e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended: September 30, 2007


o		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 þ Noo

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

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes o No þ

As of November 5, 2007, there were 49,355,498 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)


	September 30,			December 31,
	2007			2006
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	7,714		$	4,795
Revenue receivable		24,181			21,767
Joint interest billing receivable		19,707			20,072
Hedging asset		2,509			10,527
Prepaid drilling costs		2,088			4,886
Other current assets		4,639			2,143

Total current assets		60,838			64,190


Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		850,807			695,116
Unevaluated oil and gas properties		72,313			51,567
Accumulated depreciation, depletion and amortization		(401,977	)		(314,869	)

Oil and gas properties, net		521,143			431,814
Gas gathering assets		21,509			19,072
Accumulated depreciation and amortization of gas gathering assets		(5,852	)		(3,562	)

Total property and equipment		536,800			447,324


Other assets, net of accumulated depreciation and amortization of $10,843 and $11,719, respectively		6,277			6,776


Total assets	$	603,915		$	518,290


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	50,476		$	34,790
Advances from co-owners		18,056			13,391
Oil and gas revenue payable		6,935			6,935
Accrued interest		5,836			2,453
Asset retirement obligation		7,778			9,028
Other accrued liabilities		7,194			5,484

Total current liabilities		96,275			72,081

Bank debt		—			47,000
10 3/8% senior notes		148,698			148,537
Asset retirement obligation		12,671			11,211
Deferred income taxes		63,865			49,646
Other liabilities		362			104
Commitments and contingencies

Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,300 and 0, respectively		1			—
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 48,350 and 47,788, respectively		48			48
Paid-in capital		193,690			124,552
Accumulated other comprehensive income		1,418			6,632
Retained earnings		86,887			58,479

Total stockholders’ equity		282,044			189,711


Total liabilities and stockholders’ equity	$	603,915		$	518,290

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Income

(unaudited)

(Amounts in Thousands, Except Per Share Data)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Revenues:
Oil and gas sales	$	63,988	$	53,310	$	190,702	$	150,194
Gas gathering revenue and other income		1,512		1,776		5,566		4,746

		65,500		55,086		196,268		154,940


Expenses:
Lease operating expenses		8,929		8,960		24,185		24,738
Production taxes		1,593		1,772		5,777		4,554
Depreciation, depletion and amortization		31,846		23,923		89,510		62,994
Gas gathering costs		894		998		3,188		2,642
General and administrative		5,550		4,561		16,054		10,060
Accretion of asset retirement obligation		238		387		679		1,140
Interest expense		3,542		3,756		11,112		10,755

		52,592		44,357		150,505		116,883


Income from operations		12,908		10,729		45,763		38,057

Income tax expense		4,870		4,185		17,281		14,382


Net income		8,038		6,544		28,482		23,675

Preferred stock dividends		74		—		74		—


Net income available to common stockholders	$	7,964	$	6,544	$	28,408	$	23,675


Earnings per common share:
Basic	$	0.16	$	0.14	$	0.59	$	0.50


Diluted	$	0.16	$	0.13	$	0.57	$	0.49


Weighted average number of common shares:
Basic		48,284		47,643		48,018		47,454

Diluted		49,778		48,999		49,602		48,747

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)


	Nine Months Ended
	September 30,
	2007			2006
Cash flows from operating activities:
Net income	$	28,482		$	23,675
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		17,281			14,382
Depreciation, depletion and amortization		89,510			62,994
Accretion of asset retirement obligation		679			1,140
Amortization of debt issuance costs		722			705
Amortization of bond discount		161			145
Share based compensation expense		7,656			3,169
Changes in working capital accounts:
Accounts receivable		(2,414	)		(407	)
Joint interest billing receivable		365			2,593
Accounts payable and accrued liabilities		20,588			9,243
Advances from co-owners		4,665			(724	)
Other assets		(207	)		(5,069	)


Net cash provided by operating activities		167,488			111,846


Cash flows from investing activities:
Investment in oil and gas properties		(176,791	)		(136,709	)
Sale of oil and gas properties and other		248			4,859
Investment in gas gathering assets		(2,437	)		(5,861	)


Net cash used in investing activities		(178,980	)		(137,711	)


Cash flows from financing activities:
Net (payments for) proceeds from share based compensation		(63	)		1,380
Deferred financing costs		(73	)		(106	)
Proceeds from preferred stock offering		65,000			—
Costs of preferred stock offering		(3,453	)		—
Repayment of bank borrowings		(70,000	)		(6,000	)
Proceeds from bank borrowings		23,000			30,000


Net cash provided by financing activities		14,411			25,274


Net increase (decrease) in cash and cash equivalents		2,919			(591	)

Cash and cash equivalents, beginning of period		4,795			6,703


Cash and cash equivalents, end of period	$	7,714		$	6,112


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	11,283		$	9,124

Income taxes	$	—		$	—

See accompanying Notes to Consolidated Financial Statements.

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, 2007 and 2006, respectively, have been prepared by the Company and were 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, 2007 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, 2006 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 accounting principles generally accepted in the United States 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, 2006.

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

Note 2 Convertible Preferred Stock

During September 2007, the Company completed the public offering of 1,300,000 shares of its 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”). The net proceeds received from the offering were primarily used to repay the $58,000,000 of outstanding borrowings under the Company’s credit facility. Details of the September offering are as follows:


	Preferred
	Stock Offering
Gross proceeds	$	65,000,000
Underwriting discount		(3,250,000	)
Other costs of the offering		(203,000	)

Net proceeds (1)	$	61,547,000


Shares issued (1)		1,300,000
Issue price per share	$	50.00


(1)		In October 2007, the underwriters exercised their over-allotment option and we issued an additional 195,000 shares of Series B Preferred Stock resulting in net proceeds to us of $9.3 million.

