UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended:  March 31, 2007

OR

£  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	72-1440714
(State of Incorporation)	(I.R.S. Employer Identification No.)
400 E. Kaliste Saloom Rd., Suite 6000
Lafayette, Louisiana	70508
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code:  (337) 232-7028

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes S    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 S 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 S

As of  May 1, 2007 there were 47,787,725 shares of the registrant’s common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

Part I.	Financial Information		Page No.
	Item 1.	Financial Statements
		Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006	1
		Consolidated Statements of Income for the Three Months Ended March 31, 2007 and 2006	2
		Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006	3
		Notes to Consolidated Financial Statements	4
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
	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	21
	Item 6.	Exhibits	22

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

	March 31, 2007			December 31, 2006
	(unaudited)			(Note 1)
ASSETS
Current assets:
Cash and cash equivalents	$	7,179		$	4,795
Revenue receivable		20,795			21,767
Joint interest billing receivable		16,721			20,072
Hedging asset		1,203			10,527
Prepaid drilling costs		1,642			4,886
Other current assets		6,826			2,143
Total current assets		54,366			64,190
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		744,942			695,116
Unevaluated oil and gas properties		55,320			51,567
Accumulated depreciation, depletion and amortization		(341,296	)		(314,869	)
Oil and gas properties, net		458,966			431,814
Gas gathering assets		19,571			19,072
Accumulated depreciation and amortization of gas gathering assets		(4,312	)		(3,562	)
Total property and equipment		474,225			447,324
Other assets, net of accumulated depreciation and amortization of $12,057 and $11,719, respectively		6,825			6,776
Total assets	$	535,416		$	518,290
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable to vendors	$	41,445		$	32,049
Advances from co-owners		12,966			13,391
Oil and gas revenue payable		7,919			6,935
Accrued interest		6,227			2,453
Asset retirement obligation		8,968			9,028
Other accrued liabilities		7,355			8,225
Total current liabilities		84,880			72,081
Bank debt		40,000			47,000
10 3/8% senior notes		148,589			148,537
Asset retirement obligation		11,687			11,211
Deferred income taxes		52,734			49,646
Other liabilities		104			104
Commitments and contingencies
Stockholders' equity:
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 47,788 shares		48			48
Paid-in capital		127,323			124,552
Accumulated other comprehensive income		758			6,632
Retained earnings		69,293			58,479
Total stockholders' equity		197,422			189,711
Total liabilities and stockholders' equity	$	535,416		$	518,290

See accompanying Notes to Consolidated Financial Statements.

1

PETROQUEST ENERGY, INC.

Consolidated Statements of Income

(unaudited)

(Amounts in Thousands, Except Per Share Data)

	Three Months Ended
	March 31,
	2007		2006
Revenues:
Oil and gas sales	$	61,884	$	47,016
Gas gathering revenue and other income		2,124		1,342
		64,008		48,358
Expenses:
Lease operating expenses		6,937		6,951
Production taxes		2,130		1,570
Depreciation, depletion and amortization		27,613		18,719
Gas gathering costs		950		717
General and administrative		5,180		2,155
Accretion of asset retirement obligation		215		370
Interest expense		3,632		3,372
		46,657		33,854
Income from operations		17,351		14,504
Income tax expense		6,537		5,355
Net income	$	10,814	$	9,149
Earnings per common share:
Basic	$	0.23	$	0.19
Diluted	$	0.22	$	0.19
Weighted average number of common shares:
Basic		47,788		47,326
Diluted		49,451		48,718

See accompanying Notes to Consolidated Financial Statements.

