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, 2006


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: 019020

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)


DELAWARE (State of Incorporation)		72-1440714 (I.R.S. Employer Identification No.)


400 E. Kaliste Saloom Rd., Suite 6000 Lafayette, Louisiana (Address of principal executive offices)		70508 (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

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		Accelerated Filer X		Non-accelerated filer

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

Yes No þ

As of August 1, 2006, there were 47,634,391 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents


			Page No.
Part I.	Financial Information

	Item 1.	Financial Statements

		Consolidated Balance Sheets as of June 30, 2006 and December 31, 2005		1

		Consolidated Statements of Income for the Three and Six Months Ended June 30, 2006 and 2005		2

		Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2006 and 2005		3

		Notes to Consolidated Financial Statements		4

	Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations		10

	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		18

	Item 4.	Controls and Procedures		19

Part II.	Other Information

	Item 1.	Legal Proceedings		19

	Item 1A.	Risk Factors		19

	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		21

	Item 3.	Defaults upon Senior Securities		21

	Item 4.	Submission of Matters to a Vote of Security Holders		21

	Item 5.	Other Information		22

	Item 6.	Exhibits		22
Certification of CEO Pursuant to Rule 13a-14(a)
Certification of CFO Pursuant to Rule 13a-14(a)
Certification of CEO Pursuant to Section 1350
Certification of CFO Pursuant to Section 1350

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


	June 30,			December 31,
	2006			2005
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	8,488		$	6,703
Revenue receivable		20,870			22,492
Joint interest billing receivable		21,759			17,567
Hedging asset		901			—
Other current assets		7,939			3,441

Total current assets		59,957			50,203


Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		616,537			523,212
Unevaluated oil and gas properties		46,480			52,745
Accumulated depreciation, depletion and amortization		(252,386	)		(210,774	)

Oil and gas properties, net		410,631			365,183
Gas gathering assets		17,926			10,861
Accumulated depreciation and amortization of gas gathering assets		(2,186	)		(1,055	)

Total property and equipment		426,371			374,989


Other assets, net of accumulated depreciation and amortization of $10,998 and $10,353, respectively		6,560			6,278


Total assets	$	492,888		$	431,470


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	47,911		$	41,462
Advances from co-owners		10,029			5,874
Oil and gas revenue payable		8,264			8,090
Hedging liability		—			15,987
Other accrued liabilities		11,446			10,542

Total current liabilities		77,650			81,955

Bank debt		33,000			10,000
10 3/8% senior notes		148,436			148,340
Asset retirement obligation		18,650			19,257
Deferred income taxes		42,456			27,139
Other liabilities		253			242
Commitments and contingencies

Stockholders’ equity:
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 47,451 and 47,325 shares, respectively		47			47
Paid-in capital		118,878			117,441
Accumulated other comprehensive income (loss)		1,894			(7,444	)
Retained earnings		51,624			34,493

Total stockholders’ equity		172,443			144,537

Total liabilities and stockholders’ equity	$	492,888		$	431,470

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,
	2006		2005		2006		2005
Revenues:
Oil and gas sales	$	49,868	$	29,977	$	96,884	$	51,649
Gas gathering revenue and other income		1,628		302		2,970		373

		51,496		30,279		99,854		52,022


Expenses:
Lease operating expenses		8,827		4,965		15,778		8,847
Production taxes		1,212		762		2,782		1,136
Depreciation, depletion and amortization		20,352		11,859		39,071		20,054
Gas gathering costs		927		—		1,644		—
General and administrative		3,344		1,819		5,499		3,508
Accretion of asset retirement obligation		383		205		753		405
Interest expense		3,627		4,723		6,999		5,685

		38,672		24,333		72,526		39,635


Income from operations		12,824		5,946		27,328		12,387

Income tax expense		4,842		2,081		10,197		4,335


Net income	$	7,982	$	3,865	$	17,131	$	8,052


Earnings per common share:
Basic	$	0.17	$	0.08	$	0.36	$	0.17


Diluted	$	0.16	$	0.08	$	0.35	$	0.17


Weighted average number of common shares:
Basic		47,394		46,969		47,360		46,158

Diluted		48,900		48,205		48,809		47,840

See accompanying Notes to Consolidated Financial Statements.

