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, 2005


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 o

Indicate by check mark whether the registrant is an accelerated filer (as defined by Rule 12b-2 of the Exchange Act).

Yes þ No o

As of July 29, 2005, there were 47,137,088 shares of the registrant’s common stock, par value $.001 per share, outstanding.

Part I


		Item 1. Financial Statements

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets
(Amounts in Thousands)


	June 30,			December 31,
	2005			2004
	(unaudited)			(Note 1)

ASSETS
Current assets:
Cash and cash equivalents	$	78,604		$	1,529
Oil and gas revenue receivable		11,278			9,392
Joint interest billing receivable		5,307			3,655
Other current assets		1,924			1,017

Total current assets		97,113			15,593


Oil and gas properties:
Oil and gas properties, full cost method		440,375			363,756
Unevaluated oil and gas properties		22,650			16,380
Accumulated depreciation, depletion and amortization		(188,047	)		(168,453	)

Oil and gas properties, net		274,978			211,683


Other assets, net of accumulated depreciation and amortization of $9,756 and $5,967, respectively		9,975			4,341


Total assets	$	382,066		$	231,617


LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities:
Accounts payable to vendors	$	20,458		$	24,176
Advances from co-owners		14,120			2,265
Hedging liability		11,824			4,536
Other accrued liabilities		14,425			9,045

Total current liabilities		60,827			40,022

Bank debt		—			38,500
10 3/8% Senior Notes		148,249			—
Asset retirement obligation		17,874			15,238
Deferred income taxes		18,095			14,606
Other accrued liabilities		4,634			1,974

Commitments and contingencies		—			—

Stockholders’ equity:
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 47,137 and 44,685 shares, respectively		47			45
Paid-in capital		117,015			112,387
Accumulated other comprehensive loss		(5,803	)		(4,231	)
Retained earnings		21,128			13,076

Total stockholders’ equity		132,387			121,277

Total liabilities and stockholders’ equity	$	382,066		$	231,617

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,
	2005		2004			2005		2004
Revenues:
Oil and gas sales	$	29,977	$	21,436		$	51,649	$	39,568
Interest and other income		302		61			373		131

		30,279		21,497			52,022		39,699

Expenses:
Lease operating expenses		4,965		2,784			8,847		5,506
Production taxes		762		420			1,136		864
Depreciation, depletion and amortization		11,859		9,132			20,054		17,073
General and administrative		1,819		1,833			3,508		3,127
Accretion of asset retirement obligation		205		170			405		401
Interest expense		4,723		665			5,685		1,346
Derivative benefit		—		(9	)		—		—

		24,333		14,995			39,635		28,317

Income from operations		5,946		6,502			12,387		11,382
Income tax expense		2,081		2,265			4,335		3,973

Net income	$	3,865	$	4,237		$	8,052	$	7,409


Earnings per common share:
Basic	$	0.08	$	0.10		$	0.17	$	0.17

Diluted	$	0.08	$	0.09		$	0.17	$	0.16


Weighted average number of common shares:
Basic		46,969		44,588			46,158		44,573

Diluted		48,205		46,104			47,840		45,912

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows
(unaudited)
(Amounts in Thousands)


	Six Months Ended
	June 30,
	2005			2004
Cash flows from operating activities:
Net income	$	8,052		$	7,409
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		4,335			3,973
Depreciation, depletion and amortization		20,054			17,073
Accretion of asset retirement obligation		405			401
Amortization of debt issuance costs		841			820
Compensation expense		213			272
Write-off of debt issuance costs		2,439			—
Amortization of bond discount		20			—
Derivative mark to market		—			(115	)
Changes in working capital accounts:
Accounts receivable		(1,886	)		(3,294	)
Joint interest billing receivable		(1,652	)		(611	)
Other assets		(5,056	)		(143	)
Accounts payable and accrued liabilities		(6,430	)		(3,309	)
Advances from co-owners		11,855			1,306

Net cash provided by operating activities		33,190			23,782


Cash flows from investing activities:
Investment in oil and gas properties		(65,167	)		(24,151	)

Net cash used in investing activities		(65,167	)		(24,151	)