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

Dividends. The Series B Preferred Stock will accumulate dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends will be 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 will pay dividends in cash, every quarter. The first dividend payment, if declared and paid, will be made on January 15, 2008.

Subject to certain limited exceptions, no dividends or other distributions (other than a dividend payable solely in shares of a like or junior ranking) may be paid or set apart for payment upon any shares ranking equally with the Series B Preferred Stock (“parity shares”) or shares ranking junior to the Series B Preferred Stock (“junior shares”), nor may any parity shares or junior shares be redeemed or acquired for any consideration by the Company

(except by conversion into or exchange for shares of a like or junior ranking) unless all accumulated and unpaid dividends have been paid or funds therefore have been set apart on the Series B Preferred Stock and any parity shares.

Liquidation preference. In the event of the Company’s voluntary or involuntary liquidation, winding-up or dissolution, each holder of Series B Preferred Stock will be entitled to receive and to be paid out of the Company’s assets available for distribution to the Company’s stockholders, before any payment or distribution is made to holders of junior stock (including common stock), but after any distribution on any of the Company’s indebtedness or senior stock, a liquidation preference in the amount of $50 per share of the Series B Preferred Stock, plus accumulated and unpaid dividends on the shares to the date fixed for liquidation, winding-up or dissolution.

Ranking. The Series B Preferred Stock will rank:

	•		senior to all of the shares of the Company’s common stock and to all of the Company’s other capital stock issued in the future unless the terms of such capital stock expressly provide that it ranks senior to, or on a parity with, shares of the Series B Preferred Stock;

	•		on a parity with all of the Company’s other capital stock issued in the future the terms of which expressly provide that it will rank on a parity with the shares of the Series B Preferred Stock; and

	•		junior to all of the Company’s existing and future debt obligations and to all shares of the Company’s capital stock issued in the future the terms of which expressly provide that such shares will rank senior to the shares of the Series B Preferred Stock.

Mandatory conversion. On or after October 20, 2010, 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.

Limited optional redemption. If fewer than 15% of the shares of Series B Preferred Stock are outstanding, the Company may, at any time on or after October 20, 2010, at its option, redeem for cash all such Series B Preferred Stock at a redemption price equal to the liquidation preference of $50 plus any accrued and unpaid dividends, if any, on a share of Series B Preferred Stock to, but excluding, the redemption date, for each share of Series B Preferred Stock.

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.

Purchase or exchange upon fundamental change. If the Company becomes subject to a fundamental change (as defined below), each holder of shares of Series B Preferred Stock will have the right to require the Company to purchase any or all of its shares at a purchase price equal to 100% of the liquidation preference, plus accumulated and unpaid dividends, to the date of the purchase. The Company will have the option to pay the purchase price in cash, shares of common stock or a combination of cash and shares. If the Company chooses to pay all or a portion of the purchase price in shares of common stock, in no event will the total number of shares of common stock issuable upon repurchase exceed 11.1857 shares of common stock for each share of Series B Preferred Stock, subject to adjustment, and the Company will not be required to pay cash in the event the per share value of the common stock issued upon any such repurchase is less than the common stock value floor; provided,

however, that the Company shall not pay the purchase price in shares of common stock or a combination of shares of common stock and cash unless (1) the Company shall have given a timely fundamental change notice including its intention to pay the purchase price or a specified percentage of the purchase price with shares of common stock and (2) such shares of common stock are registered under the Securities Act and the Exchange Act, in each case. The Company’s ability to purchase all or a portion of Series B Preferred Stock for cash is subject to the Company’s obligation to repay or repurchase any outstanding debt required to be repaid or repurchased in connection with a fundamental change and to any contractual restrictions then contained in the Company’s existing borrowing agreements.

Conversion in connection with a fundamental change. If a holder elects to convert its shares of Series B Preferred Stock in connection with certain fundamental changes, the Company will in certain circumstances increase the conversion rate for the Series B Preferred Stock. Upon a conversion in connection with a fundamental change, the holder will be entitled to receive a cash payment for all accumulated and unpaid dividends.

A “fundamental change” will be deemed to have occurred upon the occurrence of any of the following:

	1.		any “person” becomes the “beneficial owner” directly or indirectly, of more than 50% of the voting power of the Company’s common equity;

	2.		individuals who on September 25, 2007, constituted the board of directors (together with any new directors whose election by such board of directors or whose nomination for election by the stockholders of the Company was approved by a vote of a majority of the directors of the Company then still in office who were either directors on September 25, 2007, or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the board of directors then in office;

	3.		the merger or consolidation of the Company with or into another person or the merger of another person with or into the Company, or the sale of all or substantially all the assets of the Company to another person other than a transaction following which holders of securities that represented 100% of the voting power of the Company’s common equity immediately prior to such transaction (or other securities into which such securities are converted as part of such merger or consolidation transaction) own directly or indirectly at least a majority of the voting power of the voting equity of the surviving person in such merger or consolidation transaction or transferee in such sale of assets transaction immediately after such transaction;

	4.		the adoption of a plan relating to the liquidation or dissolution of the Company; or

	5.		the Company’s common stock is neither listed on a national securities exchange nor listed nor approved for quotation on an over-the-counter market in the United States.

However, a fundamental change will not be deemed to have occurred in the case of a share exchange, merger or consolidation or in an exchange offer having the result described in subsection 1 above, if 90% or more of the consideration in the aggregate paid for common stock (and cash payments pursuant to dissenters’ appraisal rights) in the share exchange, merger or consolidation or exchange offer consists of common stock of a United States company traded on a national securities exchange (or which will be so traded or quoted when issued or exchanged in connection with such transaction).

Voting rights. If the Company fails to pay dividends for six quarterly dividend periods (whether or not consecutive) or if the Company fails to pay the purchase price on the purchase date for the Series B Preferred Stock following a fundamental change, holders of the Series B Preferred Stock will have voting rights to elect two directors to the Company’s board.