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


	Six Months Ended
	June 30,
	2006			2005
Cash flows from operating activities:
Net income	$	17,131		$	8,052
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		10,197			4,335
Depreciation, depletion and amortization		39,071			20,054
Accretion of asset retirement obligation		753			405
Amortization of debt issuance costs		467			841
Write-off of debt issuance costs		—			2,439
Amortization of bond discount		96			20
Stock based compensation expense		1,047			—
Compensation expense		—			213
Changes in working capital accounts:
Accounts receivable		1,622			(1,886	)
Joint interest billing receivable		418			(1,652	)
Accounts payable and accrued liabilities		5,515			(6,430	)
Advances from co-owners		4,155			11,855
Other assets		(5,324	)		(1,162	)


Net cash provided by operating activities		75,148			37,084


Cash flows from investing activities:
Investment in oil and gas properties		(91,434	)		(65,167	)
Investment in gas gathering assets		(5,218	)		(3,894	)


Net cash used in investing activities		(96,652	)		(69,061	)


Cash flows from financing activities:
Proceeds from exercise of options		390			546
Deferred financing costs		(101	)		(5,274	)
Proceeds from issuance of 10 3/8% senior notes		—			148,229
Issuance of common stock, net of expenses		—			4,051
Repayment of bank borrowings		—			(73,000	)
Proceeds from bank borrowings		23,000			34,500


Net cash provided by financing activities		23,289			109,052


Net increase in cash and cash equivalents		1,785			77,075

Cash and cash equivalents, beginning of period		6,703			1,529


Cash and cash equivalents, end of period	$	8,488		$	78,604


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	8,407		$	1,561


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, 2006 and 2005, 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, 2006 and for all reported periods. Certain reclassifications of prior year amounts have been made to conform to the current year presentation. 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, 2005 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, 2005.

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 Earnings Per Share

Basic earnings per common share is computed by dividing net income 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 warrants considered dilutive computed using the treasury stock method. A reconciliation between basic and diluted shares outstanding (in thousands) is as follows:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Basic shares outstanding		47,394		46,969		47,360		46,158
Effect of stock options		1,424		1,236		1,408		1,278
Effect of restricted stock		82		—		41		—
Effect of warrants		—		—		—		404

Diluted shares outstanding		48,900		48,205		48,809		47,840

In addition to the stock options included in the reconciliation above, options to purchase 40,000 and 25,000 shares of common stock were outstanding during the three- and six-month periods ended June 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 $11.75 and $12.21 during the second quarter of 2006 and between $9.99 and $12.21 during the six month period of 2006. All of the anti-dilutive options in the 2006 periods expire in 2016.

Options to purchase 90,000 shares of common stock were outstanding during the three- and six-month periods ended June 30, 2005, 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 period. These options’ exercise prices ranged between $6.64 and $7.65, and expire in 2011-2015.

Note 3 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 six months ended June 30, 2006.

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, 2006, $1.9 million had been accrued in connection with the November 15, 2006 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 with 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. The credit agreement, which was amended in December 2005, provides for a $100 million revolving credit facility that permits borrowings from time to time 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.

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 upon the valuation as of January 1 and July 1 of each year of the mortgaged oil and gas properties and any other credit factors deemed relevant by the lenders. The borrowing base is currently $67.5 million and the next scheduled borrowing base redermination will be on October 1, 2006. The Company or the lenders may request additional borrowing base re-determinations. As of June 30, 2006, there were $33 million of borrowings outstanding under the credit facility and the Company was in compliance with all of the covenants therein.

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. Outstanding letters of credit will be charged a letter of credit fee equal to the applicable margin for advances at the Eurodollar rate.

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.

Note 4 Asset Retirement Obligation

In June 2001, the Financial Accounting Standards Board 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):


	Six Months Ended
	June 30, 2006

Asset retirement obligation at beginning of year	$	21,607
Liabilities incurred during 2006		675
Liabilities settled during 2006		(253	)
Accretion expense		753
Revisions in estimated cash flows		(446	)


Asset retirement obligation at end of period		22,336
Less: current portion of asset retirement obligation		(3,686	)

Long-term asset retirement obligation	$	18,650

Note 5 New Accounting Standards

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. We adopted the standard during the first quarter of 2006.

We elected to adopt SFAS 123(R) using the “modified prospective” method in which compensation cost is recognized beginning with the effective date of January 1, 2006 using the requirements of SFAS 123(R) for all share-based payments granted after the effective date and the requirements of SFAS 123 for all unvested awards at the effective date related to awards granted prior to the effective date.