Cash flows from investing activities:
Proceeds from exercise of options		546			64
Proceeds from issuance of 10 3/8% senior notes		148,229			—
Proceeds from bank borrowings		34,500			11,000
Repayment of bank borrowings		(73,000	)		(10,000	)
Deferred financing costs		(5,274	)		(245	)
Issuance of common stock, net of expenses		4,051			—

Net cash provided by financing activities		109,052			819

Net increase in cash and cash equivalents		77,075			450
Cash and cash equivalents, beginning of period		1,529			779

Cash and cash equivalents, end of period	$	78,604		$	1,229


Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	1,561		$	817

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, 2005 and 2004, respectively, have been prepared by the Company and were not audited by its independent registered public accounting firm. 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, 2005 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, 2004 has been derived from the audited financial statements at that date. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles have been condensed or omitted. These consolidated financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2004.

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), Pittrans, Inc. (an Oklahoma corporation) and TDC Energy LLC (a single member Louisiana limited liability company).

Note 2 Earnings Per Share

Basic earnings per common share are 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 June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Basic shares outstanding		46,969		44,588		46,158		44,573
Effect of stock options		1,236		681		1,278		519
Effect of warrants		—		835		404		820

Diluted shares outstanding		48,205		46,104		47,840		45,912

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 were between $6.64 and $7.65, and expire in 2011-2015.

Options to purchase 607,834 shares of common stock were outstanding during both the three- and six-month periods ended June 30, 2004, 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 were between $3.75 and $7.65, and expire in 2010-2013.

Note 3 Long-Term Debt

On May 11, 2005, the Company issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, the Company issued an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 at 99% of their face value. Collectively, these issuances of 10 3/8% notes are referred to as “the Notes”. The Notes are guaranteed by all of the significant subsidiaries of PetroQuest

Energy, Inc. 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 for the three- and six-month periods ended June 30, 2005.

After payment of expenses and the initial purchasers’ discounts, we received $144.4 million in net proceeds from the issuance of the Notes. Net proceeds were used to repay all outstanding borrowings under our credit facilities, to fund acquisitions of assets in Oklahoma (see Note 8) and to provide capital for future acquisitions and general corporate purposes. The Notes are redeemable at our option beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, 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, 2005, $2.1 million had been accrued in connection with the November 15, 2005 interest payment.

The Company entered into a bank credit facility on May 14, 2003. Pursuant to the credit facility agreement, PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the “Borrower”) have a $75 million revolving credit facility which permits the Borrower to borrow amounts from time to time based on the available borrowing base as determined in the bank credit facility. The bank credit facility is secured by a mortgage on substantially all of the Borrower’s oil and gas properties, a pledge of the membership interest of the Borrower and PetroQuest’s corporate guarantee of the indebtedness of the Borrower. The borrowing base under the bank credit facility is based upon the valuation as of April 1 and October 1 of each year of the Borrower’s mortgaged properties, projected oil and gas prices, and any other factors deemed relevant by the lenders. The Company or the lenders may also request additional borrowing base redeterminations.

During the second quarter of 2005, we repaid all outstanding borrowings under the credit facility with a portion of the net proceeds received from the issuance of the Notes. In connection with the issuance of the Notes, the credit facility was amended and as of June 30, 2005, the borrowing base under the bank credit facility was $25 million.

Outstanding balances on the revolving credit facility bear interest at either the bank’s prime rate plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows the Company to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances. The bank credit facility matures on May 14, 2006.

The Company is subject to certain restrictive financial and non-financial covenants under the bank credit facility, as amended, including a minimum current ratio of 1.0 to 1.0, all as defined in the credit facility agreement. The bank credit facility also requires the Borrower to establish and maintain commodity hedges covering at least 50% of its proved developed producing reserves on a rolling twelve-month basis. As of June 30, 2005, the Company was in compliance with all of the covenants in the bank credit facility.

On November 6, 2003, we obtained a $20 million second lien term credit facility from Macquarie Americas Corp., which was subsequently assigned to Macquarie Bank Limited (“MBL”). On May 11, 2005, we repaid the $12 million of total borrowings outstanding with proceeds from the Notes and terminated this facility. After termination of this facility, however, certain oil and gas hedging contracts with MBL as the counterparty remained in place and are secured by a second mortgage on substantially all of the oil and gas properties of PetroQuest Energy, L.L.C. until the hedges expire or are terminated. During the second quarter of 2005, we recognized a charge of $2.3 million related to previously deferred financing costs associated with this facility.