2

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

	Three Months Ended
	March 31,
	2007			2006
Cash flows from operating activities:
Net income	$	10,814		$	9,149
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		6,537			5,355
Depreciation, depletion and amortization		27,613			18,719
Accretion of asset retirement obligation		215			370
Amortization of debt issuance costs		239			233
Amortization of bond discount		52			47
Share based compensation expense		2,771			60
Changes in working capital accounts:
Revenue receivable		972			(5,388	)
Joint interest billing receivable		3,351			(1,060	)
Accounts payable and accrued liabilities		18,120			12,824
Advances from co-owners		(425	)		(3,475	)
Other assets and liabilities		(1,812	)		(6,860	)
Net cash provided by operating activities		68,447			29,974
Cash flows from investing activities:
Investment in oil and gas properties		(58,214	)		(46,086	)
Investment in gas gathering assets		(499	)		(3,596	)
Other		(336	)		-
Net cash used in investing activities		(59,049	)		(49,682	)
Cash flows from financing activities:
Proceeds from exercise of options		-			13
Deferred financing costs		(14	)		(15	)
Repayment of bank borrowings		(7,000	)		-
Proceeds from bank borrowings		-			15,000
Net cash provided by (used in) financing activities		(7,014	)		14,998
Net increase (decrease) in cash and cash equivalents		2,384			(4,710	)
Cash and cash equivalents, beginning of period		4,795			6,703
Cash and cash equivalents, end of period	$	7,179		$	1,993
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest	$	918		$	161
Income taxes	$	-		$	-

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 Basis of Presentation

The consolidated financial information for the three month periods ended March 31, 2007 and 2006, respectively, have been prepared by the Company and were not audited by its independent registered public accountants.  In the opinion of management, all normal and recurring adjustments have been made to present fairly the financial position, results of operations, and cash flows of the Company at March 31, 2007 and for all reported periods.  Results of operations for the interim periods presented are not necessarily indicative of the operating results for the full year or any future periods.

The balance sheet at December 31, 2006 has been derived from the audited financial statements at that date.  Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States have been condensed or omitted.  These consolidated financial statements should be read in conjunction with the audited financial statements and related notes thereto included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

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

Note 2 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 restricted stock considered dilutive computed using the treasury stock method. There were no shares of restricted stock outstanding during the quarter ended March 31, 2006.  A reconciliation between basic and diluted shares outstanding (in thousands) is as follows:

	Three Months Ended
	March 31,
	2007		2006
Basic shares outstanding		47,788		47,326
Effect of stock options		1,171		1,392
Effect of restricted stock		492		-
Diluted shares outstanding		49,451		48,718

In addition to the stock options included in the reconciliation above, options to purchase 47,000 and 10,000 shares of common stock were outstanding during the three month periods ended March 31, 2007 and 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 anti-dilutive options’ exercise prices ranged between $12.21 and $13.49 during the first quarter of 2007 and were $9.99 during the first quarter of 2006.  The anti-dilutive first quarter 2007 options expire during 2016 and 2017 and the anti-dilutive first quarter 2006 options expire in 2016.

4

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 months ended March 31, 2007.

The Notes have numerous covenants including restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on May 15 and November 15.  At March 31, 2007, $5.8 million had been accrued in connection with the May 15, 2007 interest payment, and the Company was in compliance with all of the covenants under the Notes.

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

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 primarily based upon the valuation as of January 1 and July 1 of each year of the mortgaged oil and gas properties. Based upon the April 2007 borrowing base re-determination, effective April 13, 2007 the borrowing base was increased from $75 million to $77.5 million.  The next scheduled borrowing base re-determination will be on October 1, 2007.  The Company or the lenders may request additional borrowing base re-determinations.

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

The Company is subject to certain restrictive financial covenants under the credit facility, including a maximum ratio of consolidated indebtedness to annualized consolidated EBITDA, determined on a rolling four quarter basis, of 3.0 to 1 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the credit agreement.  The credit facility also includes customary restrictions with respect to liens, indebtedness, loans and investments, material changes in the Company’s business, asset sales or leases or transfers of assets, restricted payments such as distributions and dividends, mergers or consolidations, transactions with affiliates and rate management transactions.  As of March 31, 2007, there were $40 million of borrowings outstanding under the credit facility and the Company was in compliance with all of the covenants therein.

Note 4 Asset Retirement Obligation

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

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

5

The following table describes all changes to the Company’s asset retirement obligation liability during the quarter ended March 31, 2007 (in thousands):

Asset retirement obligation at January 1, 2007	$	20,239
Liabilities incurred during 2007		11
Liabilities settled during 2007		-
Accretion expense		215
Revisions in estimated cash flows		190
Asset retirement obligation at March 31, 2007		20,655
Less: current portion of asset retirement obligation		(8,968	)
Long-term asset retirement obligation	$	11,687

Note 5 New Accounting Standards

In June 2006, the FASBissued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”).  FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes,” and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes.  FIN 48 is effective for fiscal years beginning after December 15, 2006.  Accordingly, the Company adopted FIN 48 on January 1, 2007.  The adoption of FIN 48 did not have any effect on the Company’s financial position or results of operations. The Company recognizes interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2007, the Company did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 2002 through 2006 remain open to examination by the tax jurisdictions to which the Company is subject.