During the second quarter and six months ended June 30, 2006, the Company recognized $987,000 and $1,047,000, respectively, of share based compensation expense. These non-cash expenses are reflected as a component of the Company’s general and administrative expense. The impact to net income of adopting SFAS 123(R) for the second quarter and six month periods of 2006 was $719,000, or approximately $0.02 per basic and diluted share, and $768,000, or approximately $0.02 per basic and diluted share, respectively.

At June 30, 2006, the Company had $12,813,000 of unrecognized compensation expense related to granted, but unvested restricted stock and stock options. This expense will be recognized over a weighted average period of 4.2 years from June 30, 2006.

The components of share based compensation expense for the periods ended June 30, 2006 were as follows:


	Second		Six
	Quarter		Months
Stock options	$	340,000	$	400,000
Restricted stock		647,000		647,000

Share based compensation	$	987,000	$	1,047,000

Stock Options

The Company computes the fair value of its stock options using the Black-Scholes option-pricing model assuming a stock option forfeiture rate based on historical activity, an expected term of six years, using the shortcut method prescribed in SAB 107 and expected volatility computed using historical stock price fluctuations on a weekly basis for a period of time equal to the expected term of the option. Stock options vest equally over a three-year period from the date of grant and the Company recognizes compensation expense using the accelerated expense attribution method over the vesting period. Periodically the Company adjusts compensation expense based on the difference between actual and estimated forfeitures.

The following table outlines the assumptions used in computing the fair value of stock options granted during the six months ended June 30, 2006 and 2005:


	Six Months Ended June 30,
	2006		2005
Dividend yield		0%		0%
Expected volatility		61.3% — 62.8%		62.8% — 64.5%
Risk-free rate		4.5% — 5.1%		3.8% — 4.3%
Expected term	6 years		5 years
Forfeiture rate		8.4%		0%

Stock options granted (1)		566,030		130,000
Weighted avg. fair value per share	$	6.64	$	3.38
Fair value of grants (1)	$	3,761,200	$	439,600


(1)		Prior to applying estimated forfeiture rate

The following table details stock option activity during the six months ended June 30, 2006:


							Aggregate
	Number of			Wgtd. Avg.		Wgtd. Avg.	Intrinsic Value
	Options			Exercise Price		Remaining Life	(000’s)
Outstanding at beginning of year		2,311,564		$	3.08
Granted		566,030			10.82
Expired/cancelled/forfeited		(7,342	)		4.59
Exercised		(125,767	)		3.15

Outstanding at end of period		2,744,485			4.67	7.1 yrs	$	20,881

Options exercisable at end of period		1,926,548		$	2.92	6.1 yrs	$	18,024
Options expected to vest		749,227		$	8.79	9.5 yrs	$	2,617

Restricted Stock

The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock at the date of grant and assuming an 8.4% estimated forfeiture rate. Restricted stock vests over a five year period with one-fourth vesting on each of the first, second, third and fifth anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant. Compensation expense related to restricted stock is recognized over the vesting period using the accelerated expense attribution method. Periodically the Company adjusts compensation expense based on the difference between actual and estimated forfeitures.

During the six months ended June 30, 2006, the Company granted 1,033,761 shares of restricted stock with a pre-forfeiture fair value of $11.1 million. The fair value of restricted stock granted during 2006 was $10.75 per share. The restricted stock grants in May 2006 were the Company’s first use of this type of share based compensation. As a result, there were no shares of restricted stock vested during 2006.

SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reflected as a financing cash flow, rather than as an operating cash flow as was previously required. The Company did not recognize any excess tax deductions during any periods presented in connection with the exercise of stock options.

Prior to the adoption of SFAS 123R on January 1, 2006, the Company accounted for its share based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no share based

compensation cost is reflected in net income prior to January 1, 2006, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant.