In addition, subject to certain exceptions, the Company may generally not, without the approval of the holders of at least 66 2/3% of the shares of the Series B Preferred Stock then outstanding:

	•		amend the Company’s certificate of incorporation and bylaws, by merger or otherwise, if the amendment would alter or change the powers, preferences, privileges or rights of the holders of shares of the Series B Preferred Stock so as to adversely affect them;

	•		issue, authorize or increase the authorized amount of, or issue or authorize any obligation or security convertible into or evidencing a right to purchase, any senior stock; or

	•		reclassify any of the Company’s authorized stock into any senior stock of any class, or any obligation or security convertible into or evidencing a right to purchase any senior stock.

In addition, if the Company creates an additional series of preferred stock that is part of the same class as the Series B Preferred Stock and all series of the class are not equally affected by a proposed change, the approval of the holders of at least 662/3% of the series that would have diminished status will be required to amend the Company’s certificate of incorporation and bylaws, by merger or otherwise.

Note 3 Earnings Per Share

Basic earnings per common share is computed by dividing net income available to common stockholders by the weighted average number of shares of common stock outstanding during the periods presented. Diluted earnings per common share is determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and restricted stock considered dilutive computed using the treasury stock method.

Diluted earnings per share for the 2007 periods also considers the effect of the Series B Preferred Stock issued in September 2007 (Note 2) by applying the “if converted” method. Under this method, the dividends applicable to the Series B Preferred Stock are added back to the numerator and the Series B Preferred Stock is assumed to have been converted to common shares in the denominator as of the beginning of the period (or at the time of issuance if later). In applying the “if converted” method for the Series B Preferred Stock, conversion is not assumed in computing diluted earnings per share if the effect would be anti-dilutive.

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


	Income		Shares		Per
For the Three Months Ended September 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS
Net income available to common stockholders	$	7,964		48,284	$	0.16

Effect of dilutive securities:
Stock options		—		966
Restricted stock		—		528
Series B preferred stock		—		—

DILUTED EPS	$	7,964		49,778	$	0.16


	Income		Shares		Per
For the Three Months Ended September 30, 2006	(Numerator)		(Denominator)		Share Amount
BASIC EPS
Net income available to common stockholders	$	6,544		47,643	$	0.14

Effect of dilutive securities:
Stock options		—		1,199
Restricted stock		—		157

DILUTED EPS	$	6,544		48,999	$	0.13


	Income		Shares		Per
For the Nine Months Ended September 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS
Net income available to common stockholders	$	28,408		48,018	$	0.59

Effect of dilutive securities:
Stock options		—		1,090
Restricted stock		—		494
Series B preferred stock		—		—

DILUTED EPS	$	28,408		49,602	$	0.57


	Income		Shares		Per
For the Nine Months Ended September 30, 2006	(Numerator)		(Denominator)		Share Amount
BASIC EPS
Net income available to common stockholders	$	23,675		47,454	$	0.50

Effect of dilutive securities:
Stock options		—		1,293
Restricted stock		—		—

DILUTED EPS	$	23,675		48,747	$	0.49

In addition to the stock options included in the reconciliation above, options to purchase 157,035 and 145,035 shares of common stock were outstanding during the three- and nine-month periods ended September 30, 2007, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market prices of the common shares during the periods. These options’ exercise prices ranged between $12.54 and $14.48 during the periods. All of the anti-dilutive options in the 2007 periods expire in 2016 and 2017. Additionally, for the three and nine months ended September 30, 2007, diluted earnings per share did not include the assumed conversion of the Series B Preferred Stock as the effect of assuming conversion was anti-dilutive.

Options to purchase 141,159 and 655,846 shares of common stock were outstanding during the three- and nine-month periods ended September 30, 2006, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market prices of the common

shares during the periods. These options’ exercise prices ranged between $11.29 and $12.21 during the third quarter of 2006 and between $10.75 and $12.21 during the nine month period of 2006, and all expire in 2016.

Note 4 Long-Term Debt

During 2005, the Company and PetroQuest Energy, L.L.C. issued $150 million in principal amount of 10 3/8% Senior Notes due 2012 (the “Notes”). The Notes are guaranteed by the significant subsidiaries of the Company and PetroQuest Energy, L.L.C. The aggregate assets and revenues of subsidiaries not guaranteeing the Notes constituted less than 3% of the Company’s consolidated assets and revenues at and for the three and nine months ended September 30, 2007.

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 May 15 and November 15. At September 30, 2007, $5.8 million had been accrued in connection with the November 15, 2007 interest payment and the Company was in compliance with all of the covenants under the Notes.

On November 18, 2005, the Company and its wholly owned subsidiary, PetroQuest Energy, L.L.C., entered into the Second Amended and Restated Credit Agreement. The credit agreement provides for a $100 million revolving credit facility that permits borrowings based on the available borrowing base as determined in the credit facility. The credit facility also allows for the use of up to $15 million of the borrowing base for letters of credit. The credit facility matures on November 19, 2009. As of September 30, 2007, there were no borrowings outstanding under the credit facility as the Company used a portion of the proceeds from the Series B Preferred Stock offering to repay all outstanding borrowings.

The credit facility is secured by, among other things, a lien on at least 90% of the PDP present value and at least 80% of the aggregate proved reserves of the Company’s oil and gas properties. PDP present value means the present value discounted at nine percent of the future net revenues attributable to producing reserves. The borrowing base under the credit facility is based primarily upon the bi-annual valuation of the mortgaged oil and gas properties. The current borrowing base is $80 million and the next scheduled borrowing base re-determination will be on April 1, 2008. The Company or the lenders may request additional borrowing base re-determinations.

