tax expense (benefit)	6			(389		)	1,079			(389		)
Net income (loss)	(50,623		)	5,958			(231,379		)	28,160
Preferred stock dividend	1,287			1,287			3,854			3,854
Income (loss) available to common stockholders	$	(51,910	)	$	4,671		$	(235,233	)	$	24,306
Earnings per common share:
Basic
Net income (loss) per share	$	(0.80	)	$	0.07		$	(3.62	)	$	0.37
Diluted
Net income (loss) per share	$	(0.80	)	$	0.07		$	(3.62	)	$	0.37
Weighted average number of common shares:
Basic	65,035			64,265			64,901			64,073
Diluted	65,035			64,352			64,901			64,128

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)



	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2015			2014		2015			2014
Net income (loss)	$	(50,623	)	$	5,958	$	(231,379	)	$	28,160
Change in fair value of derivative instruments, accounted for as hedges, net of income tax expense (benefit) of ($6), $520, ($1,105), and $520, respectively	(10		)	4,533		(1,866		)	1,975
Comprehensive income (loss)	$	(50,633	)	$	10,491	$	(233,245	)	$	30,135

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)



	Nine Months Ended
	September 30,
	2015			2014
Cash flows from operating activities:
Net income (loss)	$	(231,379	)	$	28,160
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	1,079			(389		)
Depreciation, depletion and amortization	52,686			64,424
Ceiling test writedown	214,618			—
Accretion of asset retirement obligation	2,507			2,223
Share-based compensation expense	4,022			4,025
Amortization costs and other	1,679			1,636
Payments to settle asset retirement obligations	(1,826		)	(2,902		)
Gain on sale of oil and gas properties	(22,359		)	—
Changes in working capital accounts:
Revenue receivable	7,818			2,353
Joint interest billing receivable	20,147			1,279
Accounts payable and accrued liabilities	(36,630		)	6,561
Advances from co-owners	12,031			15,881
Other	(414		)	2,610
Net cash provided by operating activities	23,979			125,861
Cash flows provided by (used in) investing activities:
Investment in oil and gas properties	(75,818		)	(133,048		)
Investment in other property and equipment	(430		)	(860		)
Sale of oil and gas properties	271,891			10,204
Net cash provided by (used in) investing activities	195,643			(123,704		)
Cash flows used in financing activities:
Net payments for share based compensation	422			651
Deferred financing costs	(861		)	(204		)
Payment of preferred stock dividend	(3,854		)	(3,854		)
Proceeds from bank borrowings	70,000			10,000
Repayment of bank borrowings	(145,000		)	(12,500		)
Net cash used in financing activities	(79,293		)	(5,907		)
Net increase (decrease) in cash and cash equivalents	140,329			(3,750		)
Cash and cash equivalents, beginning of period	18,243			9,153
Cash and cash equivalents, end of period	$	158,572		$	5,403
Supplemental disclosure of cash flow information:
Cash paid (received) during the period for:
Interest	$	36,137		$	36,606
Income taxes (refunds)	$	(26	)	$	132

See accompanying Notes to Consolidated Financial Statements.

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PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1—Basis of Presentation

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

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

Note 2—Acquisitions and Divestitures

Acquisition:

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

The purchase price was comprised of $10 million in cash and $14 million in cash funding for future drilling, completion and lease acquisition costs. 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 the Company's joint venture partner. At September 30, 2015, $4.8 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, which was received in full during the third quarter.

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.

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 during the second quarter of 2015. 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. As a result of purchase price adjustments, the Company recognized an additional gain on the sale of $0.8 million during the third quarter of 2015.

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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.