The following table illustrates the pro forma effect on net income and earnings per share for the periods presented prior to the adoption of SFAS 123R, if the Company had applied the fair value recognition provisions of SFAS No. 123, “Accounting for Stock Based Compensation” pursuant to the disclosure requirements of SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure” (in thousands, except per share data):


	Period Ended June 30, 2005
	Three Months			Six Months
Net income	$	3,865		$	8,052
Stock-based compensation:
Add expense included in reported results, net of tax		—			22
Deduct fair value based method, net of tax		(155	)		(331	)

Pro forma net income	$	3,710		$	7,743


Earnings per common share:
Basic — as reported	$	0.08		$	0.17
Basic — pro forma	$	0.08		$	0.17
Diluted — as reported	$	0.08		$	0.17
Diluted — pro forma	$	0.08		$	0.16

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 will become effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact, if any, that FIN 48 will have on its financial position and results of operations.

Note 6 Other Comprehensive Income and Derivative Instruments

The following table presents the Company’s comprehensive income for the three and six month periods ended June 30, 2006 and 2005 (in thousands):


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2006		2005		2006		2005
Net income	$	7,982	$	3,865	$	17,131	$	8,052
Change in fair value of derivative instruments, accounted for as hedges, net of taxes		2,284		1,518		9,338		(1,572	)

Comprehensive income	$	10,266	$	5,383	$	26,469	$	6,480

For the three months ended June 30, 2006 and 2005, the effect of derivative instruments is net of deferred income tax expense of $1,440,000 and $817,000, respectively. For the six month periods ended June 30, 2006 and 2005, the effect of derivative instruments is net of deferred income tax (expense) benefit of ($5,121,000) and $846,000, respectively.

The Company accounts for derivatives in accordance with SFAS 133, as amended. When the conditions 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 as other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected

event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement as derivative expense. At June 30, 2006, our derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $2,328,000 and ($813,000) and oil hedges of ($808,000) and ($1,262,000) for the three months ended June 30, 2006 and 2005, respectively. For the six month periods ended June 30, 2006 and 2005, oil and gas sales include additions (reductions) related to the settlement of gas hedges of $3,367,000 and ($1,078,000) and oil hedges of ($1,485,000) and ($2,341,000), respectively.

As of June 30, 2006, 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:
2006	Swap	5,500 Mmbtu	$	4.33
Third Quarter 2006	Costless Collar	21,000 Mmbtu	$	7.81 — 10.74
Fourth Quarter 2006	Costless Collar	14,000 Mmbtu	$	8.14 — 12.42
2007	Costless Collar	10,000 Mmbtu	$	9.00 — 11.00

Crude Oil:
Third Quarter 2006	Costless Collar	700 Bbls	$	53.00 — 61.36
Fourth Quarter 2006	Costless Collar	500 Bbls	$	48.20 — 55.95
January—June 2007	Costless Collar	300 Bbls	$	65.00 — 79.10
July—December 2007	Costless Collar	200 Bbls	$	65.00 — 77.70

At June 30, 2006, the Company recognized an asset of $0.9 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of June 30, 2006, the Company would realize a $0.6 million gain, net of taxes, as an addition of oil and gas sales during the next 12 months. These gains are expected to be reclassified as the oil and gas volumes underlying the derivative contracts are produced and sold.

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 Gulf of Mexico shelf. Beginning in 2003, we began diversifying our reserves and production with longer life onshore properties in Texas and Oklahoma, and we enhanced our risk management policies by reducing our average working interest in projects, shifting capital to higher probability onshore wells and reducing the risks associated with individual wells by expanding our drilling program.

In particular, in 2003 we acquired properties in the Southeast Carthage Field in East Texas with 29 Bcfe of proved reserves. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring 10.5 Bcfe of proved reserves. During 2005, we increased our presence in Oklahoma through multiple acquisition transactions and an expanded drilling program consisting of 58 gross wells drilled. In the Carthage Field we successfully drilled an additional 15 wells during 2005, growing field production from 2004 by over 50%. In total, we drilled 75 wells in longer life basins during 2005, which represented 87% of the total wells we drilled during 2005. Through these focused diversification efforts, approximately 50% of our proved reserves were located in longer life basins at December 31, 2005, as compared to 45% and 35% at December 31, 2004 and 2003, respectively. In terms of production diversification, during the first six months of 2006, 31% of our production was derived from longer life basins versus 30% during 2005, 16% during 2004 and virtually none in 2003.

