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: June 30, 2008


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 No o

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o
(Do not check if a smaller reporting company)

Smaller reporting company 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 August 1, 2008 there were 50,438,268 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)


	June 30,			December 31,
	2008			2007
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	9,283		$	16,909
Revenue receivable		38,167			22,820
Joint interest billing receivable		21,342			22,936
Prepaid drilling costs		10,949			1,448
Other current assets		7,729			3,984

Total current assets		87,470			68,097

Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		1,046,803			907,083
Unevaluated oil and gas properties		123,633			80,297
Accumulated depreciation, depletion and amortization		(494,428	)		(432,530	)

Oil and gas properties, net		676,008			554,850
Gas gathering assets		26,101			22,040
Accumulated depreciation and amortization of gas gathering assets		(8,431	)		(6,640	)

Total property and equipment		693,678			570,250

Other assets, net of accumulated depreciation and amortization of $12,097 and $11,238, respectively		6,290			6,000

Total assets	$	787,438		$	644,347

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	69,418		$	78,273
Advances from co-owners		36,100			12,870
Oil and gas revenue payable		10,900			5,771
Asset retirement obligation		4,615			5,280
Hedge liability		39,313			691
Other accrued liabilities		9,413			8,955

Total current liabilities		169,759			111,840

Bank debt		52,500			—
10 3/8% Senior Notes		148,873			148,755
Asset retirement obligation		17,990			12,171
Deferred income taxes		76,139			69,160
Hedge liability		4,699			—
Other liabilities		155			104
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares		1			1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 49,195 and 48,414 shares, respectively		49			48
Paid-in capital		211,340			204,979
Accumulated other comprehensive loss		(27,727	)		(435	)
Retained earnings		133,660			97,724

Total stockholders’ equity		317,323			302,317

Total liabilities and stockholders’ equity	$	787,438		$	644,347

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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Revenues:
Oil and gas sales	$	90,614	$	64,830	$	165,433	$	126,714
Gas gathering revenue and other income		2,312		1,930		4,259		4,054

		92,926		66,760		169,692		130,768


Expenses:
Lease operating expenses		9,900		8,319		20,097		15,256
Production taxes		3,538		2,054		6,429		4,184
Depreciation, depletion and amortization		32,029		30,051		62,127		57,664
Gas gathering costs		826		1,344		1,774		2,294
General and administrative		7,149		5,324		12,316		10,504
Accretion of asset retirement obligation		301		226		548		441
Interest expense		2,390		3,938		4,889		7,570

		56,133		51,256		108,180		97,913


Income from operations		36,793		15,504		61,512		32,855
Income tax expense		13,733		5,874		23,008		12,411


Net income		23,060		9,630		38,504		20,444
Preferred stock dividend		1,285		—		2,568		—

Net income available to common stockholders	$	21,775	$	9,630	$	35,936	$	20,444


Earnings per common share:
Basic
Net income per share	$	0.45	$	0.20	$	0.74	$	0.43

Diluted
Net income per share	$	0.41	$	0.19	$	0.69	$	0.41


Weighted average number of common shares:
Basic		48,847		47,978		48,663		47,883

Diluted		56,011		49,690		55,720		49,556

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)


	Six Months Ended
	June 30,
	2008			2007
Cash flows from operating activities:
Net income	$	38,504		$	20,444
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		23,008			12,411
Depreciation, depletion and amortization		62,127			57,664
Accretion of asset retirement obligation		548			441
Share based compensation expense		4,671			5,486
Amortization expense and other		724			585
Payments to settle asset retirement obligations		(6,690	)		—
Changes in working capital accounts:
Revenue receivable		(15,347	)		(3,454	)
Joint interest billing receivable		1,594			(159	)
Prepaid drilling costs		(9,501	)		1,553
Accounts payable and accrued liabilities		(7,328	)		20,411
Advances from co-owners		23,230			835
Other		(4,746	)		(3,997	)


Net cash provided by operating activities		110,794			112,220


Cash flows from investing activities:
Investment in oil and gas properties		(167,398	)		(116,916	)
Investment in gas gathering assets		(4,061	)		(457	)
Sale of oil and gas properties and other		1,911			(509	)


Net cash used in investing activities		(169,548	)		(117,882	)


Cash flows from financing activities:
Net proceeds from (payments for) share based compensation		1,594			(450	)
Deferred financing costs		(96	)		(24	)
Payment of preferred stock dividend		(2,870	)		—
Repayment of bank borrowings		(15,500	)		(12,000	)
Proceeds from bank borrowings		68,000			15,000


Net cash provided by financing activities		51,128			2,526


Net decrease in cash and cash equivalents		(7,626	)		(3,136	)

Cash and cash equivalents, beginning of period		16,909			4,795


Cash and cash equivalents, end of period	$	9,283		$	1,659


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	8,811		$	9,757

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 six-month periods ended June 30, 2008 and 2007, 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 June 30, 2008 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, 2007 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, 2007.