In December 2004, the FASBissued 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 and restricted stock, to be recognized in the income statement based on their estimated fair values.  Pro forma disclosure is no longer an alternative.  The Company adopted the standard on January 1, 2006.

The Company elected to adopt SFAS 123(R) using the “modified prospective” method in which compensation cost is recognized using the requirements of SFAS 123(R) for all share-based payments granted after adoption and the requirements of SFAS 123 for all unvested awards granted prior to adoption.

The Company currently has one share based compensation plan from which the Company’s compensation committee may grant any of the following types of awards:

Ÿ incentive stock options as defined in Section 422 of the Code;

Ÿ nonstatutory stock options;

Ÿ stock appreciation rights;

Ÿ shares of restricted stock;

Ÿ performance units and performance shares;

Ÿ other stock-based awards; and

Ÿ supplemental payments dedicated to the payment of income taxes

The total amount of share-based awards available for grant under the plan is equal to the greater of (i) 15% of the number of issued and outstanding shares of the Company’s common stock as of the first day of the then-current fiscal quarter, or (ii) 7,000,000 shares.

6

During the three months ended March 31, 2007 and 2006, the Company recognized approximately $2,771,000 and $60,000, respectively, of share based compensation expense.  These non-cash expenses are reflected as a component of the Company’s general and administrative expense.  The Company recorded income tax benefits of $908,000 and $11,000, respectively, related to the share based compensation expense recognized during the first quarters of 2007 and 2006.  Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized until the Company is in a current tax paying position.  Presently, all of the Company’s income taxes are deferred and the Company has substantial net operating losses available to carryover to future periods.

At March 31, 2007, the Company had $14.7 million 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 approximately 1.5 years from March 31, 2007.

The components of share based compensation expense for the quarters ended March 31, 2007 and 2006 were as follows (in thousands):

	Three Months Ended
	March 31,
	2007		2006
Stock options:
Incentive Stock Options	$	317	$	30
Non-Qualified Stock Options		405		30
Restricted stock		2,049		-
Share based compensation	$	2,771	$	60

Stock Options

Stock options generally vest equally over a three-year period, must be exercised within 10 years of the grant date and may be granted only to employees, directors and consultants.  The exercise price of each option may not be less than 100% of the fair market value of a share of Common Stock on the date of grant.  Upon a change in control of the Company, all outstanding options become immediately exercisable.

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.  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.

7

The following table outlines the assumptions used in computing the fair value of stock options granted during the first quarters of 2007 and 2006:

	Three Months Ended
	March 31,
	2007			2006
Dividend yield		0	%		0	%
Expected volatility		58.5	%		62.8	%
Risk-free rate		4.5%-4.8	%		4.5	%
Expected term	6 years			6 years
Forfeiture rate		5.0	%		8.4	%
Stock options granted (1)		285,641			10,000
Wgtd. avg. grant date fair value per share	$	7.00		$	6.16
Fair value of grants (1)	$	1,999,487		$	61,600
___________
(1) Prior to applying estimated forfeiture rate

The following table details stock option activity during the quarter ended March 31, 2007:

	Number of Options			Wgtd. Avg.  Exercise Price		Wgtd. Avg. Remaining Life	Aggregate Intrinsic Value (000's)
Outstanding at beginning of year		2,520,811		$	5.18
Granted		285,641			11.87
Expired/cancelled/forfeited		(20,000	)		11.75
Exercised		-			-
Outstanding at end of period		2,786,452		$	5.82	7 years	$	16,434
Options exercisable at end of period		1,558,467		$	2.85	5.4 years	$	13,781
Options expected to vest		1,166,585		$	9.59	8.9 years	$	2,520

Restricted Stock

Beginning in May 2006, the Company began granting shares of restricted stock to its employees as part of its long-term incentive compensation plan.  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, assuming a 5% estimated forfeiture rate.  Restricted stock grants vest 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.  Upon a change in control of the Company, all outstanding shares of restricted stock will become immediately vested.  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.