Note 4 Asset Retirement Obligation

The Company accounts for asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143 (SFAS 143), “Accounting for Asset Retirement Obligations”. 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 changes to the Company’s asset retirement obligation liability (in thousands):


	Six Months Ended
	June 30, 2005
Asset retirement obligation at beginning of period	$	16,393
Liabilities incurred during 2005		6,748
Liabilities settled during 2005		—
Accretion expense		405
Revisions in estimated cash flows		(1,916	)

Asset retirement obligation at end of period		21,630
Less: current portion of asset retirement obligation		(3,756	)

Long-term asset retirement obligation	$	17,874

Note 5 New Accounting Standards

On December 16, 2004, the Financial Accounting Standards Board ssued 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. On April 21, 2005, the SEC issued an amendment to rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R). This amendment changed the effective date to the first fiscal year beginning on or after June 15, 2005. Accordingly, we expect to adopt the standard January 1, 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 restate 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.

The Company currently accounts for its stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, 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. Accordingly, the adoption of SFAS 123(R) will have a significant impact on our results of operations, but will have no impact on our overall financial position.

The specific impact of the adoption cannot be predicted at this time because it will depend on the level of share-based payments granted in the future. However, had we adopted SFAS 123(R) in prior periods, the impact would approximate the impact of SFAS 123 as described in Note 7. 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 currently required. We did not recognize any excess tax deductions during the first six months of 2005 or 2004 in connection with the exercise of stock options.

In September 2004, the Securities and Exchange Commission adopted Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of SFAS No. 143 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the

present value of estimated future net revenues used in applying the ceiling test. We began applying SAB No. 106 in the first quarter of 2005.

Note 6 Equity

Other Comprehensive Income and Derivative Instruments

The following table presents a recap of the Company’s comprehensive income for the three- and six-month periods ended June 30, 2005 and 2004 (in thousands):


	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2005		2004			2005			2004
Net income	$	3,865	$	4,237		$	8,052		$	7,409
Change in fair value of derivative instruments, accounted for as hedges, net of taxes		1,518		(1,123	)		(1,572	)		(3,117	)

Comprehensive income	$	5,383	$	3,114		$	6,480		$	4,292

For the three months ended June 30, 2005 and 2004, the effect of derivative financial instruments is net of deferred income tax (expense) benefit of ($817,000) and $605,000, respectively. For the six months ended June 30, 2005 and 2004, the effect of derivative financial instruments is net of deferred income tax benefit of $846,000 and $1,678,000, 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 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.

Oil and gas sales include reductions related to gas hedges of $813,000 and $356,000 and oil hedges of $1,262,000 and $738,000 for the three months ended June 30, 2005 and 2004, respectively. Oil and gas sales include reductions related to gas hedges of $1,078,000 and $366,000 and oil hedges of $2,341,000 and $1,174,000 for the six months ended June 30, 2005 and 2004, respectively. In addition, during the second quarter of 2004, we recognized ($9,000) in derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

As of June 30, 2005, 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:
2005	Swap	10,750 Mmbtu	$	6.04
Third Quarter 2005	Costless Collar	12,500 Mmbtu	$	5.34-8.27
Fourth Quarter 2005	Costless Collar	10,500 Mmbtu	$	5.36-10.66
2006	Swap	5,500 Mmbtu	$	4.33
January — June 2006	Costless Collar	6,500 Mmbtu	$	5.42-10.46
July — December 2006	Costless Collar	4,000 Mmbtu	$	6.00-11.21

Crude Oil:
Third Quarter 2005	Costless Collar	1,300 Bbls	$	33.46-56.38
Fourth Quarter 2005	Costless Collar	900 Bbls	$	32.78-48.04
First Quarter 2006	Costless Collar	600 Bbls	$	37.67-57.37
April — December 2006	Costless Collar	200 Bbls	$	23.00-26.40

At June 30, 2005, the Company recognized a liability of $16.3 million related to the estimated fair value of these derivative instruments. We expect to reclassify approximately $7.7 million of deferred losses, net of taxes, on derivatives from accumulated comprehensive loss to oil and gas sales during the next 12 months. These losses are expected to be reclassified as the oil and gas volumes underlying the derivative contracts are produced and sold. At June 30, 2005, our derivative instruments were considered effective cash flow hedges.