We seek to grow proved reserves, production, cash flow and earnings at low finding and development costs through a mix of lower risk development and exploitation activities, higher risk and higher impact exploration activities and acquisitions. We were successful in 2005 in achieving company records for proved reserves, production, cash flow from operating activities and net income. During 2005, we increased these operational and financial metrics by 29%, 13%, 4% and 31%, respectively, from 2004 levels. Our record results were achieved by our ability to capitalize on another year of strong commodity prices which enabled us to substantially increase our capital expenditures. During 2005, we invested approximately $196 million, a 128% increase from 2004, into our exploration, development and acquisition activities. These investments yielded a 91% success rate on a company record 86 wells drilled and the consummation of several strategic acquisitions.

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. 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, 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 to other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement.

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 June 30, 2006, 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 December 2004, the Financial Accounting Standards Board issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. The effective date for adoption is the first fiscal year beginning on or after June 15, 2005. Accordingly, we adopted the standard during the first quarter of 2006.

SFAS 123(R) permits adoption using one of two methods. A “modified prospective” method in which compensation cost is recognized beginning with the effective date using the requirements of SFAS 123(R) for all share-based payments granted after the effective date and the requirements of SFAS 123 for all unvested awards at

the effective date related to awards granted prior to the effective date. An alternate method, the “modified retrospective” method includes the requirements of the modified prospective method described above, but also permits entities to retroactively adjust, based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures, either (a) all prior periods presented or (b) prior interim periods of the year of adoption. We elected to adopt SFAS 123(R) using the “modified prospective” method.

During the second quarter and six months ended June 30, 2006, we recognized $987,000 and $1,047,000, respectively, of share based compensation expense. These non-cash expenses are reflected as a component of our general and administrative expense. The impact to net income of adopting SFAS 123(R) for the second quarter and six month periods of 2006 was $719,000, or approximately $0.02 per basic and diluted share, and $768,000, or approximately $0.02 per basic and diluted share, respectively.

At June 30, 2006, we had $12,813,000 of unrecognized compensation expense related to granted, but unvested restricted stock and stock options. This expense will be recognized over a weighted average period of 4.2 years from June 30, 2006. See Note 5 to our financial statements for more detailed information relative to share based compensation.

We previously accounted for our share based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no share based compensation cost is reflected in net income prior to January 1, 2006, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. See Note 5 for disclosure of share based compensation cost prior to January 1, 2006 reflected on a pro forma basis as prior period financial statements have not been restated.

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 will become effective for fiscal years beginning after December 15, 2006. We are currently evaluating the impact, if any, that FIN 48 will have on our financial position and results of operations.

Results of Operations

The following table (unaudited) sets forth certain operating 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,
	2006		2005		2006		2005
Production:
Oil (Bbls)		187,449		217,156		342,423		398,555
Gas (Mcf)		5,408,047		3,252,510		10,285,010		5,501,623
Total Production (Mcfe)		6,532,741		4,555,446		12,339,548		7,892,953

Sales:
Total oil sales	$	12,254,099	$	9,747,130	$	21,019,667	$	17,619,699
Total gas sales		37,613,962		20,229,581		75,864,315		34,028,518

Total oil and gas sales		49,868,061		29,976,711		96,883,982		51,648,217

Average sales prices:
Oil (per Bbl)	$	65.37	$	44.89	$	61.39	$	44.21
Gas (per Mcf)		6.96		6.22		7.38		6.19
Per Mcfe		7.63		6.58		7.85		6.54

The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of $2,328,000 and ($813,000) and the settlement of oil hedges of ($808,000) and ($1,262,000) for the three months ended June 30, 2006 and 2005, respectively. The above sales and average sales prices include additions

(reductions) to revenue related to the settlement of gas hedges of $3,367,000 and ($1,078,000) and the settlement of oil hedges of ($1,485,000) and ($2,341,000) for the six month periods ended June 30, 2006 and 2005, respectively.

Net income totaled $7,982,000 and $3,865,000 for the quarters ended June 30, 2006 and 2005, respectively, while net income for the six month periods ended June 30, 2006 and 2005 totaled $17,131,000 and $8,052,000, respectively. The increase in net income during the 2006 periods was primarily attributable to the following:

Production. Oil production during the three and six month periods ended June 30, 2006 decreased 14% from the respective 2005 periods, while natural gas production during the quarter and six months ended June 30, 2006 increased 66% and 87%, respectively, from the comparable 2005 periods. In total, production during 2006 was 43% and 56% higher than the production during the quarter and six months ended June 30, 2005. During the six months ended June 30, 2006, 83% of our total production was natural gas as compared to 70% during the 2005 period. This shift towards natural gas is the result of our expanded operations in Texas and Oklahoma where our production is primarily natural gas.