8

The following table details restricted stock activity during the quarter ended March 31, 2007:

	Number of Shares		Wgtd. Avg. Fair Value per Share
Outstanding at beginning of year		1,409,895	$	11.04
Granted		162,515		11.81
Expired/cancelled/forfeited		-		-
Lapse of restrictions		-		-
Outstanding at end of period		1,572,410	$	11.12

There were no shares of restricted stock vested at March 31, 2007.

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.

Note 6 Other Comprehensive Income and Derivative Instruments

The following table presents the Company’s comprehensive income for the three month periods ended March 31, 2007 and 2006 (in thousands):

	Three Months Ended
	March 31,
	2007			2006
Net income	$	10,814		$	9,149
Change in fair value of derivative instruments, accounted for as hedges, net of taxes		(5,874	)		7,054
Comprehensive income	$	4,940		$	16,203

For the three months ended March 31, 2007 and 2006, the effect of derivative instruments is net of deferred income tax (expense) benefit of $3,450,000 and ($3,681,000), 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 March 31, 2007, our derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $2,523,000 and $1,039,000 and oil hedges of $210,000 and ($677,000) for the three months ended March 31, 2007 and 2006, respectively.

9

As of March 31, 2007, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
2007	Costless Collar	17,500 Mmbtu	$8.36 - 10.01
April-December 2007	Costless Collar	10,000 Mmbtu	$7.00 -  8.65
Crude Oil:
April-June 2007	Costless Collar	1,300 Bbls	$61.15 - 71.52
July-December 2007	Costless Collar	200 Bbls	$65.00 - 77.70

At March 31, 2007, the Company recognized a net asset of $1.2 million related to the estimated fair value of these derivative instruments.    Based on estimated future commodity prices as of March 31, 2007, the Company would realize a $0.8 million gain, net of taxes, as an addition to oil and gas sales during the next 12 months.  These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

10

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company, which from the commencement of operations in 1985 through 2002, was focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties in Texas and Oklahoma.  As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

Specific asset diversification activities included the 2003 acquisition of proved reserves and acreage in the Southeast Carthage Field in East Texas. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring proved reserves.  During 2005 we further increased our presence in Oklahoma through multiple acquisition transactions and an expanded drilling program.  Our diversification efforts continued during 2006 through the opening of an exploration office in Tulsa, Oklahoma to augment our increased presence in the region, the drilling of 96 gross wells in Oklahoma and East Texas, which represented approximately 85% of our total gross wells drilled during 2006, and the divestiture of certain mature Gulf of Mexico properties.  Through these efforts, at December 31, 2006, 52% of our estimated proved reserves were located in longer life basins as compared to 50% at December 31, 2005 and 45% at December 31, 2004.  During 2006, 29% of our production was derived from longer life basins versus 30% during 2005, 16% during 2004 and virtually none in 2003.  The decline in production from longer life basins as a percent of our total production during 2006 was primarily due to the restoration of production at Main Pass Block 74 in January 2006 and our discovery at the Turtle Bayou Field, onshore Louisiana.  Our Main Pass Block 74 field had been shut in since September 2004 as a result of damages sustained during Hurricane Ivan.

During 2006, we invested approximately $171 million in exploratory, development and acquisition activities as we drilled a company record 113 gross wells realizing an overall success rate of 91% on our 2006 drilling program.  This drilling activity represented a 31% increase over the number of gross wells drilled in 2005.  As a result of our successful 2006 drilling program, production during the first quarter of 2007 increased to a quarterly company record 7.7 Bcfe, a 32% increase from the corresponding quarter of 2006.  This growth in production resulted in revenues, net income and cash flow from operating activities all achieving quarterly company records by increasing 32%, 18% and 128%, respectively, from first quarter 2006 levels.

11

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%, 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.

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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 reserve engineers in accordance with guidelines established by the SEC.  These estimates, however, represent projections based on geologic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures.  Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure.  The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment.  Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs, all of which may in fact vary considerably from actual results.  The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic.  For these reasons, estimates of the economically recoverable quantities of expected oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows may vary substantially.  Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties.  Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variance may be material.

Derivative Instruments

The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet.  At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production.  The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded 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 March 31, 2007, our derivative instruments were considered effective cash flow hedges.