Note 7 Stock Based Compensation

The Company accounts for its stock-based compensation plans under the principles prescribed by the Accounting Principles Board’s Opinion No. 25, “Accounting for Stock Issued to Employees.”

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


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2005			2004			2005			2004
Net income	$	3,865		$	4,237		$	8,052		$	7,409
Stock-based compensation:
Add expense included in reported results, net of tax		—			140			22			177
Deduct fair value based method, net of tax		(155	)		(380	)		(331	)		(658	)

Pro forma net income	$	3,710		$	3,997		$	7,743		$	6,928


Earnings per common share:
Basic — as reported	$	0.08		$	0.10		$	0.17		$	0.17
Basic — pro forma	$	0.08		$	0.09		$	0.17		$	0.16
Diluted — as reported	$	0.08		$	0.09		$	0.17		$	0.16
Diluted — pro forma	$	0.08		$	0.09		$	0.16		$	0.15

Note 8 Acquisitions

On April 12, 2005, we acquired all of the outstanding membership interests of TDC Energy Inc. (“TDC”) an oil and gas exploration company with 12 producing fields and 19 wells in the Gulf of Mexico shelf. TDC’s oil and gas properties had an estimated 10.5 Bcfe of proved reserves (80% natural gas) as of December 31, 2004. Consideration for the acquisition included cash, our common stock and the repayment of approximately $11.5 million in net debt associated with TDC’s operations.

On May 11, 2005, we closed two of four purchase and sale agreements relating to gas properties and gas gathering systems located in Oklahoma for an aggregate purchase price of $5.9 million. On July 1, 2005, we closed the remaining two purchase and sale agreements for an adjusted purchase price of $23.2 million. On July 13, 2005, we acquired additional working interests in producing properties located in Oklahoma. This acquisition increased interests that were previously acquired by a proportionate 20% for an adjusted purchase price of approximately $3.6 million.

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 with operations in the Gulf Coast Basin, Texas and Oklahoma. We seek to increase our proved reserves, production, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. We were successful in 2004 in improving our operating and financial results compared to the prior year. From 2003 to 2004, we increased proved reserves by 22%, production by 47%, cash flow from operating activities by 106% and net income by 349%.

From the commencement of our operations in 1985 through 2002, we 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. To complement these transactions, we added personnel with expertise and knowledge specific to these regions dedicated to evaluating and exploiting these properties. At June 30, 2005, approximately 45% of our estimated proved reserves were located outside of the Gulf Coast Basin.

Recent Events

On May 11, 2005, we issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, we issued an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 at 99% of their face value. Collectively, the issuances of 10 3/8% notes are referred to as “the Notes”. Net proceeds from the issuance of the Notes totaled $144.4 million and were used to repay all of our debt outstanding under the credit facilities, to fund acquisitions of assets in Oklahoma as described above and to provide capital for future acquisitions and general corporate purposes.

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 relate to 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 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 the 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 and the political and regulatory environment. The accounting for future abandonment costs changed on January 1, 2003, with the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” See Note 4 in the Notes to Consolidated Financial Statements for a further discussion of this accounting standard.

Reserve Estimates

Our estimates of proved oil and gas reserves constitute quantities that we are reasonably certain of recovering in future years. 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 Gulf Coast Basin 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 our Gulf Coast Basin production. Through this analysis, we are able to determine if a high correlation exists between the prices received for our Gulf Coast Basin production and the indexed prices at which the hedges will be settled. At June 30, 2005, our derivative instruments were considered effective cash flow hedges.

Estimating the fair values of hedging derivatives requires complex calculations incorporating estimates of future prices, discount rates and price movements. As a result, we choose to obtain the fair value of our commodity derivatives from the counter parties to those contracts. Since the counter parties are market makers, they are able to provide us with a literal market value, or what they would be willing to settle such contracts for as of the given date.