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 and October 2007, the Company completed the public offering of an aggregate of 1,495,000 shares of its 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”). The net proceeds received from the offering totaled $70.7 million and were primarily used to repay outstanding borrowings under the Company’s credit facility.

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.

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. At June 30, 2008, the Company had accrued $1,073,022 in connection with the dividend payment made on July 15, 2008.

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 2008 periods also considers the effect of the Series B Preferred Stock issued in 2007 (Note 2) by applying the “if converted” method. Under this method, the dividends applicable to the Series B Preferred Stock are added to the numerator and the Series B Preferred Stock is assumed to have been converted to common shares in the denominator as of the date of issuance. 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 June 30, 2008	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	21,775		48,847	$	0.45

Effect of dilutive securities:
Stock options		—		1,257
Restricted stock		—		759
Series B preferred stock		1,285		5,148


DILUTED EPS	$	23,060		56,011	$	0.41


	Income		Shares		Per
For the Three Months Ended June 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	9,630		47,978	$	0.20

Effect of dilutive securities:
Stock options		—		1,135
Restricted stock		—		577


DILUTED EPS	$	9,630		49,690	$	0.19


	Income		Shares		Per
For the Six Months Ended June 30, 2008	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	35,936		48,663	$	0.74

Effect of dilutive securities:
Stock options		—		1,192
Restricted stock		—		717
Series B preferred stock		2,568		5,148


DILUTED EPS	$	38,504		55,720	$	0.69


	Income		Shares		Per
For the Six Months Ended June 30, 2007	(Numerator)		(Denominator)		Share Amount
BASIC EPS

Net income available to common stockholders	$	20,444		47,883	$	0.43

Effect of dilutive securities:
Stock options		—		1,153
Restricted stock		—		520


DILUTED EPS	$	20,444		49,556	$	0.41

Options to purchase 100,000 and 130,000 shares of common stock were outstanding during the three-and six-month periods ended June 30, 2008, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. These anti-dilutive options had an exercise price of $22.40 during the second quarter of 2008 and exercise prices that ranged between $21.30 and $22.40 during the six-month period of 2008. All of the anti-dilutive options in the 2008 periods expire during 2018.

Options to purchase 145,000 shares of common stock were outstanding during the three- and six-month periods ended June 30, 2007, but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. These anti-dilutive options’ exercise prices ranged between $13.49 and $14.48 during the periods. All of the anti-dilutive options in the 2007 periods expire in 2017.

Note 4 Long-Term Debt

During 2005, the Company and its wholly-owned subsidiary, 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 six months ended June 30, 2008.

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 June 30, 2008, $1.9 million had been accrued in connection with the November 15, 2008 interest payment and the Company was in compliance with all of the covenants under the Notes.

On November 18, 2005, the Company and 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 June 30, 2008, there were $52.5 million in borrowings outstanding under the credit facility.

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. In connection with such valuation, effective April 1, 2008, the borrowing base was increased from $80

million to $95 million. The next scheduled borrowing base re-determination will be on October 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 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the credit agreement. The credit 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 June 30, 2008, 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, 2008	$	17,451
Liabilities incurred during 2008		8,798
Liabilities settled during 2008		(11,020	)
Accretion expense		548
Revisions in estimated cash flows		6,828


Asset retirement obligation at June 30, 2008		22,605
Less: current portion of asset retirement obligation		(4,615	)

Long-term asset retirement obligation	$	17,990

Periodically, the Company revises its estimates regarding abandonment of its properties to consider changes in scope, timing and cost. During the first and second quarters of 2008, the Company revised its cost estimates to abandon several of its Gulf of Mexico properties.