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

New Accounting Standards

In December 2004, the Financial Accounting Standards Board(“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 on January 1, 2006 using the modified prospective method.

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During the three months ended March 31, 2007 and 2006, we recognized $2,771,000 and $60,000, respectively, of share based compensation expense.  These non-cash expenses are reflected as a component of our general and administrative expense.

At March 31, 2007, we had $14.7 million 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 approximately 1.5 years from March 31, 2007.  See Note 5 to our financial statements for more detailed information relative to share based compensation.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes” (“FIN 48”).  FIN 48 is an interpretation of SFAS 109, “Accounting for Income Taxes,” and it seeks to reduce the diversity in practice associated with certain aspects of measurement and accounting for income taxes and requires expanded disclosure with respect to the uncertainty in income taxes.  FIN 48 is effective for fiscal years beginning after December 15, 2006.  Accordingly, we adopted FIN 48 on January 1, 2007.  The adoption of FIN 48 did not have an effect on our financial position or results of operations. We recognize interest and penalties related to uncertain tax positions in income tax expense. As of March 31, 2007, we did not have any accrued interest or penalties related to uncertain tax positions. The tax years from 2002 through 2006 remain open to examination by the tax jurisdictions to which we are subject.

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
	March 31,
	2007		2006
Production:
Oil (Bbls)		359,781		154,974
Gas (Mcf)		5,532,314		4,876,963
Total Production (Mcfe)		7,691,000		5,806,807
Sales:
Total oil sales	$	21,587,900	$	8,765,568
Total gas sales		40,295,694		38,250,353
Total oil and gas sales		61,883,594		47,015,921
Average sales prices:
Oil (per Bbl)	$	60.00	$	56.56
Gas (per Mcf)		7.28		7.84
Per Mcfe		8.05		8.10

The above sales and average sales prices include additions (reductions) to revenue related to the settlement of gas hedges of $2,523,000 and $1,039,000 and the settlement of oil hedges of $210,000 and ($677,000) for the three months ended March 31, 2007 and 2006, respectively.

Net income totaled $10,814,000 and $9,149,000 for the quarters ended March 31, 2007 and 2006, respectively.  The  increase in net income during the 2007 period was primarily attributable to the following:

Production.  Oil production during the three month period ended March 31, 2007 increased 132% from the comparable 2006 period, while natural gas production during the quarter ended March 31, 2007 increased 13% from the 2006 quarter.  In total, production during the first quarter of 2007 was 32% higher than the production during the first quarter of 2006.

In December 2006, production was restored at our Ship Shoal 72 Field, which produces substantial oil volumes.  This field had been shut-in during October and November 2006 to replace a portion of the main field pipeline.  As a result of several successful wells drilled during 2006 and the improvement in throughput from the new main field pipeline, production from Ship Shoal 72 totaled 2.8 Bcfe, or approximately 36% of total company production during the first quarter of 2007, as compared to only 0.8 Bcfe, or 13% of total company production during the first quarter of 2006.  The increase in production during the first quarter of 2007 was partially offset by the sale of certain producing Gulf of Mexico properties in November 2006.

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A common characteristic of Gulf of Mexico reservoirs is a high initial production rate followed by a steep decline.  As a result, we expect that the production rates from the recently drilled wells at Ship Shoal 72, as well as from other discoveries made in the Gulf of Mexico during 2006, would decline throughout 2007.  If our 2007 drilling program does not continue its success, we may not be able to completely offset these declines and continue to meaningfully grow production during the remainder of 2007.

Prices.  Including the effects of our hedges, average oil prices per barrel for the quarter ended March 31, 2007 were $60.00, as compared to $56.56 for the 2006 period.  Average gas prices per Mcf were $7.28 for the first quarter of 2007, as compared to $7.84 for the comparable period in 2006.  Stated on an Mcfe basis, unit prices received during the quarter ended March 31, 2007 were 1% lower than the prices received during the comparable 2006 quarter.

Revenue.  Oil and gas sales during the quarter ended March 31, 2007 increased 32% to $61,884,000, as compared to oil and gas sales of $47,016,000 for the 2006 period.  The increased revenue during the 2007 period was primarily the result of higher production levels.