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Note 4—Earnings Per Share

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



For the Three Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(51,910	)	65,035	$	(0.80	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(51,910	)	65,035	$	(0.80	)

For the Nine Months Ended September 30, 2015	Loss (Numerator)			Shares (Denominator)	Per Share Amount
BASIC EPS
Net loss available to common stockholders	$	(235,233	)	64,901	$	(3.62	)
Stock options	—			—
Attributable to participating securities	—			—
DILUTED EPS	$	(235,233	)	64,901	$	(3.62	)

For the Three Months Ended September 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	4,671		64,265
Attributable to participating securities	(123		)
BASIC EPS	$	4,548		64,265	$	0.07

Net income available to common stockholders	$	4,671		64,265
Effect of dilutive securities:
Stock options	—			87
Attributable to participating securities	(123		)	—
DILUTED EPS	$	4,548		64,352	$	0.07

For the Nine Months Ended September 30, 2014	Income (Numerator)			Shares (Denominator)	Per Share Amount
Net income available to common stockholders	$	24,306		64,073
Attributable to participating securities	(649		)
BASIC EPS	$	23,657		64,073	$	0.37

Net income available to common stockholders	$	24,306		64,073
Effect of dilutive securities:
Stock options	—			55
Attributable to participating securities	(649		)	—
DILUTED EPS	$	23,657		64,128	$	0.37

An aggregate of 0.3 million and 0.4 million shares of common stock representing options to purchase common stock and unvested shares of restricted common stock and common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5.1 million shares were not included in the computation of diluted earnings per share for the three and nine month periods ended September 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 0.9 million and 1.4 million shares of common stock were outstanding during the three and nine month periods ended September 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.

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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 nine month periods ended September 30, 2014, respectively, because the inclusion would have been anti-dilutive. Options to purchase 0.9 million and 1.0 million shares of common stock were outstanding during the three and nine months ended September 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 September 30, 2015, $2.9 million had been accrued in connection with the March 1, 2016 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 the Company does 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, the Company 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 September 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, the borrowing base was reduced to $55 million (subject to the aggregate commitments of the lenders then in effect) effective September 8, 2015. The aggregate commitments of the lenders is currently $55 million. The next scheduled borrowing base redetermination is scheduled to occur by 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 90% 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 (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) 4.0 to 1.0 as of the last day of the fiscal quarter ending September 30, 2015, with the amount of total debt for such quarterly period reduced by the amount of

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unencumbered and unrestricted net cash proceeds actually received by the Company from the Sold Assets (such reduction amount not to exceed $130,000,000), (b) if the Company has unused availability greater than or equal to 75% of the aggregate commitments of the Lenders at all times during the consecutive three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 4.5 to 1.0 as of the last day of the fiscal quarters ending December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016, and 4.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, with in each case the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted cash of the Company, (c) if the Company has unused availability of less than 75% of the aggregate commitments of the Lenders at any time during the consecutive three month period prior to and including the date of calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.0 as of the last day of the fiscal quarters ending December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, and (d) 5.0 to 1.0 as of the last day of any fiscal quarter ending on or after March 31, 2017 and (ii) a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement.

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



	Nine Months Ended September 30,
	2015			2014
Asset retirement obligation, beginning of period	$	54,970		$	48,536
Liabilities incurred	392			224
Liabilities settled	(1,826		)	(2,902		)
Accretion expense	2,507			2,223
Revisions in estimates	(5,345		)	743
Divestiture of oil and gas properties	(2,103		)	—
Asset retirement obligation, end of period	48,595			48,824
Less: current portion of asset retirement obligation	(5,378		)	(1,426		)
Long-term asset retirement obligation	$	43,217		$	47,398

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 September 30, 2015, the prices used in computing the estimated future net cash flows from the Company’s estimated proved reserves, including the effect of hedges in place at that date, averaged $2.89 per Mcf of natural gas, $59.71 per barrel of oil and $2.70 per Mcfe of Ngl. As a result of lower commodity prices and their negative impact on the Company's estimated proved reserves and estimated future net cash flows, the Company recognized ceiling test write-downs of approximately $40.2 million and $214.6 million during the three and nine months ended September 30, 2015, respectively. The Company’s cash flow hedges in place at September 30, 2015 decreased the ceiling test write-down by approximately $2.2 million.