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 three- and six-month periods ended June 30, 2008 and 2007 is as follows (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Stock options:
Incentive Stock Options	$	321	$	371	$	670	$	688
Non-Qualified Stock Options		698		507		1,232		912
Restricted stock		1,320		1,837		2,769		3,886

Share based compensation	$	2,339	$	2,715	$	4,671	$	5,486

During the three- and six-month periods ended June 30, 2008, the Company recorded income tax benefits of $0.7 million and $1.5 million, respectively, related to share based compensation expense recognized during those periods. The three- and six-month periods ended June 30, 2007 include income tax benefits of $0.9 million and $1.8 million, respectively, related 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.

Note 7 Derivative Instruments

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 are recorded in the income statement as derivative income or expense. At June 30, 2008, 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 ($7,787,000) and $1,318,000 and oil hedges of ($2,121,000) and $22,200 for the three months ended June 30, 2008 and 2007, respectively. For the six-month periods ended June 30, 2008 and 2007, oil and gas sales include additions (reductions) related to the settlement of gas hedges of ($7,613,000) and $3,841,000 and oil hedges of ($2,937,000) and $232,200, respectively.

As of June 30, 2008, 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:
2008	Costless Collar	20,000 Mmbtu	$7.75 — 8.78
July-December 2008	Costless Collar	22,500 Mmbtu	$8.83 — 12.06
2009	Costless Collar	20,000 Mmbtu	$9.50 — 12.94
Crude Oil:
2008	Costless Collar	400 Bbls	$70.00 — 75.55
July-December 2008	Costless Collar	500 Bbls	$100.00 — 167.25
2009	Costless Collar	400 Bbls	$100.00 — 168.50

At June 30, 2008, the Company recognized a liability of $44 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of June 30, 2008, the Company would realize a $24.8 million loss, net of taxes, as a reduction of oil and gas sales during the next 12 months. These losses are expected to be reclassified based on the production of oil and gas associated with the derivative contracts.

Note 8 New Accounting Standards

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about derivative and hedging activities, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company expects to adopt SFAS No. 161 beginning January 1, 2009, and is currently evaluating the impact, if any, SFAS No. 161 will have on its financial position or results of operations.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). SFAS No. 141(R) replaces SFAS No. 141, “Business Combinations,” and establishes principles and requirements for the recognition and measurement by an acquirer in its financial statements of the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree. The statement also establishes principles and requirements for the recognition and measurement of the goodwill acquired in the business combination or the gain from a bargain purchase and for information disclosed in its financial statements. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and certain other items at fair value. The Company adopted SFAS No. 159 on January 1, 2008 and elected not to account for any other assets or liabilities at fair value and thus the adoption had no impact to its financial statements.

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 under generally accepted accounting principles and expands disclosure about fair value measurements. The Company adopted SFAS No. 157 on January 1, 2008. The adoption did not have an effect on the Company’s financial position or results of operations.

As defined in SFAS No. 157, 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. SFAS 157 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.

With the adoption of SFAS 157, the Company classified its commodity derivatives based upon the data used to determine the fair values. The Company’s derivative instruments at June 30, 2008 were in the form of costless collars. The fair value of these derivatives is derived from quotes provided by the counterparties to the contracts. Although the Company believes the quotes are indicative of the approximate price at which the counterparty would be willing to settle such contracts as of the measurement date and there is observable market data underlying the quotes, there is not sufficient corroborating market evidence to support classifying these instruments as Level 2. As a result, the Company designates its commodity derivatives as Level 3 in the fair value hierarchy.

The following table summarizes the valuation of the Company’s instruments subject to fair value measurement on a recurring basis as of June 30, 2008 (in thousands):

Fair Value Measurements Using

Quoted Prices

Significant Other

Significant

in Active

Observable

Unobservable

Instrument

Markets (Level 1)

Inputs (Level 2)

Inputs (Level 3)

Commodity Derivatives

—

(44,012

)

The following table sets forth a reconciliation of changes in the fair value of our commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):


	Three Months Ended			Six Months Ended
	June 30, 2008			June 30, 2008
Balance at beginning of period	$	(17,748	)	$	(691	)
Total gains or losses (realized or unrealized):
Included in earnings		(9,908	)		(10,550	)
Included in other comprehensive income		(26,264	)		(43,321	)
Purchases, issuances and settlements		9,908			10,550
Transfers in and out of Level 3		—			—

Balance at end of period	$	(44,012	)	$	(44,012	)

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. 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.