The increase in production as compared to the 2005 periods was the result of the restoration of production at our Main Pass 74 Field in January 2006, the impact of several acquisitions of producing properties made during 2005 and production attributable to the 91% drilling success rate we achieved during 2005. Production from Main Pass 74 accounted for 17% of our total production for the second quarter and six month periods of 2006.

We expect to drill approximately 130 gross wells during 2006, a 51% increase from 2005. We expect that our 2006 expanded drilling program, along with wells that have been successfully drilled and are awaiting connections to sales lines, will provide additional production growth during 2006.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and six months ended June 30, 2006 were $65.37 and $61.39, as compared to $44.89 and $44.21, respectively, for the 2005 periods. Average gas prices per Mcf were $6.96 and $7.38 for the quarter and six months ended June 30, 2006, respectively, as compared to $6.22 and $6.19 for the respective periods in 2005. Stated on an Mcfe basis, unit prices received during the quarter and six months ended June 30, 2006 were 16% and 20% higher, respectively, than the prices received during the comparable 2005 periods.

Revenue. Oil and gas sales during the quarter and six months ended June 30, 2006 increased 66% and 88% to $49,868,000 and $96,884,000, respectively, as compared to oil and gas revenues of $29,977,000 and $51,649,000 for the 2005 periods. Higher commodity prices and production volumes generated the increased revenue during the 2006 periods.

During the quarter and six month periods of 2006, gas gathering revenue and other income totaled $1,628,000 and $2,970,000, respectively, as compared to $302,000 and $373,000 during the 2005 periods. The increase in 2006 is primarily due to income generated by our gas gathering assets, which were acquired in connection with certain purchases of oil and gas properties during 2005. Amounts recorded in the 2005 periods primarily consist of interest and other miscellaneous income.

Expenses. Lease operating expenses for the three and six month periods ended June 30, 2006 increased to $8,827,000 and $15,778,000, as compared to $4,965,000 and $8,847,000 during the 2005 periods. On an Mcfe basis, lease operating expenses for the three and six month periods of 2006 totaled $1.35 and $1.28, respectively, as compared to $1.09 and $1.12 for the 2005 periods. Operating costs during the 2006 periods were higher due to a significant increase in the number of producing wells in which we participate, which is the result of 2005 acquisitions and our expanded drilling program during 2005 and the first half of 2006. In addition, operating costs were higher in the current period because of the increased cost of oil field related services prevalent throughout the industry, such as labor, transportation, insurance and materials. We expect this trend in increased operating expenses to continue throughout 2006.

At June 30, 2006, we had a $4.1 million receivable representing our estimate of costs incurred to repair hurricane related damages that we believe qualify for insurance reimbursement. During the second quarter of 2006, we received a partial payment on our claim totaling $1.4 million.

Production taxes during the second quarter and six months ended June 30, 2006 totaled $1,212,000 and $2,782,000, as compared to $762,000 and $1,136,000 during the 2005 periods. Production taxes in Texas and Oklahoma are predominately value based and therefore fluctuate in relation to commodity prices. The increase in 2006 production taxes is primarily due to higher commodity prices coupled with significantly increased production from our Oklahoma and Texas properties.

Gas gathering costs during the three and six month periods ended June 30, 2006 totaled $927,000 and $1,644,000. Because our gas gathering assets were acquired in connection with purchases of certain oil and gas properties in 2005, gas gathering costs during the respective 2005 periods were minimal and recorded as a component of lease operating expenses.