Outstanding balances on the credit facility bear interest at either the alternate base rate plus a margin (based on a sliding scale of 0.125% to 0.875% based on borrowing base usage) or the Eurodollar rate plus a margin (based on a sliding scale of 1.375% to 2.125% depending on borrowing base usage). The alternate base rate is equal to the higher of the JPMorgan Chase prime rate or the Federal Funds Effective Rate plus 0.5% per annum, and the Eurodollar rate is equal to the applicable British Bankers’ Association LIBOR rate for deposits in U.S. dollars.

The Company is subject to certain restrictive financial covenants under the credit facility, including a maximum ratio of consolidated indebtedness to annualized consolidated EBITDA, determined on a rolling four quarter basis of 3.0 to 1 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the credit agreement. The credit facility also includes customary restrictions with respect to liens, indebtedness, loans and investments, material changes in the Company’s business, asset sales or leases or transfers of assets, restricted payments such as distributions and dividends, mergers or consolidations, transactions with affiliates and rate management transactions. At September 30, 2007, the Company was in compliance with all of the covenants under the credit facility.

Note 5 Asset Retirement Obligation

In June 2001, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations,” which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred.

Retirement obligations associated with long-lived assets included within the scope of SFAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed.

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


Asset retirement obligation at January 1, 2007	$	20,239
Liabilities incurred during 2007		554
Liabilities settled during 2007		(1,233	)
Accretion expense		679
Revisions in estimates		210


Asset retirement obligation at September 30, 2007		20,449
Less: current portion of asset retirement obligation		(7,778	)

Long-term asset retirement obligation	$	12,671

Note 6 Share Based Compensation

The Company accounts for share-based compensation in accordance with SFAS 123 (revised 2004), “Share Based Payment” (“SFAS 123(R)”). Share based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share based compensation for the periods ended September 30, 2007 and 2006 is as follows (in thousands):


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Stock options:
Incentive Stock Options	$	255	$	520	$	943	$	813
Non-Qualified Stock Options		484		122		1,396		229
Restricted stock		1,431		1,480		5,317		2,127

Share based compensation	$	2,170	$	2,122	$	7,656	$	3,169

During the three and nine month periods ended September 30, 2007, the Company recorded income tax benefits of $0.7 million and $2.5 million, respectively, related to share based compensation expense recognized during those periods. The three- and nine-month periods ended September 30, 2006 include income tax benefits of $0.6 million and $0.9 million relative to share based compensation. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has substantial net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented.

The following table details stock option activity during the nine months ended September 30, 2007:


	Number of			Wgtd. Avg.
	Options			Exercise Price
Outstanding at beginning of year		2,520,811		$	5.18
Granted		415,676			12.43
Expired/cancelled/forfeited		(30,000	)		10.59
Exercised		(327,662	)		2.81

Outstanding at end of period		2,578,825		$	6.59

The following table details restricted stock activity during the nine months ended September 30, 2007:


				Wgtd. Avg.
	Number of			Fair Value per
	Shares			Share
Outstanding at beginning of year		1,409,895		$	11.04
Granted		238,420			11.75
Expired/cancelled/forfeited		(3,095	)		11.78
Lapse of restrictions		(310,954	)		10.84

Outstanding at end of period		1,334,266		$	11.21

Note 7 Other Comprehensive Income and Derivative Instruments

The following table presents the Company’s comprehensive income for the three- and nine-month periods ended September 30, 2007 and 2006 (in thousands):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006
Net income available to common stockholders	$	7,964		$	6,544	$	28,408		$	23,675
Change in fair value of derivative instruments, accounted for as hedges, net of taxes		(1,293	)		5,017		(5,214	)		14,355

Comprehensive income	$	6,671		$	11,561	$	23,194		$	38,030

For the three months ended September 30, 2007 and 2006, the effect of derivative instruments is net of deferred income tax benefit (expense) of $760,000 and ($2,947,000), respectively. For the nine months ended September 30, 2007 and 2006, the effect of derivative instruments is net of deferred income tax benefit (expense) of $3,062,000 and ($8,067,000), respectively.

The Company accounts for derivatives in accordance with SFAS 133, as amended. When the conditions for hedge accounting specified in SFAS 133 are met, the Company may designate these derivatives as hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative would be recorded in the income statement as derivative income or expense. At September 30, 2007, our outstanding derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $4,366,000 and $2,765,000 and oil hedges of ($77,200) and ($804,000) for the three months ended September 30, 2007 and 2006, respectively. For the nine month periods ended September 30, 2007 and 2006, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $8,207,000 and $6,132,000 and oil hedges of $155,000 and ($2,289,000), respectively.

As of September 30, 2007, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

Fourth Quarter 2007

Costless Collar

27,500 Mmbtu

7.87-9.52

2008

Costless Collar

10,000 Mmbtu

7.50-8.97

Crude Oil:

Fourth Quarter 2007

Costless Collar

700 Bbls

68.57-75.95

2008

Costless Collar

400 Bbls

70.00-75.55

At September 30, 2007, the Company recognized a net asset of $2.2 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2007, the Company would realize a $1.6 million gain, net of taxes, as an addition to oil and gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

Note 8 New Accounting Standards

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes,” and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Accordingly, the Company adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have any effect on the Company’s financial position or results of operations. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of the date of adoption and September 30, 2007, the Company did not have any unrecognized tax benefits or accrued interest or penalties related to uncertain tax positions. The tax years from 2002 through 2006 remain open to examination by the tax jurisdictions to which the Company is subject.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure about fair value measurements. SFAS No. 157 will be effective for financial statements issued for fiscal years beginning after November 15, 2007. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Liabilities — Including an amendment of FASB Statement No. 115” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure many financial instruments and certain other items at fair value. This statement will be effective for the Company on January 1, 2008. The Company is evaluating these standards and does not anticipate that their implementation will have a material effect on its 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, which from the commencement of operations in 1985 through 2002, was 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 in Texas and Oklahoma. 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 onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

Specific asset diversification activities included the 2003 acquisition of proved reserves and acreage in the Southeast Carthage Field in East Texas. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring proved reserves. During 2005, we further increased our presence in Oklahoma through multiple acquisition transactions and an expanded drilling program. Our diversification efforts continued during 2006 through the opening of an exploration office in Tulsa, Oklahoma to augment our increased presence in the region, the drilling of 96 gross wells in Oklahoma and East Texas, which represented approximately 85% of our total gross wells drilled during 2006, and the divestiture of certain mature Gulf of Mexico properties. As a result of these focused diversification efforts, approximately 60% of our proved reserves and 30% of our production at September 30, 2007 were derived from longer life basins.