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Note 8—Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. When the conditions for hedge accounting are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a derivative does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income (expense). At September 30, 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 $3,603,000 and $337,000, oil hedges of $299,000 and ($125,000) and Ngl hedges of $191,000 and $28,000 for the three months ended September 30, 2015 and 2014, respectively. For the nine month periods ended September 30, 2015 and 2014, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $10,108,000 and ($4,802,000), oil hedges of $38,000 and ($1,231,000) and Ngl hedges of $348,000 and $28,000, respectively.

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



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

LLS - Louisiana Light Sweet

At September 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 September 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 September 30, 2015 and December 31, 2014:



	Commodity Derivatives
Period	Balance Sheet Location	Fair Value
September 30, 2015	Derivative asset	$	5,659
December 31, 2014	Derivative asset	$	8,631

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



Instrument	Amount of Gain Recognized in Other Comprehensive Income		Location of Gain Reclassified into Income	Amount of Gain Reclassified into Income
Commodity Derivatives at September 30, 2015	$	4,077	Oil and gas sales	$	4,093
Commodity Derivatives at September 30, 2014	$	5,293	Oil and gas sales	$	240

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Effect of Cash Flow Hedges on the Consolidated Statement of Operations for the nine months ended September 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 September 30, 2015	$	7,523		Oil and gas sales	$	10,494
Commodity Derivatives at September 30, 2014	$	(3,510	)	Oil and gas sales	$	(6,005	)

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 September 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 September 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:
September 30, 2015	$	—	$	5,659	$	—
December 31, 2014	$	—	$	8,631	$	—

The fair value of the Company's cash and cash equivalents approximated book value at September 30, 2015 and December 31, 2014. The Company had no variable rate bank debt as of September 30, 2015 and the fair value of the variable rate bank debt approximated book value as of December 31, 2014.The fair value of the Notes was approximately $303 million and $301 million as of September 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 $121 million as of September 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 September 30, 2015 (in thousands):



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

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



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

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



	Gains and Losses on Cash Flow Hedges		Change in Valuation Allowance	Total
Balance as of June 30, 2014	($2,294)		($1,360)	($3,654)
Other comprehensive loss before reclassifications:
Change in fair value of derivatives	5,293		—	5,293
Income tax effect	(1,969	)	1,360	(609	)
Net of tax	3,324		1,360	4,684
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	(240	)	—	(240	)
Income tax effect	89		—	89
Net of tax	(151	)	—	(151	)
Net other comprehensive income	3,173		1,360	4,533
Balance as of September 30, 2014	$879		$0	$879

The following table represents the changes in accumulated other comprehensive income (loss), net of tax, for the nine month period ended September 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	(3,510	)	—		(3,510	)
Income tax effect	1,395		(2,004	)	(609	)
Net of tax	(2,115	)	(2,004	)	(4,119	)
Amounts reclassified from accumulated other comprehensive loss:
Oil and gas sales	6,005		—		6,005
Income tax effect	(2,323	)	2,412		89
Net of tax	3,682		2,412		6,094
Net other comprehensive income	1,567		408		1,975
Balance as of September 30, 2014	$879		$0		$879

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. The Company does not expect the adoption of ASU 2015-03 will have a material impact on its consolidated financial statements.

In August 2015, the FASB issued Accounting Standards Update No. 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements". (“ASU 2015-15”), which was issued to clarify the guidance included in ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", described above. ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. Given the absence of authoritative guidance within ASU 2015-03 for debt issuance costs related to line-of-credit arrangements, ASU 2015-15 was issued

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to clarify that the SEC staff would not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This ASU is effective for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The Company does not expect the adoption of ASU 2015-15 will have a material impact on its consolidated financial statements.

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with primary operations in Texas and the Gulf Coast Basin and Oklahoma. 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, which was received in full during the third quarter. 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 September 30, 2015, we had $159 million of cash on hand and had no borrowings outstanding under our bank credit facility. We are presently evaluating deleveraging and refinancing options with respect to our 10% Senior Notes due 2017, as well as resuming drilling activity in the Cotton Valley play. 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,

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such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.