General and administrative expenses during the quarter and six months ended June 30, 2006 totaled $3,344,000 and $5,499,000 as compared to expenses of $1,819,000 and $3,508,000 during the 2005 periods. Included in general and administrative expenses for the three and six month periods ended June 30, 2006 was $987,000 and $1,047,000, respectively, attributable to share based compensation recognized in connection with the adoption of SFAS 123R on January 1, 2006. We capitalized $1,468,000 and $2,929,000 of general and administrative costs during the three and six month periods ended June 30, 2006, respectively, and $1,051,000 and $2,303,000 during the comparable 2005 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and six months ended June 30, 2006 totaled $19,641,000 or $3.01 per Mcfe and $37,763,000 or $3.06 per Mcfe, as compared to $11,693,000 or $2.57 per Mcfe and $19,786,000 or $2.51 per Mcfe in the respective periods of 2005. The increase in DD&A expense per Mcfe is primarily due to increased costs to drill for, develop and acquire oil and gas reserves. We expect the trend of increasing costs to drill for, develop and acquire oil and gas reserves to continue as a result of the increased demand for oil and gas properties, equipment and services caused by high commodity prices, relative to historical averages.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $3,627,000 and $6,999,000, respectively, during the quarter and six months ended June 30, 2006 as compared to $4,723,000 and $5,685,000 during the 2005 periods. Included in interest expense for the 2005 periods was a charge of $2,439,000 related to previously deferred financing costs, which were written off in connection with the repayment of amounts outstanding under our credit facilities. We capitalized $1,149,000 and $2,247,000 of interest during the three and six month periods of 2006 and $485,000 and $752,000 during the respective 2005 periods. The increase in capitalized interest during the 2006 periods is the result of higher debt levels outstanding throughout 2006, as the $150 million Senior Notes were issued in May 2005.

Income tax expense during the three and six month periods of 2006 totaled $4,842,000 and $10,197,000, as compared to $2,081,000 and $4,335,000 during 2005 periods. The increase is primarily the result of the increased operating profit during the 2006 periods, as compared to 2005. We provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, 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 common stock and debt securities and sales of properties.

Source of Capital: Operations

Net cash flow from operations increased from $37,084,000 in the six month period ended June 30, 2005 to $75,148,000 during the six month 2006 period. The increase in operating cash flow was primarily the result of higher prices and production volumes realized during 2006.

At June 30, 2006, we had a working capital deficit of $17,693,000 versus a deficit of $31,752,000 at December 31, 2005. The improvement in our working capital was primarily due to the decrease in the estimated fair value of our derivative instruments, a result of lower estimated future commodity prices and the expiration of several hedge contracts, offset in part by an increase in our accounts payable to vendors, which is a function of increased operational activity. 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, 2006, we had $34.5 million of borrowings available under our bank credit facility.

Source of Capital: Debt

During the second quarter of 2005, we issued $150 million in principal amount of 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 June 30, 2006, $1.9 million had been accrued in connection with the November 15, 2006 interest payment. At June 30, 2006, 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 with 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. The credit agreement, which was amended in December 2005, provides for a $100 million revolving credit facility that permits us to borrow amounts from time to time 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 upon the valuation as of January 1 and July 1 of each year of our mortgaged oil and gas properties and any other credit factors deemed relevant by the lenders. The borrowing base is currently $67.5 million and the next scheduled borrowing base re-determination will be on October 1, 2006. We or the lenders may request additional borrowing base re-determinations. As of June 30, 2006, we had $33 million of 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. Although we do not anticipate debt covenant violations, our ability to comply with 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 an effective $200 million 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 from time to time or when financing needs arise. The registration statement does not provide assurance that we will or could sell any such securities.

Use of Capital: Exploration and Development

Our exploration and development budget for 2006 will require significant capital. Our 2006 capital budget, which is dependent on commodity prices, drilling success and related completion and facility costs and which excludes acquisitions, is $165 million to $175 million, of which approximately $85 million had been incurred through June 30, 2006.

Based upon our outlook on commodity prices and production, we believe that cash flows from operations and available bank borrowings will be sufficient to fund the remainder of our planned 2006 exploration and development activities. In the future, our 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 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.

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. There can be no assurance that we will be able to sell any of our assets.

As part of our ongoing portfolio diversification efforts, in April 2006 we engaged Randall & Dewey to assist us in the possible sale of certain Gulf of Mexico properties. After evaluating our Gulf of Mexico assets, we decided to explore opportunities to monetize certain properties with the intention of reinvesting the capital into properties with greater long-term potential.