During 2006, we invested approximately $171 million in exploratory, development and acquisition activities as we drilled a company record 113 gross wells realizing an overall success rate of 91% on our 2006 drilling program. For the nine months ended September 30, 2007, we have drilled 49 gross wells realizing an 86% success rate. As a result of our drilling success during 2006 and 2007, production during the third quarter of 2007 increased to 8.1 Bcfe, a 16% increase from the corresponding quarter of 2006. This growth in production resulted in revenues, net income available to common stockholders and cash flow from operating activities increasing 20%, 22% and 50%, respectively, from third quarter 2006 levels.

Recent Events

Fayetteville Shale Acreage

During the second and third quarters of 2007, we closed several transactions acquiring an aggregate of approximately 16,000 net unevaluated acres in Arkansas. During late-September, we began participating in a multi-well drilling program on this acreage targeting the Fayetteville Shale. We expect operational activity to increase in this area during the remainder of 2007 and into 2008.

Preferred Stock Offering

In September 2007, we issued 1.3 million shares of our Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”) receiving $61.5 million in net proceeds. The offering proceeds were primarily used to repay all outstanding borrowings under our credit facility. In October 2007, the underwriters exercised their over-allotment option and we issued an additional 195,000 shares of Series B Preferred Stock resulting in net proceeds to us of $9.3 million.

Critical Accounting Policies

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 and dismantlement, restoration and abandonment costs, net of estimated salvage values. 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, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.

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

Future Abandonment Costs

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

Reserve Estimates

Our estimates of proved oil and gas reserves constitute quantities that we are reasonably certain of recovering in future years. At the end of each year, our proved reserves are estimated by independent petroleum

consultants in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. 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 quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results. 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. For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially. 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. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variance may be material.

Derivative Instruments

The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income or expense.

Our hedges are specifically referenced to the NYMEX index prices we receive for our designated production. 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 index prices and the posted prices we receive from the designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At September 30, 2007, our derivative instruments were considered effective cash flow hedges.

Estimating the fair value of hedging derivatives requires complex calculations incorporating estimates of future prices, discount rates and price movements. As a result, we obtain the fair value of our commodity derivatives from the counterparties to those contracts. Because the counterparties are market makers, they are able to provide us with a market value by providing us with a price at which they would be willing to settle such contracts as of the given date.

New Accounting Standards

In July 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”). FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes,” and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. Accordingly, we adopted FIN 48 on January 1, 2007. The adoption of FIN 48 did not have an effect on our financial position or results of operations. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of the date of adoption and September 30, 2007, we did not have any unrecognized tax benefits or accrued interest or penalties related to uncertain tax positions. The tax years from 2002 through 2006 remain open to examination by the tax jurisdictions to which we are subject.

certain other items at fair value. This statement will be effective for us on January 1, 2008. We do not anticipate that the implementation of these new standards will have a material effect on our financial statements.

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				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Production:
Oil (Bbls)		243,048		206,576		889,521		548,999
Gas (Mcf)		6,621,226		5,738,895		18,257,387		16,023,905
Total Production (Mcfe)		8,079,514		6,978,351		23,594,513		19,317,899

Sales:
Total oil sales	$	18,793,535	$	13,721,525	$	59,892,329	$	34,741,192
Total gas sales		45,194,457		39,587,994		130,809,880		115,452,309

Total oil and gas sales		63,987,992		53,309,519		190,702,209		150,193,501

Average sales prices:
Oil (per Bbl)	$	77.32	$	66.42	$	67.33	$	63.28
Gas (per Mcf)		6.83		6.90		7.16		7.21
Per Mcfe		7.92		7.64		8.08		7.77

The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of $4,366,000 and $2,765,000 and the settlement of oil hedges of ($77,200) and ($804,000) for the three months ended September 30, 2007 and 2006, respectively. The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of $8,207,000 and $6,132,000 and the settlement of oil hedges of $155,000 and ($2,289,000) for the nine months ended September 30, 2007 and 2006, respectively.

Net income available to common stockholders totaled $7,964,000 and $6,544,000 for the quarters ended September 30, 2007 and 2006, respectively, while net income available for common stockholders for the nine month periods ended September 30, 2007 and 2006 totaled $28,408,000 and $23,675,000, respectively. The increase in net income during the 2007 periods was primarily attributable to the following:

Production. Oil production during the three and nine month periods ended September 30, 2007 increased 18% and 62%, respectively, from the comparable 2006 periods, while natural gas production during the quarter and nine months ended September 30, 2007 increased 15% and 14%, respectively, from the comparable 2006 periods. In total, production during the quarter and nine month periods ended September 30, 2007 was 16% and 22% higher, respectively, than the production during the quarter and nine months ended September 30, 2006.

Throughout 2006, we successfully drilled and recompleted several wells at our Ship Shoal 72 Field, which produces substantial oil volumes. As a result of drilling success and the improvement in throughput from a new main field pipeline installed in late 2006, production from Ship Shoal 72 totaled 8 Bcfe, or approximately 34% of total company production during the first nine months of 2007, as compared to only 3.8 Bcfe, or 20% of total company production during the comparable 2006 period. The increase in production during the nine month period ended September 30, 2007 was partially offset by the sale of certain producing Gulf of Mexico properties in November 2006.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and nine months ended September 30, 2007 were $77.32 and $67.33, respectively, as compared to $66.42 and $63.28, respectively, for the 2006 periods. Average gas prices per Mcf were $6.83 and $7.16 for the quarter and nine months ended September 30, 2007, respectively, as compared to $6.90 and $7.21 for the respective 2006 periods. Stated on an Mcfe basis, unit prices received during the quarter and nine months ended September 30, 2007 were 4% higher than the prices received during the comparable 2006 periods.