Results of Operations

The following table (unaudited) sets forth certain operating information with respect to our oil and gas operations for the periods noted:


	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2005		2004		2005		2004
Production:
Oil (Bbls)		217,156		246,052		398,555		424,531
Gas (Mcf)		3,252,510		2,160,311		5,501,623		4,322,051
Total Production (Mcfe)		4,555,446		3,636,623		7,892,953		6,869,237

Sales:
Total oil sales	$	9,747,130	$	8,507,123	$	17,619,699	$	14,310,726
Total gas sales		20,229,581		12,928,781		34,028,518		25,257,755

Average sales prices:
Oil (per Bbl)	$	44.89	$	34.57	$	44.21	$	33.71
Gas (per Mcf)		6.22		5.98		6.19		5.84
Per Mcfe		6.58		5.89		6.54		5.76

The above sales and average sales prices include reductions related to gas hedges of $813,000 and $356,000 and oil hedges of $1,262,000 and $738,000 for the three months ended June 30, 2005 and 2004, respectively. The above

sales and average sales prices include reductions related to gas hedges of $1,078,000 and $366,000 and oil hedges of $2,341,000 and $1,174,000 for the six months ended June 30, 2005 and 2004, respectively.

Net income totaled $3,865,000 and $4,237,000 for the quarters ended June 30, 2005 and 2004, respectively. Net income totaled $8,052,000 and $7,409,000 for the six months ended June 30, 2005 and 2004, respectively. The results are attributable to the following components:

Production. Oil production in 2005 declined 12% and 6% from the quarter and six months ended June 30, 2004, respectively. Natural gas production in 2005 increased 51% and 27% over the quarter and six months ended June 30, 2004, respectively. On an Mcfe basis, production for the quarter and six months ended June 30, 2005 increased 25% and 15% over the respective 2004 periods. During the first six months of 2005, 70% of our total production was natural gas as compared to 63% during the 2004 period. This shift towards natural gas is the result of our expanded operations in Texas and Oklahoma where the production is primarily natural gas.

The increase in current year production as compared to 2004 was due to our recent acquisitions and the success of our increased drilling program, offset in part by the shut-in of our Main Pass 74 field since the third quarter of 2004 due to third-party pipeline damage from Hurricane Ivan. We estimate that production from Main Pass 74 could be restored during the third quarter of 2005. During the first six months of 2005 we drilled 33 gross wells, equaling the number of wells we drilled during the entire year of 2004, and realized a 94% success rate.

Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and six months ended June 30, 2005 were $44.89 and $44.21, as compared to $34.57 and $33.71, respectively, for the same periods in 2004. Average gas prices per Mcf were $6.22 and $6.19 for the quarter and six months ended June 30, 2005, respectively, as compared to $5.98 and $5.84 for the respective periods in 2004. Stated on an Mcfe basis, unit prices received during the quarter and six months ended June 30, 2005 were 12% and 14% higher, respectively, than the prices received during the comparable 2004 periods.

During the second quarter of 2005, our hedges reduced the average prices we received for gas by $0.25 per Mcfe and for oil by $5.81 per barrel. For the first six months of 2005, our hedges reduced our average realized prices by $0.20 per Mcfe and $5.87 per barrel. Hedges reduced our average realized prices by $0.16 per Mcfe and $3.00 per barrel during the second quarter of 2004 and by $0.08 per Mcfe and $2.77 per barrel for the six month period of 2004.

Revenue. Oil and gas sales during the quarter and six months ended June 30, 2005 increased to $29,977,000 and $51,649,000 as compared to sales of $21,436,000 and $39,568,000, respectively, for the same periods in 2004. The increase in revenue was the result of higher production volumes and average realized commodity prices during the 2005 periods.

Expenses. Lease operating expenses for the quarter and six months ended June 30, 2005 increased to $4,965,000 and $8,847,000 as compared to $2,784,000 and $5,506,000, respectively, for the same periods in 2004. On an Mcfe basis, lease operating expenses for the quarter and six months ended June 30, 2005 totaled $1.09 and $1.12 as compared to $0.77 and $0.80, respectively, for the same periods during 2004. The increase in operating costs was the result of the increase in the number of producing wells we participate in and higher oil field service costs, such as labor, transportation and materials. We expect this trend in higher operating costs to continue during 2005.