Utilizing the cash flow generated by our higher margin Gulf Coast Basin assets, and leveraging strong commodity prices, we have been able to accelerate our penetration into longer life basins in Oklahoma, Arkansas and Texas through significantly increased and successful drilling activity and selective acquisitions. 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 and 2006, we acquired additional acreage in Oklahoma and Texas, initiated an expanded drilling program in these areas, opened an exploration office in Tulsa, Oklahoma and divested several mature, high-cost Gulf of Mexico fields. During 2007 we continued to diversify into longer life regions by acquiring unevaluated leasehold interests in Arkansas. Drilling operations targeting the Fayetteville Shale began on this acreage in September 2007. In addition, robust drilling activity continued in Oklahoma and Texas as we drilled 61 gross wells in these regions during 2007, realizing a 93% success rate.

Our 2007 results marked the fourth consecutive year we achieved annual company records for production, estimated proved reserves, cash flow from operating activities and net income. Our record results over the last four years reflect our consistent drilling success and correlate directly with the implementation of our asset diversification strategy during 2003. Comparing 2007 results with those in 2003, we have grown production by 226% and proved reserves by 88%.

At June 30, 2008, 71% of our estimated proved reserves were located in our longer life basins as compared to 61% at December 31, 2007. Approximately 42% of our second quarter 2008 production volumes were derived from our longer-life properties as compared to 33% during the fourth quarter of 2007. During the first half of 2008, 78% of our capital expenditures were allocated to our longer life properties.

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. 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. Declines in prices or reserves could result in a future write-down of oil and gas properties.

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 substantially, 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 engineers 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 NYMEX prices. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At June 30, 2008, 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 an approximate price at which they would be willing to settle such contracts as of the given date. We believe the values provided by our counterparties represent an accurate estimate of the fair value of the contracts.

New Accounting Standards

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133” (“SFAS No. 161”). SFAS No. 161 requires enhanced disclosures about derivative and hedging activities, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We expect to adopt SFAS No. 161 beginning January 1, 2009, and are currently evaluating the impact, if any, SFAS No. 161 will have on our financial position or results of operations.

prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008.

In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to choose to measure certain financial instruments and certain other items at fair value. We adopted SFAS No. 159 on January 1, 2008 and elected not to account for any other assets or liabilities at fair value. As a result, the adoption had no impact to our financial statements.

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 under generally accepted accounting principles and expands disclosure about fair value measurements. We adopted SFAS No. 157 on January 1, 2008 (see Note 8).

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				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007

Production:
Oil (Bbls)		172,804		286,692		366,580		646,473
Gas (Mcf)		7,380,648		6,103,848		14,108,476		11,636,162
Total Production (Mcfe)		8,417,472		7,824,000		16,307,956		15,515,000

Sales:
Total oil sales	$	19,437,078	$	19,510,894	$	37,666,918	$	41,098,794
Total gas sales		71,176,412		45,319,729		127,765,877		85,615,423

Total oil and gas sales	$	90,613,490	$	64,830,623	$	165,432,795	$	126,714,217


Average sales prices:
Oil (per Bbl)	$	112.48	$	68.06	$	102.75	$	63.57
Gas (per Mcf)		9.64		7.42		9.06		7.36
Per Mcfe		10.76		8.29		10.14		8.17

The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of ($7,787,000) and $1,318,000 and the settlement of oil hedges of ($2,121,000) and $22,200 for the three months ended June 30, 2008 and 2007, respectively. The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of ($7,613,000) and $3,841,000 and the settlement of oil hedges of ($2,937,000) and $232,200 for the six-month periods ended June 30, 2008 and 2007, respectively.

Net income available to common stockholders totaled $21,775,000 and $9,630,000 for the quarters ended June 30, 2008 and 2007, respectively, while net income available to common stockholders for the six-month periods ended June 30, 2008 and 2007 totaled $35,936,000 and $20,444,000, respectively. The increase during the 2008 periods was primarily attributable to the following:

Production. Oil production during the three- and six-month periods ended June 30, 2008 decreased 40% and 43%, respectively, from the comparable 2007 periods. The decrease in oil production is primarily the result of normal production declines at our Ship Shoal 72 and Turtle Bayou Fields, which produce approximately half of our total oil production. In addition, during the first quarter of 2008, we experienced shut-ins at Ship Shoal 72 and Main Pass 74, which represented approximately 29% of our production in the first six months of 2008, due to compressor repair work.