Revenue. Oil and gas sales during the quarter and nine months ended September 30, 2007 increased 20% and 27% to $63,988,000 and $190,702,000, respectively, as compared to oil and gas sales of $53,310,000 and $150,194,000 for the 2006 periods. The increased revenue during the 2007 periods was primarily the result of higher production levels.

Expenses. Lease operating expenses for the three and nine month periods ended September 30, 2007 decreased to $8,929,000 and $24,185,000, respectively, as compared to $8,960,000 and $24,738,000 during the 2006 periods. The third quarter and nine month 2006 periods included lease operating costs of $1,722,000 and $4,771,000, respectively, related to several mature Gulf of Mexico properties that were sold in November 2006. Excluding the operating expenses and production related to the sold properties, per unit operating expenses totaled $1.10 and $1.12 per Mcfe during the three and nine month periods of 2006, respectively, as compared to $1.11 and $1.03, per Mcfe during the 2007 periods. We expect that operating expenses for the remainder of 2007 will approximate third quarter 2007 amounts.

Production taxes during the quarter and nine months ended September 30, 2007 totaled $1,593,000 and $5,777,000, respectively, as compared to $1,772,000 and $4,554,000 during the 2006 periods. The decrease in production taxes during the third quarter of 2007, as compared to the 2006 quarter, was due to the 28% reduction in the Louisiana severance tax rate effective July 1, 2007 and 1% lower natural gas prices.

General and administrative expenses during the quarter and nine months ended September 30, 2007 totaled $5,550,000 and $16,054,000, respectively, as compared to expenses of $4,561,000 and $10,060,000 during the comparable 2006 periods. Included in general and administrative expenses for the periods ended September 30, 2007 and 2006 was share based compensation expense relative to SFAS 123(R) as follows:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Stock options:
Incentive Stock Options	$	255,000	$	520,000	$	943,000	$	813,000
Non-Qualified Stock Options		484,000		122,000		1,396,000		229,000
Restricted stock		1,431,000		1,480,000		5,317,000		2,127,000

Share based compensation	$	2,170,000	$	2,122,000	$	7,656,000	$	3,169,000

Excluding the impact of share based compensation expense, the increase in general and administrative expenses was primarily attributable to the 29% increase in our staffing throughout 2006 and the first nine months of 2007 necessary to manage our increased operational activity. We capitalized $1,734,000 and $5,270,000 of general and administrative costs during the three and nine month periods ended September 30, 2007, respectively, and $1,453,000 and $4,382,000 during the comparable 2006 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and nine months ended September 30, 2007 totaled $30,935,000, or $3.83 per Mcfe, and $86,861,000, or $3.68 per Mcfe, respectively, as compared to $23,158,000, or $3.32 per Mcfe, and $60,921,000, or $3.15 per Mcfe, in the respective periods of 2006. The increase in DD&A expense per Mcfe is primarily due to increased costs to drill for, develop and acquire oil and gas reserves. Assuming commodity prices remain at current levels, we would expect the costs to drill for, develop and acquire oil and gas reserves to generally approximate third quarter 2007 levels.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $3,542,000 and $11,112,000, respectively, during the quarter and nine months ended September 30, 2007 as compared to $3,756,000 and $10,755,000 during the 2006 periods. We capitalized $1,674,000 and $4,437,000 of interest during the three and nine month periods of 2007 and $1,153,000 and $3,400,000 during the respective 2006 periods.

Income tax expense during the quarter and nine month periods ended September 30, 2007 totaled $4,870,000 and $17,281,000, respectively, as compared to $4,185,000 and $14,382,000 during 2006 periods. The increases are primarily the result of the increased operating profit during the 2007 periods, as compared to 2006. We 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.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, private and public offerings of equity and debt securities and sales of properties. During September and October 2007, we received approximately $71 million in net proceeds from the issuance of 1,495,000 shares of our Series B Preferred Stock. The offering proceeds were primarily used to repay all outstanding borrowings under our credit facility in order to provide liquidity for our ongoing diversification efforts.

At September 30, 2007, we had a working capital deficit of $35.4 million compared to a deficit of $7.9 million at December 31, 2006. The decline in our working capital was primarily due to the $8 million reduction in the estimated fair value of our derivative instruments, which is primarily the result of the expiration of several hedge contracts, the $15.7 million increase in our accounts payable to vendors, which is a result of increased operational activity, and the $3.3 million increase in accrued interest, which is a function of the timing of payments due under our 10 3/8% Senior Notes due 2012. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. As a result of the application of the net proceeds from the sale of our Series B Preferred Stock, we currently have $80 million of borrowing capacity under our bank credit facility.

Source of Capital: Operations

Net cash flow from operations increased from $111,846,000 in the nine month period ended September 30, 2006 to $167,488,000 during the nine month period ended September 30, 2007. The increase in operating cash flow was primarily the result of higher production volumes realized during 2007.

Source of Capital: Debt

During 2005, we issued $150 million in principal amount of the 10 3/8% Senior Notes due 2012 (the “Notes”). 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 May 15 and November 15. At September 30, 2007, $5.8 million had been accrued in connection with the November 15, 2007 interest payment. At September 30, 2007, we were in compliance with all of the covenants under the Notes.

On November 18, 2005, we and our wholly owned subsidiary, PetroQuest Energy, L.L.C., entered into the Second Amended and Restated Credit Agreement. The credit agreement provides for a $100 million revolving credit facility that permits us to borrow amounts based on the available borrowing base as determined in the credit facility. The credit facility also allows us to use up to $15 million of the borrowing base for letters of credit. The credit facility matures on November 19, 2009.