During the first quarter of 2007, gas gathering revenue and other income totaled $2,124,000, as compared to $1,342,000 during the 2006 period.The increase in the first quarter of 2007 is the result of increased gas volumes being transported through the gas gathering systems.

Expenses. Lease operating expenses for the three month period ended March 31, 2007 decreased to $6,937,000, as compared to $6,951,000 during the 2006 period.  However, first quarter 2006 lease operating costs included $1,671,000 of operating expenses related to properties that were sold in November 2006.  Excluding the operating expenses and production related to the sold properties, per unit operating expenses totaled $1.02 per Mcfe during the first quarter of 2006, as compared to $0.90 per Mcfe during the first quarter of 2007.  The decline in per unit costs is primarily attributable to the significantly increased production during the first quarter of 2007.  We expect that operating expenses for the remainder of 2007 will be slightly higher than first quarter 2007 expenses, but lower than the operating expenses incurred during the comparable second through fourth quarters of 2006.

Production taxes during the first quarter of 2007 totaled $2,130,000, as compared to $1,570,000 during the corresponding quarter of 2006. The increase in 2007 production taxes is primarily due to increased production from our Oklahoma, Texas and onshore Louisiana properties.  In addition, effective July 1, 2006, the Louisiana severance tax rate increased 48%.

General and administrative expenses during the first quarter of 2007 totaled $5,180,000, as compared to expenses of $2,155,000 during the 2006 period.  Included in general and administrative expenses for the three month periods ended March 31, 2007 and 2006 was $2,771,000 and $60,000, respectively, attributable to share based compensation recognized in connection with SFAS 123(R).  Excluding the impact of SFAS 123(R), the increase in general and administrative expenses is primarily attributable to the 11% increase in our staffing during 2006 necessary to manage our increased operational activity.  We capitalized $1,675,000 and $1,461,000 of general and administrative costs during the quarters ended March 31, 2007 and 2006, respectively.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the quarter ended March 31, 2007 totaled $26,764,000, or $3.48 per Mcfe, as compared to $18,122,000, or $3.12 per Mcfe, in the respective period of 2006.   The increase in DD&A expense per Mcfe is primarily due to increased costs to drill for, develop and acquire oil and gas reserves.  Assuming commodity prices remain at current levels, we would expect the costs to drill for, develop and acquire oil and gas reserves to generally approximate first quarter 2007 levels.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $3,632,000 during the quarter ended March 31, 2007, as compared to $3,372,000 during the 2006 quarter.  We capitalized $1,352,000 and $1,098,000 of interest during the three months ended March 31, 2007 and 2006, respectively.

Income tax expense during the first quarter of 2007 totaled $6,537,000, as compared to $5,355,000 during the 2006 period.  The increase is primarily the result of the increased operating profit during the current quarter, as compared to 2006.  We provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.  The increase in our effective tax rate during the first quarter of 2007, as compared to the 2006 period, is primarily the result of the increase in non-deductible stock compensation expense related to incentive stock options.

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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 $29,974,000 in the three month period ended March 31, 2006 to $68,447,000 during the three month 2007 period.    The increase in operating cash flow was primarily the result of higher production volumes realized during 2007.

At March 31, 2007, we had a working capital deficit of $30.5 million versus a deficit of $7.9 million at December 31, 2006.   The decline in our working capital was primarily due to the $9.3 million reduction in the estimated fair value of our derivative instruments, which is the result of higher estimated future commodity prices, the $9.4 million increase in our accounts payable to vendors, which is a result of operational activity, and the $3.8 million increase in accrued interest, which is primarily a function of the timing of payments due under our 10 3/8% Senior Notes due 2012.  We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity.   We currently have $37.5 million of available capacity under our bank credit facility.

Source of Capital: Debt

During 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 March 31, 2007, $5.8 million had been accrued in connection with the May 15, 2007 interest payment.  At March 31, 2007 we were in compliance with all of the covenants under the Notes.

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

The credit facility is secured by, among other things, a lien on at least 90% of the PDP present value and at least 80% of the aggregate proved reserves of our oil and gas properties.  PDP present value means the present value discounted at nine percent of the future net revenues attributable to producing reserves.  The borrowing base under the credit facility is based primarily upon the valuation as of January 1 and July 1 of each year of our mortgaged oil and gas properties. The borrowing base is currently $77.5 million.  The next scheduled borrowing base re-determination will be on October 1, 2007 and we or the lenders may request additional borrowing base re-determinations.  As of March 31, 2007, we had $40 million of borrowings outstanding under the credit facility and we were 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.