During late 2007, we began drilling operations on our Arkansas acreage. As a result of production from this new basin and our continued expansion into our longer life basins, where the production is primarily natural gas, our gas production during the three- and six-month periods ended June 30, 2008 increased 21% from the comparable 2007 periods. Overall, production during the first half of 2008 was 5% higher than the 2007 period.

During the five-year period ended December 31, 2007, we realized a 90% success rate on 329 gross wells drilled. Assuming there are no material production shut-ins during the remainder of 2008 and we are able to maintain our historically high drilling success rate, we expect that our production will continue to increase during 2008.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and six months ended June 30, 2008 were $112.48 and $102.75, respectively, as compared to $68.06 and $63.57, respectively, for the 2007 periods. Average gas prices per Mcf were $9.64 and $9.06 for the quarter and six months ended June 30, 2008, respectively, as compared to $7.42 and $7.36 for the respective 2007 periods. Stated on an Mcfe basis, unit prices received during the quarter and six months ended June 30, 2008 were 30% and 24% higher, respectively, than the prices received during the comparable 2007 periods.

Revenue. Oil and gas sales during the quarter and six months ended June 30, 2008 increased 40% and 31% to $90,614,000 and $165,433,000, respectively, as compared to oil and gas sales of $64,830,000 and $126,714,000 for the 2007 periods. The increased revenue during the 2008 periods was primarily the result of higher pricing and increased gas production. Assuming commodity prices remain at current levels, we expect that our revenues would continue to increase as we expect to grow our production during the remainder of 2008 through our drilling program.

Expenses. Lease operating expenses for the three- and six-month periods ended June 30, 2008 increased to $9,900,000 and $20,097,000, respectively, as compared to $8,319,000 and $15,256,000 during the 2007 periods. On a unit of production basis, operating expenses totaled $1.18 and $1.23 per Mcfe during the three- and six-month periods of 2008, respectively, as compared to $1.06 and $0.98 per Mcfe during the 2007 periods. The increase in per unit costs during the 2008 periods is primarily attributable to an increase in unscheduled major maintenance costs during the first half of 2008, as well as higher overall costs for materials, transportation and other services. We expect that per unit operating expenses, excluding any significant unscheduled major maintenance projects, for the remainder of 2008 will generally approximate the second quarter 2008 amount.

Production taxes during the quarter and six months ended June 30, 2008 totaled $3,538,000 and $6,429,000, respectively, as compared to $2,054,000 and $4,184,000 during the 2007 periods. The increase in 2008 production taxes is primarily due to higher prices and increased production from our Oklahoma, Arkansas and Texas properties. Offsetting these increases was a 28% reduction in the Louisiana gas severance tax rate effective July 1, 2007.

General and administrative expenses during the quarter and six months ended June 30, 2008 totaled $7,149,000 and $12,316,000, respectively, as compared to expenses of $5,324,000 and $10,504,000 during the comparable 2007 periods. Included in general and administrative expenses for the periods ended June 30, 2008 and 2007 was share-based compensation expense relative to SFAS 123(R) as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2008		2007		2008		2007
Stock options:
Incentive Stock Options	$	321,000	$	371,000	$	670,000	$	688,000
Non-Qualified Stock Options		698,000		507,000		1,232,000		912,000
Restricted stock		1,320,000		1,837,000		2,769,000		3,886,000

Share-based compensation	$	2,339,000	$	2,715,000	$	4,671,000	$	5,486,000

Excluding share-based compensation, general and administrative expense during the second quarter and six month periods ended June 30, 2008 increased 84% and 52%, respectively, from the comparable 2007 periods. During the second quarter of 2008, we elected to pay additional compensation of $2.5 million, or approximately $1.2 million net of capitalization, to assist our employees with their tax burden associated with the vesting of restricted stock grants. This additional compensation expense, along with other employee-related costs associated with the 32% increase in our staffing since June 2007, represented the majority of the increase in general and administrative costs for the 2008 periods, as compared to 2007. We expect that general and administrative expenses for the third and fourth quarters of 2008 would be less than the second quarter of 2008.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and six months ended June 30, 2008 totaled $30,930,000, or $3.67 per Mcfe, and $59,987,000, or $3.68 per Mcfe, respectively, as compared to $29,162,000, or $3.73 per Mcfe, and $55,926,000, or $3.60 per Mcfe, respectively, during the 2007 periods. Assuming commodity prices remain at current levels, we would expect the per unit costs to drill for, develop and acquire oil and gas reserves for the remainder of 2008 to generally approximate second quarter 2008 levels.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,390,000 and $4,889,000, respectively, during the quarter and six months ended June 30, 2008 as compared to $3,938,000 and $7,570,000 during the 2007 periods. We capitalized $2,511,000 and $4,801,000 of interest during the three- and six-month periods of 2008 and $1,411,000 and $2,763,000 during the respective 2007 periods. The increase in the capitalized portion of our interest cost during the 2008 periods is due to the increase in our unevaluated properties, which is primarily the result of leasehold acquisitions in our longer-life basins.