Disclosure Regarding Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are the Company’s estimate of the sufficiency of its existing capital sources, its 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 and divestitures 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 remainder of 2006, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $10 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 six month periods ended June 30, 2006, we received from the counterparties to our derivative instruments $1,520,000 and $1,882,000, 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, 2006, 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:
2006	Swap	5,500 Mmbtu	$	4.33
Third Quarter 2006	Costless Collar	21,000 Mmbtu	$	7.81 — 10.74
Fourth Quarter 2006	Costless Collar	14,000 Mmbtu	$	8.14 — 12.42
2007	Costless Collar	10,000 Mmbtu	$	9.00 — 11.00

Crude Oil:
Third Quarter 2006	Costless Collar	700 Bbls	$	53.00 — 61.36
Fourth Quarter 2006	Costless Collar	500 Bbls	$	48.20 — 55.95
January—June 2007	Costless Collar	300 Bbls	$	65.00 — 79.10
July—December 2007	Costless Collar	200 Bbls	$	65.00 — 77.70

In July 2006 we entered into the following additional gas hedging contract accounted for as a cash flow hedge:


	Instrument
Production Period	Type	Daily Volumes	Average Price
September—December 2006	Costless Collar	7,500 Mmbtu	$8.00 — $10.55

Debt outstanding under our bank credit facility is subject to a floating interest rate and represents only 18% of our total debt as of June 30, 2006. As a result, the potential effect of rising interest rates during the remainder of 2006 on borrowings outstanding at June 30, 2006 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

Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.

We maintain several types of insurance to cover our operations, including maritime employer’s liability and comprehensive general liability. Amounts over base coverages are provided by primary and excess umbrella liability policies with maximum limits of $50 million. We also maintain operator’s extra expense coverage, which covers the control of drilled or producing wells as well as redrilling expenses and pollution coverage for wells out of control.

There have been substantial insurance claims made by the oil and gas industry as a result of hurricane damages incurred during 2005 in the Gulf Coast Basin. In addition, we understand that insurance carriers are modifying or otherwise restricting insurance coverage or ceasing to provide certain types of insurance coverage relative to the Gulf Coast Basin. As a result, our insurance costs in 2006 have increased significantly and our insurance coverage is more limited than in prior years. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

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 Main Pass 74 and Ship Shoal 72 fields, which are located offshore Louisiana, represented approximately 34% of our production during the first six months of 2006. 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 is expected to be 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, which represented approximately 11% of our 2004 production, 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, 2006, the aggregate amount of our outstanding indebtedness was $181.4 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.

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 June 30, 2006, we had $33 million outstanding under our bank credit facility and our borrowing base was $67.5 million. To the extent we add new indebtedness to our current indebtedness levels, the risks described above could substantially increase.

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 16, 2006, the annual meeting of stockholders of the Company was held. The holders of 23,664,696 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 directors of the Company 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		42,251,936		408,874
William W. Rucks, IV		41,480,861		1,179,949
Michael O. Aldridge		42,164,445		496,365
E. Wayne Nordberg		41,204,329		1,456,481
Michael L. Finch		41,484,787		1,176,023
W. J. Gordon, III		41,468,345		1,192,465
Charles F. Mitchell, II, M.D.		41,438,972		1,221,838

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

The stockholders voted to adopt the amended and restated 1998 Incentive Plan as follows:

Number of

Votes

Broker

For

Against

Abstaining

Non-Votes

23,390,689

4,146,588

247,996

14,875,537

The stockholders ratified the appointment of Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 as follows:


Number of	Number of		Number of
Votes	Votes		Votes
For	Against		Abstaining
42,316,375		279,434		65,000

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

Exhibit 10.1, PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective March 16, 2006 (the “Incentive Plan”) (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2006).

Exhibit 10.2, Form of Incentive Stock Option Agreement for executive officers (including Charles T. Goodson, Arthur M. Mixon, III, Michael O. Aldridge, Daniel G. Fournerat and Stephen H. Green) under the Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2006).

Exhibit 10.3, Form of Restricted Stock Agreement for executive officers (including Charles T. Goodson, Arthur M. Mixon, III, Michael O. Aldridge, Daniel G. Fournerat and Stephen H. Green) under the Incentive Plan (incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2006).

Exhibit 10.4, Form of Amendment to Termination Agreement entered into between the Company and each of its executive officers (including Charles T. Goodson, Arthur M. Mixon, III, Michael O. Aldridge, Daniel G. Fournerat and Stephen H. Green) effective as of May 16, 2006 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed with the SEC on May 19, 2006).

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.

SIGNATURE

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


	PETROQUEST ENERGY, INC.
Date: August 3, 2006	/s/ Michael O. Aldridge
		Michael O. Aldridge
		Executive Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial and Accounting Officer)

EXHIBIT INDEX

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.