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

Full Cost Method of Accounting

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

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

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

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

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

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices 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

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and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Derivative Instruments

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 September 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 September 30,				Nine Months Ended September 30,
	2015		2014		2015		2014
Production:
Oil (Bbls)	123,102		170,014		421,539		642,511
Gas (Mcf)	5,395,789		8,153,145		20,478,563		23,033,254
Ngl (Mcfe)	1,297,566		2,397,236		4,458,392		5,186,794
Total Production (Mcfe)	7,431,967		11,570,465		27,466,189		32,075,114
Sales:
Total oil sales	$	6,073,709	$	16,670,934	$	21,613,942	$	64,279,648
Total gas sales	17,737,112		29,109,608		59,314,437		87,469,799
Total ngl sales	3,060,948		10,705,208		11,944,564		25,283,882
Total oil, gas, and ngl sales	$	26,871,769	$	56,485,750	$	92,872,943	$	177,033,329
Average sales prices:
Oil (per Bbl)	$	49.34	$	98.06	$	51.27	$	100.04
Gas (per Mcf)	3.29		3.57		2.90		3.80
Ngl (per Mcfe)	2.36		4.47		2.68		4.87
Per Mcfe	3.62		4.88		3.38		5.52

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $3,603,000 and $337,000, oil hedges of $299,000 and ($125,000) and Ngl hedges of $191,000 and $28,000 for the three months ended September 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 $10,108,000 and ($4,802,000), oil hedges of $38,000 and ($1,231,000) and Ngl hedges of $348,000 and $28,000 for the nine months ended September 30, 2015 and 2014, respectively. Please see Item 3. Quantitative and Qualitative Disclosures About Market Risk in this Form 10-Q for further details on our hedging program and our current hedging arrangements.

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Net income (loss) available to common stockholders totaled ($51,910,000) and $4,671,000 for the quarters ended September 30, 2015 and 2014, respectively, while net income (loss) available to common stockholders totaled ($235,233,000) and $24,306,000 for the nine months ended September 30, 2015 and 2014, respectively. The primary fluctuations were as follows:

Production Total production decreased 36% and 14% during the three and nine month periods ended September 30, 2015, respectively, as compared to the 2014 periods. The decrease in total production was primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 and normal production declines at our Gulf Coast fields. Partially offsetting the decrease was the successful drilling program in our Carthage field as well as our Thunder Bayou discovery. 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 September 30, 2015 decreased 34% from the comparable period in 2014. The decrease was primarily the result of the divestment of a majority of our Oklahoma assets on June 4, 2015 and normal production declines at our Gulf Coast fields. Partially offsetting the decrease was the successful completion of our Thunder Bayou discovery. Gas production during the nine month period ended September 30, 2015 decreased 11% from the comparable period in 2014 as the result of the the effect of our Oklahoma divestment and normal production declines at our Gulf Coast fields, partially offset by the successful drilling program in our Carthage field and the completion of our Thunder Bayou discovery. 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 nine month periods ended September 30, 2015 decreased 28% and 34%, 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 and downtime at certain of our 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 September 30, 2015 decreased 46% from the respective 2014 period primarily due to our Oklahoma divestment and normal production declines at our Carthage field. Offsetting the decrease was the successful completion of our Thunder Bayou discovery. Ngl production during the nine month period ended September 30, 2015 decreased 14% from the comparable 2014 period due to our Oklahoma divestment and normal production declines at our Gulf Coast fields, partially offset by the successful drilling program in our Carthage field and the completion of our Thunder Bayou discovery. 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 nine month periods ended September 30, 2015 were $3.29 and $2.90 as compared to $3.57 and $3.80 for the respective 2014 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2015 were $49.34 and $51.27 as compared to $98.06 and $100.04 for the respective 2014 periods and average Ngl prices per Mcfe were $2.36 and $2.68 for the three and nine months ended September 30, 2015, as compared to $4.47 and $4.87 for the respective 2014 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2015 were 26% and 39% 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 ended September 30, 2015 decreased 52% to $26,872,000, as compared to oil and gas sales of $56,486,000 during the 2014 period. Including the effects of hedges, oil and gas sales during the nine months ended September 30, 2015 decreased 48% to $92,873,000, as compared to oil and gas sales of $177,033,000 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 nine months ended September 30, 2015 totaled $10,070,000 and $32,163,000, respectively, as compared to $13,019,000 and $37,445,000 during the respective 2014 periods. Per unit lease operating expenses totaled $1.35 and $1.17 per Mcfe, respectively, during the three and nine month periods ended September 30, 2015 as compared to $1.13 and $1.17 per Mcfe during the respective 2014 periods. Total lease operating expenses decreased during the three and nine months ended September 30, 2015 primarily as result of our Oklahoma divestment. Per unit lease operating expenses increased during the 2015 quarter as result of our Oklahoma divestment, which included properties with a lower relative per unit cost, as well as normal production declines and downtime at certain of our Gulf Coast fields. 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 nine months ended September 30, 2015 totaled $399,000 and $2,303,000, respectively, as compared to $1,709,000 and $4,678,000, respectively, during the 2014 periods. Per unit production taxes totaled $0.05 and $0.08 per Mcfe, respectively, during the three and nine month periods ended September 30, 2015 as compared to $0.15 per Mcfe during