Income tax expense during the quarter and six-month period ended June 30, 2008 totaled $13,733,000 and $23,008,000, respectively, as compared to $5,874,000 and $12,411,000 during the respective 2007 periods. The increase is primarily the result of the increased operating profit in the 2008 periods as compared to 2007. 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. At June 30, 2008, we had a working capital deficit of $82.3 million compared to a deficit of $43.7 million at December 31, 2007. The increase in our working capital deficit at June 30, 2008 was primarily attributable to the $38.6 million increase in the current portion of our hedge liability resulting from higher estimated future commodity prices.

We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity. At June 30, 2008 we had $42.5 million of borrowings available under our bank credit facility. On July 31, 2008, we sold the majority of our gas gathering systems located in Oklahoma for $41.3 million. After using the net proceeds of $40.3 million to repay a portion of the borrowings outstanding under our bank credit facility, we had $65 million of borrowings available as of August 4, 2008 to address our working capital deficit.

Source of Capital: Operations

Net cash flow from operations decreased from $112,220,000 during the six months ended June 30, 2007 to $110,794,000 during the 2008 period. The decrease in operating cash flow was primarily attributable to the timing of payments made to reduce our accounts payable to vendors and the increase in our revenue receivable, which is the result of increased production and realized prices in June 2008, offset by an increase in advance payments received from partners for near-term drilling projects.

Source of Capital: Debt

During 2005, we issued $150 million in principal amount of our 10 3/8% Senior Notes, which 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 June 30, 2008, $1.9 million had been accrued in connection with the November 15, 2008 interest payment and 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. As of August 4, 2008, we had $30 million of borrowings outstanding under the credit facility.

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. In connection with such valuation, effective April 1, 2008, the borrowing base was increased from $80 million to $95 million. The next scheduled borrowing base re-determination will be on October 1, 2008 and we or the lenders may request additional borrowing base re-determinations.

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.

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 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the credit agreement. The credit 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. At June 30, 2008, we were in compliance with all of the covenants under the credit facility.

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

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 any 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. On July 31, 2008, we sold the majority of our gas gathering systems located in Oklahoma for $41.3 million. The net proceeds from the sale were used to repay a portion of the borrowings outstanding under our credit facility in order to provide increased liquidity to execute our capital program. There can be no assurance that we will be able to sell any of our assets in the future.

Use of Capital: Acquisitions

We do not budget for acquisitions; however, we are continually evaluating opportunities that fit our specific acquisition profile. During the first half of 2008 we completed several acquisitions in our longer life basins. In Texas, we acquired an additional 50% interest and control of operations in our Weekley Prospect for approximately $20 million. The initial test well from this primarily oil targeted prospect came on-line during the first quarter of 2008. In addition, we closed several leasehold transactions in Oklahoma for a combined cost of approximately $20 million. These acquisition costs were funded through borrowings under our credit facility and a majority of the acreage is considered unevaluated at June 30, 2008.

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.

Use of Capital: Exploration and Development

Our 2008 capital budget, which excludes acquisitions and capitalized interest and general and administrative costs, is expected to range between $270 million and $300 million, of which $113.3 million was incurred during the first half of 2008. Based on our outlook of commodity prices and production, we believe that we will be able to fund the remainder of our planned 2008 exploration and development activities with cash on hand, cash flow from operations and available bank borrowings. Our future exploration and development activities, or any significant acquisitions, could require additional financings, which may include sales of additional equity or debt securities, additional bank borrowings, sales of properties or assets, 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.