General and administrative expenses during the quarter and six months ended June 30, 2005 totaled $1,819,000 and $3,508,000 as compared to expenses of $1,833,000 and $3,127,000, respectively, during the 2004 periods. The 12% increase in expenses during the first half of 2005 as compared to the 2004 period was primarily due to the 13% increase in our staffing over that period necessary to support our increased operational activity. The Company capitalized $1,051,000 and $2,303,000 of general and administrative costs during the quarter and six months ended June 30, 2005 as compared to $1,247,000 and $2,239,000, respectively, in the comparable 2004 periods.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter and six months ended June 30, 2005 totaled $11,693,000, or $2.57 per Mcfe, and $19,786,000, or $2.51 per Mcfe. DD&A expense on oil and gas properties for the respective 2004 periods totaled $9,024,000, or $2.48 per Mcfe, and $16,867,000, or $2.46 per Mcfe. The increase in our DD&A expense per Mcfe is primarily due to increased costs to drill for, develop and acquire oil and gas reserves.

Interest expense, net of amounts capitalized on unevaluated prospects, increased to $4,723,000 and $5,685,000, respectively, during the quarter and six months ended June 30, 2005 as compared to $665,000 and $1,346,000 during the same periods in 2004. Included in second quarter 2005 interest expense 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 $485,000 and $205,000 of interest during the quarters ended June 30, 2005 and 2004, respectively. We capitalized $752,000 and $384,000 of interest during the six months ended June 30, 2005 and 2004, respectively. As a result of higher debt levels associated with the Notes, we expect interest expense for the remainder of 2005 to exceed amounts recognized during 2004.

Income tax expense of $2,081,000 and $4,335,000 was recognized during the quarter and six months ended June 30, 2005, respectively, as compared to $2,265,000 and $3,973,000 during the same periods of 2004. The change is a result of fluctuations in the operating profit during the current year. We provide for income taxes at a statutory rate of 35%.

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 $23,782,000 during the six months ended June 30, 2004 to $33,190,000 for the same period in 2005. This increase resulted primarily from the increased production and realized commodity prices during the current year. Our working capital at June 30, 2005 totaled $36,286,000 versus a deficit of $24,429,000 at December 31, 2004. The improvement in our working capital balance was due to remaining proceeds received from the issuance of the Notes. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facilities when measuring liquidity.

Source of Capital: Debt

After payment of expenses and the initial purchasers’ discounts, we received $144.4 million in net proceeds from the issuance of the Notes. Net proceeds were used to repay all outstanding borrowings under our credit facilities, to fund acquisitions and to provide capital for future acquisitions and general corporate purposes. The Notes are redeemable at our option beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, 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, 2005, $2.1 million had been accrued in connection with the November 15, 2005 interest payment. As of June 30, 2005, we were in compliance with all of the covenants under the Notes.

We entered into a bank credit facility on May 14, 2003. Pursuant to the credit facility agreement, PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the “Borrower”) have a $75 million revolving credit facility that permits us to borrow amounts from time to time based on the available borrowing base as determined in the bank credit facility. The bank credit facility is secured by a mortgage on substantially all of the Borrower’s oil and gas properties, a pledge of the membership interest of the Borrower and PetroQuest’s corporate guarantee of the indebtedness of the Borrower. The borrowing base under the bank credit facility is based upon the valuation as of April 1 and October 1 of each year of the Borrower’s mortgaged properties, projected oil and gas prices, and any other factors deemed relevant by the lenders. We, or the lenders, may request additional borrowing base re-determinations.

During the second quarter of 2005, we repaid all outstanding borrowings under the credit facility with proceeds received from the issuance of the Notes. In connection with the issuance of the Notes, the credit facility was amended and as of June 30, 2005, the borrowing base under the bank credit facility was $25 million.

Outstanding balances on the revolving credit facility bear interest at either the prime rate of the bank serving as legal agent under the facility plus a margin (based on a sliding scale of 0.75% to 1.25% based on borrowing base usage but never less than the Federal Funds Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank credit facility also allows us to use up to $5 million of the borrowing base for letters of credit for fees equal to the applicable margin rate for Eurodollar advances. The bank credit facility matures on May 14, 2006.