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the comparable 2014 periods. The decrease in 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, lower estimated production as a result of our Oklahoma divestment and the completion of our Thunder Bayou discovery, which is expected to be exempt from severance taxes, 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 nine months ended September 30, 2015 totaled $4,686,000 and $16,544,000, respectively, as compared to $6,319,000 and $19,028,000 during the 2014 periods. General and administrative expenses decreased 13% during the nine months ended September 30, 2015 as compared to the 2014 period primarily due to lower employee related costs including share-based compensation during the 2015 periods, which was only partially offset by lower capitalized costs. Included in general and administrative expenses for the three and nine month periods ended September 30, 2015 were share-based compensation costs of $988,000 and $3,940,000, respectively, compared to $1,442,000 and $5,177,000, respectively, during the 2014 periods. We capitalized $1,926,000 and $6,522,000, respectively, of general and administrative expenses during the three and nine month periods ended September 30, 2015 compared to $3,362,000 and $11,331,000, respectively, during the 2014 periods. We expect total general and administrative expenses during 2015 to decrease as compared to 2014.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three and nine months ended September 30, 2015 totaled $13,318,000, or $1.79 per Mcfe, and $51,632,000, or $1.88 per Mcfe, respectively, as compared to $21,913,000, or $1.89 per Mcfe, and $63,373,000, or $1.98 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 current year ceiling test write-downs, we expect our DD&A rate to be lower for the remainder of 2015.

At September 30, 2015, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.89 per Mcf of natural gas, $59.71 per barrel of oil and $2.70 per Mcfe of Ngl, respectively. As a result of lower commodity prices and their negative impact on our estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of approximately $40,212,000 and $214,618,000 during the three and nine month periods ended September 30, 2015, respectively. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-downs. Utilizing current strip prices for oil and gas prices for the fourth quarter of 2015 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of December 31, 2015, we expect to recognize an additional ceiling test write-down of $40 million to $60 million in the fourth quarter of 2015.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $8,526,000 and $24,996,000 during the three and nine months ended September 30, 2015, respectively, as compared to $7,050,000 and $22,066,000, respectively, during the 2014 periods. During the three and nine month periods ended September 30, 2015, our capitalized interest totaled $724,000 and $4,100,000, respectively, as compared to $2,704,000 and $7,327,000, respectively, during the 2014 periods. The increase in interest expense during the 2015 periods was the result of lower capitalized interest on our reduced unevaluated property balance. Our unevaluated property balance declined during 2015 as a result of our Oklahoma divestment.