The credit facility is secured by, among other things, a lien on at least 90% of the PDP present value and at least 80% of the aggregate proved reserves of our oil and gas properties. PDP present value means the present value discounted at nine percent of the future net revenues attributable to producing reserves. The borrowing base under the credit facility is based primarily upon the bi-annual valuation of our mortgaged oil and gas properties. The borrowing base is currently $80 million and the next scheduled borrowing base re-determination will be on April 1, 2008 and we or the lenders may request additional borrowing base re-determinations. As of September 30, 2007, we did not have any borrowings outstanding under the credit facility and we were in compliance with all of the covenants therein.

We are subject to certain restrictive financial covenants under the credit facility, including a maximum ratio of consolidated indebtedness to annualized consolidated EBITDA, determined on a rolling four quarter basis of 3.0 to 1 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the credit agreement. The credit facility also includes customary restrictions with respect to liens, indebtedness, loans and investments, material changes in our business, asset sales or leases or transfers of assets, restricted

payments such as distributions and dividends, mergers or consolidations, transactions with affiliates and rate management transactions.

Natural gas and oil prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil 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. Reduced cash flow may also make it difficult to incur debt, other than under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. 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 natural gas and oil prices.

Source of Capital: Issuance of Securities

During September and October 2007, we issued a total of 1,495,000 shares of Series B Preferred Stock resulting in net proceeds to us of approximately $71 million. Cash dividends are payable quarterly in the amount of $0.8594 per share of Series B Preferred Stock. Based on the total of 1,495,000 shares of Series B Preferred Stock issued, the annual dividend payment, if declared and paid, is expected to be approximately $5.1 million. Each share of convertible preferred stock is convertible at the holder’s option at any time initially into 3.4433 shares of our common stock (based on an initial conversion price of $14.52 per share of common stock, subject to adjustment), subject to our right to settle all or a portion of the conversion in cash. On or after October 20, 2010, we may, at our option, cause the Series B Preferred Stock to be automatically converted at the applicable conversion rate if the closing price of our common stock for 20 trading days within a period of 30 consecutive trading days equals or exceeds 130% of the conversion price. See Note 2 of the Notes to Consolidated Financial Statements for a summary of certain terms of the Series B Preferred Stock.

After giving effect to the issuance of the Series B Preferred Stock, we have approximately $125 million remaining under an effective universal shelf registration statement relating to the potential public offer and sale of any combination of debt securities, common stock, preferred stock, depositary shares, and warrants. The registration statement does not provide assurance that we will or could sell any such securities.

Source of Capital: Divestitures

We do not budget property divestitures; however, we are continually evaluating our property base to determine if there are assets in our portfolio that no longer meet our strategic objectives. From time to time we may divest certain non-strategic assets in order to provide capital to be reinvested in higher rate of return projects or in projects that have longer estimated lives. During August 2007, we announced that we were seeking strategic alternatives with respect to our gas gathering assets located in Oklahoma. One of those alternatives includes the potential sale of these assets. There can be no assurance that we will be able to sell any of our assets.

Use of Capital: Exploration and Development

Our 2007 capital budget, which excludes acquisitions and capitalized interest and general and administrative costs, is approximately $200 million. Excluding acquisitions and capitalized interest and general and administrative costs, through September 30, 2007 we incurred approximately $141 million of our 2007 capital budget.

Based on our outlook of commodity prices and production, we believe that we will be able to fund the remainder of the planned 2007 exploration and development activities with cash on hand, cash flow from operations and available bank borrowings. Our future exploration and development activities could require additional financings, which may include sales of additional equity or debt securities, additional bank borrowings, sales of properties, or joint venture arrangements with industry partners. We cannot assure you that such additional financings will be available on acceptable terms, if at all. If we are unable to obtain additional financing, we could be forced to delay, reduce our participation in or even abandon some of our exploration and development opportunities or be forced to sell some of our assets on an untimely or unfavorable basis.

Use of Capital: Acquisitions

We do not budget for acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. We expect to fund future acquisitions primarily with cash flow from operations and borrowings

under our bank credit facility, but may also issue additional equity or debt securities either directly or in connection with an acquisition. There can be no assurance that acquisition funds may be available on terms acceptable to us, if at all.

Disclosure Regarding Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices, declines in the values of our properties resulting in ceiling test writedowns, our ability to replace reserves and sustain production, our estimate of the sufficiency of our existing capital sources, our ability to raise additional capital to fund cash requirements for future operations, the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions or dispositions and in projecting future rates of production, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

When used in this Form 10-Q, the words, “expect,” “anticipate,” “intend,” “plan,” “believe,” “seek,” “estimate” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain these identifying words. Because these forward-looking statements involve risks and uncertainties, actual results could differ materially from those expressed or implied by these forward-looking statements for a number of important reasons, including those discussed under “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in this Form 10-Q.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We experience market risks primarily in two areas: interest rates and commodity prices. Because our properties are located within the United States, we do not believe that our business operations are exposed to significant foreign currency exchange risks.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected sales volumes for the fourth quarter of 2007, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $6 million impact on our revenues.

We periodically 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 counterparts 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 counterparts this difference multiplied by the quantity hedged. During the quarter and nine month periods ended September 30, 2007, we received from the counterparties to our derivative instruments $4,289,000 and $8,362,000, respectively, 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.