We are subject to certain restrictive financial and non-financial covenants under the bank credit facility including a minimum current ratio of 1.0 to 1.0, all as defined in the credit facility agreement. The bank credit facility also requires the Borrower to establish and maintain commodity hedges covering at least 50% of its proved developed producing reserves on a rolling twelve-month basis. As of June 30, 2005, we were in compliance with all of the covenants in the bank 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 for 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 Equity Securities

During April 2005, we issued 646,226 shares of our common stock in connection with our acquisition of TDC Energy, Inc.

We have an effective universal shelf registration statement relating to the potential public offer and sale by PetroQuest 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 the remainder of 2005 will require significant capital. Our 2005 capital budget, excluding acquisitions, capitalized interest and general and administrative costs, is $90 to $100 million, of which approximately $47 million was incurred during the first half of 2005.

Based upon our outlook on commodity prices and production, we believe that cash flow from operations and borrowings available under our credit facility will be sufficient to fund the remainder of our planned 2005 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 working capital, cash flow from operations and borrowings under our credit facility, but we 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.

Contractual Obligations

The following table summarizes our contractual obligations as of June 30, 2005 (in thousands):


													After
	Total		2005		2006		2007		2008		2009		2009
Bank debt	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Senior notes		259,157		9,943		15,563		15,563		15,563		15,563		186,962
Operating leases (1)		4,073		416		772		742		741		755		647
Capital projects (2)		21,630		127		3,629		3,272		1,142		1,979		11,481


(1)		Consists primarily of leases for office space and leases for equipment rentals.

(2)		Consists of estimated future obligations to abandon our leased properties.

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 in projecting future rates of production, the timing of development expenditures and drilling of wells, 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 the 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 Discussions 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

Historically, we have experienced market risks primarily in two areas: commodity prices and interest rates. We believe that our business operations are not exposed to significant market risks relating to foreign currency exchange risk because all of our operations are conducted within the United States.

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected annual sales volumes for the remaining six months of 2005, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $7 million impact on our revenues, inclusive of hedging.

In 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. 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, 2005, 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:
2005	Swap	10,750 Mmbtu	$	6.04
Third Quarter 2005	Costless Collar	12,500 Mmbtu	$	5.34-8.27
Fourth Quarter 2005	Costless Collar	10,500 Mmbtu	$	5.36-10.66
2006	Swap	5,500 Mmbtu	$	4.33
January — June 2006	Costless Collar	6,500 Mmbtu	$	5.42-10.46
July — December 2006	Costless Collar	4,000 Mmbtu	$	6.00-11.21

Crude Oil:
Third Quarter 2005	Costless Collar	1,300 Bbls	$	33.46-56.38
Fourth Quarter 2005	Costless Collar	900 Bbls	$	32.78-48.04
First Quarter 2006	Costless Collar	600 Bbls	$	37.67-57.37
April — December 2006	Costless Collar	200 Bbls	$	23.00-26.40

At June 30, 2005, the Company recognized a liability of $16.3 million related to the estimated fair value of these derivative instruments. In addition, during the second quarter of 2004, we recognized ($9,000) of derivative expense related to an interest rate swap that did not qualify for hedge accounting treatment. This contract expired in November 2004.

During the second quarter of 2005, we repaid all of our variable rate bank debt using proceeds from the issuance of fixed rate senior notes. Because 100% of our debt outstanding at June 30, 2005 was subject to a fixed rate, we did not have any exposure to rising interest rates at June 30, 2005.

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, carried out 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 the following:

	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 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 12, 2005, the annual meeting of stockholders of the Company was held. The holders of 41,327,993 shares of common stock were present in person or represented by proxy at the meeting. At the meeting, 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		41,218,392		109,601
William W. Rucks, IV		41,040,117		287,876
Michael O. Aldridge		41,055,792		272,201
E. Wayne Nordberg		41,195,051		132,942
Michael L. Finch		41,040,870		287,123
W. J. Gordon, III		41,199,606		128,387
Charles F. Mitchell, II, M.D.		41,165,909		162,084

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS

(a) Exhibits:

2.1		Agreement and Plan of Merger dated April 12, 2005, among PetroQuest Energy, Inc., TDC Acquisition Sub LLC and TDC Energy LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on April 13, 2005).