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.

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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 2007 will require significant capital.  Our 2007 capital budget, which is dependent on production, commodity prices, drilling success and related completion and facility costs and which excludes acquisitions, is $160 million to $175 million, of which approximately $52 million had been incurred through March 31, 2007.

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 2007 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.

Disclosure Regarding Forward Looking Statements

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

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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 2007, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $18 million impact on our revenues.

We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged.  If the floating price exceeds the fixed price, we are required to pay the counterparts this difference multiplied by the quantity hedged.  During the quarter ended March 31, 2007, we received from the counterparties to our derivative instruments $2,733,000 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 March 31, 2007, we had entered into the following oil and gas contracts accounted for as cash flow hedges:

Production Period	Instrument Type	Daily Volumes	Weighted Average Price
Natural Gas:
2007	Costless Collar	17,500 Mmbtu	$8.36 - 10.01
April-December 2007	Costless Collar	10,000 Mmbtu	$7.00 -  8.65
Crude Oil:
April-June 2007	Costless Collar	1,300 Bbls	$61.15 - 71.52
July-December 2007	Costless Collar	200 Bbls	$65.00 - 77.70

At March 31, 2007, we recognized a net asset of $1.2 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of March 31, 2007, we would realize a $0.8 million gain, net of taxes, as an addition to oil and gas sales during the next 12 months.  These gains are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

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Debt outstanding under our bank credit facility is subject to a floating interest rate and represents 21% of our total debt as of March 31, 2007.  Based upon an analysis, utilizing the actual interest rate in effect and balances outstanding as of March 31, 2007, and assuming a 10% increase in interest rates and no changes in the amount of debt outstanding, the potential effect on interest expense for the remainder of 2007 is approximately $0.2 million.

Item 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

Changes in Internal Controls

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

Part II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 1A. RISK FACTORS

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

As is generally the case in the Gulf Coast Basin where the majority of our current production is located, many of our producing properties are characterized by a high initial production rate, followed by a steep decline in production. As a result, we expect that production rates from the wells drilled during 2006 at Ship Shoal 72, as well as the production from other discoveries made in the Gulf Coast Basin during 2006, to decline throughout 2007.  In order to maintain or increase our reserves, we must constantly locate and develop or acquire new oil and natural gas reserves to replace those being depleted by production. We must do this even during periods of low oil and natural gas prices when it is difficult to raise the capital necessary to finance our exploration, development and acquisition activities. Without successful exploration, development or acquisition activities, our reserves and revenues will decline rapidly. In particular, if our 2007 drilling program does not continue its success, we may not be able to completely offset the expected declines from the discoveries mentioned above and continue to meaningfully grow production during the remainder of 2007.  We may not be able to find and develop or acquire additional reserves at an acceptable cost or have access to necessary financing for these activities, either of which would have a material adverse effect on our financial condition.

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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 50% of our production during the first quarter of 2007.  Operations in this area are subject to tropical weather disturbances.  Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, Hurricanes Katrina and Rita impacted our South Louisiana and Texas operations in August and September of 2005, respectively, causing property damage to certain facilities, a substantial portion of which was covered by insurance. As a result, a portion of our oil and gas production was shut-in reducing our overall production volumes in the third and fourth quarters of 2005.  In addition, production from our Main Pass 74 field, which represented approximately 13% of our first quarter 2007 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 March 31, 2007, the aggregate amount of our outstanding indebtedness was $189 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.

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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 March 31, 2007, we had $40 million outstanding under our bank credit facility and our borrowing base was $75 million. Effective April 13, 2007, our borrowing base was increased to $77.5 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

NONE.

Item 5. OTHER INFORMATION

NONE.

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Item 6. EXHIBITS

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

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

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

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

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SIGNATURE

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

	PETROQUEST ENERGY, INC.
Date:  May 3, 2007	/s/	Michael O. Aldridge
		Michael O. Aldridge
		Executive Vice President, Chief Financial Officer and Treasurer
		(Authorized Officer and Principal Financial and Accounting Officer)

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