Income tax expense during the three and nine months ended September 30, 2015 was $6,000 and $1,079,000, respectively, as compared to an income tax benefit of $389,000 during the comparable 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.

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 $120,980,000 as of September 30, 2015.

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 $22.4 million during the nine months ended September 30, 2015. 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.

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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 September 30, 2015 we had working capital of approximately $69.1 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 nine months ended September 30, 2015, we funded our capital expenditures with cash flow from operations, cash on hand and bank borrowings. We expect to fund our capital expenditures for the remainder of the year with cash flow from operations and cash on hand. We are currently evaluating our plans for 2016; however, based upon current commodity prices, we expect our capital expenditures during 2016 to be reduced from 2015 spending levels.

As of September 30, 2015, we had $159 million of cash on hand and had no borrowings outstanding under our $55 million bank credit facility. Based on our expectations for the remainder of the year, we anticipate that our financial covenants will effectively limit the utilization of the borrowing base to 25% of the aggregate commitments of the lenders, or $13.75 million, for the fiscal quarter ended December 31, 2015. We are presently evaluating refinancing and deleveraging options with respect to our 10% Senior Notes due 2017. These options include, but are not limited to, using cash to redeem a portion of the existing Notes at market prices, exchanging a portion of the existing Notes for secured second lien notes to extend the maturity date or using various combinations of cash and secured second lien Notes to reduce indebtedness under the existing Notes and extend the debt maturity schedule. In addition, we are evaluating new sources of debt capital that could be combined with existing cash to redeem all or a portion of the existing Notes and extend the maturity schedule.

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. While we seek to reduce our exposure to price volatility by hedging a portion of our production, our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us from continuing and prolonged declines in commodity prices.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 $125.9 million during the nine months ended September 30, 2014 to $24.0 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.

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

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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 September 30, 2015, $2.9 million had been accrued in connection with the March 1, 2016 interest payment and we were 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 September 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, the borrowing base was reduced to $55 million (subject to the aggregate commitments of the lenders then in effect and our compliance with the financial covenants under the Credit Agreement) effective September 8, 2015. The aggregate commitments of the lenders is currently $55 million and based on our expectations for the remainder of the year, we anticipate that these financial covenants (discussed in greater detail below) will effectively limit our utilization of the borrowing base to 25% of the aggregate commitments of the lenders, or $13.75 million, for the fiscal quarter ended December 31, 2015. The next scheduled borrowing base redetermination, is scheduled to occur by 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 90% 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 (i) a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of (a) 4.0 to 1.0 as of the last day of the fiscal quarter ending September 30, 2015, with the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted net cash proceeds actually received from the Sold Assets (such reduction amount not to exceed $130,000,000), (b) if we have unused availability greater than or equal to 75% of the aggregate commitments of the Lenders at all times during the consecutive three month period prior to and including the date of each fiscal quarter end, the maximum ratio of total debt to EBITDAX is 4.5 to 1.0 as of the last day of the fiscal quarters ending December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016, and 4.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, with in each case the amount of total debt for such quarterly period reduced by the amount of unencumbered and unrestricted cash of the Company, (c) if we have unused availability of less than 75% of the aggregate commitments of the Lenders at any time during the consecutive three month period prior to and including the date of calculating the ratio, the maximum ratio of total debt to EBITDAX will be 5.75 to 1.0 as of the last day of the fiscal quarters ending December 31, 2015, March 31, 2016, June 30, 2016 and September 30, 2016 and 5.25 to 1.0 as of the last day of the fiscal quarter ending December 31, 2016, and (d) 5.0 to 1.0 as of the last day of any fiscal quarter ending

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on or after March 31, 2017 and (ii) 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 September 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 $55.7 million was incurred during the first nine 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 in order to manage our liquidity position. During the nine months ended September 30, 2015, we funded our capital expenditures with cash flow from operations, cash on hand and bank borrowings. We plan to fund our capital expenditures during the remainder of 2015 with cash flow from operations and cash on hand. We are currently evaluating our plans for 2016; however, based upon current commodity prices, we expect our capital expenditures during 2016 to be reduced from 2015 spending levels.