2.2		Purchase and Sale Agreement, dated as of April 13, 2005, between Staab Holdings, L.L.C. and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on April 22, 2005).

2.3		Purchase and Sale Agreement, dated as of April 7, 2005, among MAKO Resources, LLC, Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.2 to the Company’s Form 8-K filed on April 22, 2005).

2.4		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.3 to the Company’s Form 8-K filed on April 22, 2005).

2.5		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.4 to the Company’s Form 8-K filed on April 22, 2005).

10.1		Sixth Amendment to Amended and Restated Credit Agreement dated April 12, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Acquisition Sub LLC, and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 13, 2005).

10.2		Fifth Amendment to Second Lien Secured Credit Agreement dated April 12, 2005, among PetroQuest Energy, L.L.C., TDC Energy LLC f/k/a TDC Acquisition Sub LLC, PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on April 13, 2005).

10.3		Severance Agreement and Release, effective April 8, between Ralph J. Daigle and PetroQuest Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005).

10.4		Seventh Amendment to Amended and Restated Credit Agreement dated May 9, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 11, 2005).

10.5		Eighth Amendment to Amended and Restated Credit Agreement dated June 17, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, JPMorgan Chase Bank, N.A., Guaranty Bank, FSB and Calyon New York Branch (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 17, 2005).

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

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

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith

EXHIBIT INDEX

2.1		Agreement and Plan of Merger dated April 12, 2005, among PetroQuest Energy, Inc., TDC Acquisition Sub LLC and TDC Energy LLC (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on April 13, 2005).

2.2		Purchase and Sale Agreement, dated as of April 13, 2005, between Staab Holdings, L.L.C. and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on April 22, 2005).

2.3		Purchase and Sale Agreement, dated as of April 7, 2005, among MAKO Resources, LLC, Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.2 to the Company’s Form 8-K filed on April 22, 2005).

2.4		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.3 to the Company’s Form 8-K filed on April 22, 2005).

2.5		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, L.L.C. (incorporated by reference to Exhibit 2.4 to the Company’s Form 8-K filed on April 22, 2005).

10.1		Sixth Amendment to Amended and Restated Credit Agreement dated April 12, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Acquisition Sub LLC, and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 13, 2005).

10.2		Fifth Amendment to Second Lien Secured Credit Agreement dated April 12, 2005, among PetroQuest Energy, L.L.C., TDC Energy LLC f/k/a TDC Acquisition Sub LLC, PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed on April 13, 2005).

10.3		Severance Agreement and Release, effective April 8, between Ralph J. Daigle and PetroQuest Energy, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on April 22, 2005).

10.4		Seventh Amendment to Amended and Restated Credit Agreement dated May 9, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JPMorgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on May 11, 2005).

10.5		Eighth Amendment to Amended and Restated Credit Agreement dated June 17, 2005, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, JPMorgan Chase Bank, N.A., Guaranty Bank, FSB and Calyon New York Branch (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed on June 17, 2005).

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

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

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*32.2		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


*		Filed herewith


	PETROQUEST ENERGY, INC.
Date: August 2, 2005	By:	/s/ Michael O. Aldridge
		Michael O. Aldridge
		Senior Vice President, Chief Financial Officer and Treasurer (Authorized Officer and Principal Financial and Accounting Officer)

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		Page No.
Part I.	Financial Information
Item 1.	Financial Statements
	Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004		1
	Consolidated Statements of Income for the Three and Six Months Ended June 30, 2005 and 2004		2
	Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2005 and 2004		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		16
Item 4.	Controls and Procedures		17
Part II.	Other Information
Item 1.	Legal Proceedings		18
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		18
Item 3.	Defaults upon Senior Securities		18
Item 4.	Submission of Matters to a Vote of Security Holders		18
Item 5.	Other Information		18
Item 6.	Exhibits		18
Certification of CEO pursuant to Rule 13a-14(a)
Certification of CFO pursuant to Rule 13a-14(a)
Certification pursuant to 18 U.S.C. Section 1350
Certification pursuant to 18 U.S.C. Section 1350