As of September 30, 2007, we had entered into the following oil and gas contracts accounted for as cash flow hedges:


	Instrument		Weighted
Production Period	Type	Daily Volumes	Average Price
Natural Gas:
Fourth Quarter 2007	Costless Collar	27,500 Mmbtu	$	7.87-9.52
2008	Costless Collar	10,000 Mmbtu	$	7.50-8.97

Crude Oil:
Fourth Quarter 2007	Costless Collar	700 Bbls	$	68.57-75.95
2008	Costless Collar	400 Bbls	$	70.00-75.55

At September 30, 2007, we recognized a net asset of $2.2 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of September 30, 2007, we would realize a $1.6 million gain, net of taxes, as an addition to oil and gas sales during the next 12 months. These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

In October 2007, we entered into the following additional gas contract accounted for as a cash flow hedge:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

2008

Costless Collar

10,000 Mmbtu

8.00-8.60

At September 30, 2007, we had no debt outstanding that was subject to a floating interest rate. As a result, the potential effect of rising interest rates during the remainder of 2007 is not expected to be material.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

Changes in Internal Controls

There have been no changes in the Company’s internal controls 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

Our future success depends upon our ability to find, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable.

As is generally the case in the Gulf Coast Basin where the majority of our current production is located, many of our producing properties are characterized by a high initial production rate, followed by a steep decline in production. In order to maintain or increase our reserves, we must constantly locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development and acquisition activities. Without successful exploration, development or acquisition activities, our reserves and revenues will decline rapidly. We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

A substantial portion of our operations is exposed to the additional risk of tropical weather disturbances.

A substantial portion of our production and reserves is located in Federal waters offshore, onshore South Louisiana and Texas. For example, production from our Ship Shoal 72 and Main Pass 74 fields, which are located offshore Louisiana, represented approximately 34% and 14%, respectively, of our production during the first nine months of 2007. Operations in this area are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, Hurricanes Katrina and Rita impacted our South Louisiana and Texas operations in August and September of 2005, respectively, causing property damage to certain facilities, a substantial portion of which was covered by insurance. As a result, a portion of our oil and gas production was shut-in reducing our overall production volumes in the third and fourth quarters of 2005. In addition, production from our Main Pass 74 field was shut-in from September 2004 to January 2006 due to third party pipeline damage associated with Hurricane Ivan in September 2004. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks.

Losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

A material reduction or loss in production from our Ship Shoal 72 field could materially affect our operations.

Production from our Ship Shoal 72 field represented approximately 34% of our production for the first nine months of 2007. A material reduction or loss of production from this field due to a variety of industry operating hazards and adverse weather conditions could have a material adverse effect on our financial condition and results of operations.

We have a substantial amount of indebtedness, which 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, 2007, the aggregate amount of our outstanding indebtedness was $149 million, which could have important consequences for you, including the following:

•

it may be more difficult for us to satisfy our obligations with respect to our 10 3/8% senior notes due 2012, which we refer to as our 10 3/8% 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 indenture governing our 10 3/8% notes and the agreements governing such other indebtedness;

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

	•		we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, approximately $15.6 million per year for interest on our 10 3/8% notes alone, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

	•		we 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 declines in oil and natural gas prices; and

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

We may incur debt from time to time under our bank credit facility. The borrowing base limitation under our bank credit facility is periodically redetermined and upon such redetermination, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make such repayments.

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 3/8% notes, and meet our other obligations. If we do not have enough money to service our debt, we may be required to refinance all or part of our existing debt, including our 10 3/8% notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

Together with our subsidiaries, we may be able to incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. Although the indenture governing our 10 3/8% notes contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. As of September 30, 2007, we had no borrowings outstanding under our bank credit facility and our borrowing base was $80 million. To the extent we add new indebtedness to our current indebtedness levels, the risks described above could substantially increase.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not historically paid a dividend on our common stock, cash or otherwise, and do not intend to in the foreseeable future. We are currently restricted from paying dividends on common stock by our bank credit facility 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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

NONE.

Item 3. DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

NONE

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

Exhibit 3.1, Certificate of Designations establishing the 6.875% Series B cumulative convertible perpetual preferred stock, dated September 24, 2007 (incorporated herein by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 24, 2007).

Exhibit 10.1, Amendment No. 3 to Second Amended and Restated Credit Agreement, dated as of September 17, 2007, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans, Inc., TDC Energy LLC, JPMorgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 18, 2007).

Exhibit 10.2, Amendment No. 4 to Second Amended and Restated Credit Agreement, dated as of September 19, 2007, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans, Inc., TDC Energy LLC, JPMorgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated herein by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on September 24, 2007).

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.

Index to Exhibits

Exhibit 31.1, Certification of Chief Executive Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 31.2, Certification of Chief Financial Officer pursuant to Rule 13-a-14(a)/Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934, as amended.

Exhibit 32.1, Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Exhibit 32.2, Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


		PETROQUEST ENERGY, INC.

Date: November 6, 2007		/s/ Michael O. Aldridge Michael O. Aldridge
		Executive Vice President, Chief
		Financial Officer and Treasurer
		(Authorized Officer and Principal
		Financial and Accounting Officer)

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			Page No.
Part I. Financial Information

	Item 1.	Financial Statements

		Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006		1

		Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2007 and 2006		2

		Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		3

		Notes to Consolidated Financial Statements		4

	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		20

	Item 4.	Controls and Procedures		21

Part II. Other Information

	Item 1.	Legal Proceedings		22

	Item 1A.	Risk Factors		22

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		24

	Item 3.	Defaults upon Senior Securities		24

	Item 4.	Submission of Matters to a Vote of Security Holders		24

	Item 5.	Other Information		24

	Item 6.	Exhibits		24
Certification of CEO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)/15d-14(a)
Certification of CEO Pursuant to 18 U.S.C Section 1350
Certification of CFO Pursuant to 18 U.S.C Section 1350

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

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

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

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


/s/ Charles T. Goodson Charles T. Goodson
Chief Executive Officer
November 6, 2007


/s/ Michael O. Aldridge Michael O. Aldridge
Chief Financial Officer
November 6, 2007


/s/Charles T. Goodson Charles T. Goodson
Chief Executive Officer
November 6, 2007