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.

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 ability to hedge future production to reduce our exposure to price volatility in the current commodity pricing environment, 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 reduce leverage or refinance our senior notes due 2017, 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

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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 less than a $1 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the three and nine months ended September 30, 2015, we received $4.1 million and $10.5 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.

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



Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
October 2015 - December 2015	Swap	40,000 Mmbtu	$3.62
October 2015 - June 2016	Swap	10,000 Mmbtu	$3.22

Crude Oil:
October 2015 - December 2015	Swap (LLS)	500 Bbls	$56.68
Propane:
October 2015 - December 2015	Swap	250 Bbls	$25.62

LLS - Louisiana Light Sweet

The Company has approximately 4.6 Bcf of gas volumes at an average price of $3.54 per Mcf, 46,000 barrels of oil volumes at an average price of $56.68 per barrel, and 23,000 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 Instruments" in this Form 10-Q.

Interest Rate Risk

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

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Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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


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

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

Changes in Internal Control Over Financial Reporting

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

Part II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 1A. RISK FACTORS

Oil and natural gas prices are volatile, and 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 September 30, 2015, the NYMEX-WTI oil price ranged from a high of $113.39 per Bbl to a low of $38.22 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;

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•	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 will likely 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 September 30, 2015, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $191.4 million. Based upon the current commitment level of our bank group, we have $55 million (subject to compliance with the financial covenants under the Credit Agreement) of additional availability under our bank credit facility. Based on our expectations for the remainder of the year, we anticipate that these financial covenants will effectively limit our utilization of the borrowing base to 25% of the aggregate commitments of the lenders, or $13.75 million, for the fiscal quarter ended December 31, 2015. 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;

•

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

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

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 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 $40.2 million and $214.6 million during the three and nine months ended September 30, 2015, respectively. Utilizing current strip prices for oil and gas prices for the fourth quarter of 2015 and projecting the effect on the estimated future net cash flows from our estimated proved reserves as of December 31, 2015, we expect to recognize an additional ceiling test write-down of $40 million to $60 million in the fourth quarter of 2015.

Our hedging program may limit potential gains from increases in commodity prices or may result in losses or may be inadequate to protect us against continuing and prolonged declines in commodity prices.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at September 30, 2015 are in the form of swaps placed with the commodity trading branches of JPMorgan Chase Bank, Wells Fargo Bank, Bank of America and The Bank of Nova Scotia, all of which participate in our bank credit facility. We cannot assure you that these or future counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may also limit the benefit we could receive from increases in the market or spot prices for oil and natural gas.

For the nine months ended September 30, 2015, our total oil and gas sales included additions related to the settlement of gas hedges of $10,108,000, oil hedges of $38,000 and Ngl hedges of $348,000, which in total represented 11.3% of our total oil and gas sales for the nine month period. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. In addition, at September 30, 2015, we had approximately 4.6 Bcf of gas volumes, 46,000 barrels of oil volumes and 23,000 barrels of propane volumes hedged for the remainder 2015, and approximately 1.8 Bcf of gas volumes hedged for the first half of 2016. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition would be negatively impacted.

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

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended September 30, 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
July 1 - July 31, 2015	7,908	$	1.72	—	—
August 1 - August 31, 2015	—	—		—	—
September 1 - September 30, 2015	247	$	1.41	—	—
Total	8,155	$	1.71	—	—

________________________


(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.

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Item 6. EXHIBITS

10.1 Twelfth Amendment to Credit Agreement dated as of September 8, 2015, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, 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 September 8, 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

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SIGNATURE

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



		PETROQUEST ENERGY, INC.

Date:	November 3, 2015	/s/ J. Bond Clement
		J. Bond Clement Executive Vice President, Chief Financial Officer (Authorized Officer and Principal Financial and Accounting Officer)

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