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 or future reserves, 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 remainder of 2008, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $19 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 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 quarter and six month periods ended June 30, 2008 we paid to the counterparties to our derivative instruments $9,908,000 and $10,550,000, 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 June 30, 2008, 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:
2008	Costless Collar	20,000 Mmbtu	$7.75 — 8.78
July-December 2008	Costless Collar	22,500 Mmbtu	$8.83 — 12.06
2009	Costless Collar	20,000 Mmbtu	$9.50 — 12.94
Crude Oil:
2008	Costless Collar	400 Bbls	$70.00 — 75.55
July-December 2008	Costless Collar	500 Bbls	$100.00 — 167.25
2009	Costless Collar	400 Bbls	$100.00 — 168.50

At June 30, 2008, we recognized a liability of $44 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of June 30, 2008, we would realize a $24.8 million loss, net of taxes, as a reduction to oil and gas sales during the next 12 months. These losses are expected to be reclassified based on the production of oil and gas associated with the derivative contracts.

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 26% of our total debt as of June 30, 2008. Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of June 30, 2008, and assuming a 10% increase in interest rates and no changes in the amount of debt outstanding, the potential effect on interest expense for the remainder of 2008 is approximately $0.1 million.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

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

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 15% and 14%, respectively, of our production during the first six months of 2008. 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.

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 June 30, 2008, the aggregate amount of our outstanding indebtedness was $201 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;

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

	•		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.

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

On May 14, 2008, we held our 2008 annual meeting of stockholders. The holders of 46,784,869 shares of common stock were present in person or represented by proxy at the meeting. At the meeting, the stockholders took the following actions:

(a)

Election of Directors

The stockholders elected the following persons to serve as our directors until the next annual meeting of stockholders or until their successors are duly elected and qualified:


	Number of		Number of
	Votes		Votes
Name	For		Withheld
Charles T. Goodson		46,334,150		450,718
William W. Rucks, IV		44,783,256		2,001,612
E. Wayne Nordberg		44,780,156		2,004,712
Michael L. Finch		44,783,766		2,001,102
W. J. Gordon, III		44,787,611		1,997,257
Charles F. Mitchell, II, M.D.		44,781,081		2,003,787

(b)

Ratification of the Appointment of Ernst & Young LLP

The stockholders ratified the appointment of Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2008 as follows:


Number of	Number of		Number of
Votes	Votes		Votes
For	Against		Abstaining
46,640,873		65,604		78,391

(c)

Approval of the proposed amendment to the Certificate of Incorporation

The stockholders approved the amendment of the Cerfiticate of Incorporation to increase the number of authorized shares of common stock from 75,000,000 to 150,000,000 as follows:


Number of	Number of		Number of
Votes	Votes		Votes
For	Against		Abstaining
41,071,725		5,387,845		325,293

(d) Adoption of the Amended and Restated 1998 Incentive Plan

The stockholders ratified the adoption of the Amended and Restated 1998 Incentive Plan as follows:

Number of

Votes

Broker

For

Against

Abstaining

Non-Votes

23,340,816

16,716,048

234,791

6,493,214

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

Exhibit 10.1, PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective May 14, 2008 (incorporated by reference to Appendix A to the Company’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 9, 2008).

Exhibit 10.2, Amendment No. 5 to Second Amended and Restated Credit Agreement, dated effective as of April 1, 2008, 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 by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on April 25, 2008).

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 INDEX

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.


			Page No.
Part I. Financial Information

Item 1. Financial Statements

Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007			1

Consolidated Statements of Income for the Three and Six Months Ended June 30, 2008 and 2007			2

Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2008 and 2007			3

Consolidated Statements of Comprehensive Income for the Three and Six Months Ended June 30, 2008 and 2007			4

Notes to Consolidated Financial Statements			5

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			12

Item 3. Quantitative and Qualitative Disclosures About Market Risk			19

Item 4. Controls and Procedures			20

Part II. Other Information

Item 1. Legal Proceedings			20

Item 1A. Risk Factors			20

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			22

Item 3. Defaults upon Senior Securities			22

Item 4. Submission of Matters to a Vote of Security Holders			22

Item 5. Other Information			23

Item 6. Exhibits			23
Certification of CEO Pursuant to Rule 13a-14(a)/Rule 15d-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)/Rule 15d-14(a)
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


	PETROQUEST ENERGY, INC.
Date: August 7, 2008	/s/ W. Todd Zehnder
	W. Todd Zehnder
	Executive Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial Officer)



/s/ W. Todd Zehnder
W. Todd Zehnder
Chief Financial Officer
August 7, 2008



/s/ W. Todd Zehnder
W. Todd Zehnder
Chief Financial Officer
August 7, 2008

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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
August 7, 2008



/s/ Charles T. Goodson
Charles T. Goodson
Chief Executive Officer
August 7, 2008