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

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

Commission file number: 001-32681

 

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)

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

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

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

Yes þ     No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes o     No o

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

Large accelerated filer o		Accelerated filer þ		Non-accelerated filer o		Smaller reporting company o

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

Yes o     No þ

As of May 3, 2011, there were 63,163,460 shares of the registrant’s common stock, par value $.001 per share, outstanding.

 

 

PETROQUEST ENERGY, INC.

Table of Contents

		Page No.
Part I. Financial Information
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010			1
Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010			2
Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010			3
Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2011 and 2010			4
Notes to Consolidated Financial Statements			5
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			20
Item 1A. Risk Factors			20
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			22
Item 3. Defaults upon Senior Securities			22
Item 4. (Removed and Reserved)			22
Item 5. Other Information			22
Item 6. Exhibits			22
Exhibit 31.1
Exhibit 31.2
Exhibit 32.1
Exhibit 32.2

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

		March 31,				December 31,
		2011				2010
		(unaudited)				(Note 1)
ASSETS
Current assets:
Cash and cash equivalents		$	55,022			$	63,237
Revenue receivable			13,346				13,386
Joint interest billing receivable			21,486				12,193
Other receivable			13,851				13,795
Prepaid drilling costs			2,451				789
Drilling pipe inventory			7,386				11,711
Other current assets			4,195				1,827
Total current assets			117,737				116,938
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method			1,453,952				1,433,642
Unevaluated oil and gas properties			59,426				54,851
Accumulated depreciation, depletion and amortization			(1,195,295	)			(1,175,553	)
Oil and gas properties, net			318,083				312,940
Gas gathering assets			4,177				4,177
Accumulated depreciation and amortization of gas gathering assets			(1,571	)			(1,496	)
Total property and equipment			320,689				315,621
Other assets, net of accumulated depreciation and amortization of $6,824 and $6,435, respectively			6,143				6,958
Total assets		$	444,569			$	439,517
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors		$	33,312			$	26,097
Advances from co-owners			12,077				7,963
Oil and gas revenue payable			4,529				7,220
Accrued interest and preferred stock dividend			2,446				6,575
Hedge liability			1,817				1,089
Asset retirement obligation			674				1,517
Other accrued liabilities			5,096				7,380
Total current liabilities			59,951				57,841
10% Senior Notes			150,000				150,000
Asset retirement obligation			24,257				23,075
Other liabilities			474				439
Commitments and contingencies
Stockholders’ equity:
Preferred stock, $.001 par value; authorized 5,000 shares; issued and outstanding 1,495 shares			1				1
Common stock, $.001 par value; authorized 150,000 shares; issued and outstanding 61,834 and 61,565 shares, respectively			62				62
Paid-in capital			267,463				266,907
Accumulated other comprehensive loss			(1,817	)			(1,089	)
Accumulated deficit			(55,822	)			(57,719	)
Total stockholders’ equity			209,887				208,162
Total liabilities and stockholders’ equity		$	444,569			$	439,517

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(unaudited)

(Amounts in Thousands, Except Per Share Data)

		Three Months Ended
		March 31,
		2011				2010
Revenues:
Oil and gas sales		$	41,546			$	47,545
Gas gathering revenue			64				69
			41,610				47,614
Expenses:
Lease operating expenses			9,503				9,695
Production taxes			1,162				1,348
Depreciation, depletion and amortization			14,062				14,984
Ceiling test writedown			5,934				—
Gas gathering costs			7				11
General and administrative			4,398				4,509
Accretion of asset retirement obligation			752				468
Interest expense			2,694				1,810
			38,512				32,825
Gain on legal settlement			—				12,400
Other income (expense)			80				(83	)
Income from operations			3,178				27,106
Income tax expense (benefit)			1				(3,891	)
Net income			3,177				30,997
Preferred stock dividend			1,280				1,280
Net income available to common stockholders		$	1,897			$	29,717
Earnings per common share:
Basic
Net income per share		$	0.03			$	0.47
Diluted
Net income per share		$	0.03			$	0.46
Weighted average number of common shares:
Basic			61,668				61,243
Diluted			63,018				67,382

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(unaudited)

(Amounts in Thousands)

		Three Months Ended
		March 31,
		2011				2010
Cash flows from operating activities:
Net income		$	3,177			$	30,997
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense (benefit)			1				(3,891	)
Depreciation, depletion and amortization			14,062				14,984
Ceiling test writedown			5,934				—
Non-cash gain on legal settlement			—				(4,164	)
Accretion of asset retirement obligation			752				468
Share based compensation expense			1,032				1,982
Amortization costs and other			153				388
Payments to settle asset retirement obligations			(513	)			(517	)
Changes in working capital accounts:
Revenue receivable			40				583
Joint interest billing receivable			(9,293	)			(481	)
Accounts payable and accrued liabilities			(1,430	)			8,624
Advances from co-owners			4,114				3,105
Other			230				630
Net cash provided by operating activities			18,259				52,708
Cash flows used in investing activities:
Investment in oil and gas properties			(24,701	)			(25,587	)
Net cash used in investing activities			(24,701	)			(25,587	)
Cash flows used in financing activities:
Net payments for share based compensation			(476	)			(221	)
Deferred financing costs			(13	)			(2	)
Payment of preferred stock dividend			(1,284	)			(1,284	)
Repayment of bank borrowings			—				(19,000	)
Net cash used in financing activities			(1,773	)			(20,507	)
Net (decrease) increase in cash and cash equivalents			(8,215	)			6,614
Cash and cash equivalents, beginning of period			63,237				20,772
Cash and cash equivalents, end of period		$	55,022			$	27,386
Supplemental disclosure of cash flow information:
Cash paid during the period for:
Interest		$	8,003			$	171
Income taxes		$	1			$	—

See accompanying Notes to Consolidated Financial Statements.

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income

(unaudited)

(Amounts in Thousands)

		Three Months Ended
		March 31,
		2011				2010
Net income		$	3,177			$	30,997
Change in fair value of derivative instruments, accounted for as hedges, net of tax benefit (expense) of zero, and ($3,891), respectively			(728	)			6,569
Comprehensive income		$	2,449			$	37,566

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-month periods ended March 31, 2011 and 2010, 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, 2011 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, 2010 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, 2010.

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

Note 2 — Convertible Preferred Stock

The Company has 1,495,000 shares of 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”) outstanding.

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

Dividends. The Series B Preferred Stock accumulates dividends at an annual rate of 6.875% for each share of Series B Preferred Stock. Dividends are cumulative from the date of first issuance and, to the extent payment of dividends is not prohibited by the Company’s debt agreements, assets are legally available to pay dividends and the Company’s board of directors or an authorized committee of the board declares a dividend payable, the Company pays dividends in cash, every quarter.

Mandatory conversion. The Company may, at its option, cause shares of the Series B Preferred Stock to be automatically converted at the applicable conversion rate, but only if the closing sale price of the Company’s common stock for 20 trading days within a period of 30 consecutive trading days ending on the trading day immediately preceding the date the Company gives the conversion notice equals or exceeds 130% of the conversion price in effect on each such trading day.

Conversion rights. Each share of Series B Preferred Stock may be converted at any time, at the option of the holder, into 3.4433 shares of the Company’s common stock (which is based on an initial conversion price of approximately $14.52 per share of common stock, subject to adjustment) plus cash in lieu of fractional shares, subject to the Company’s right to settle all or a portion of any such conversion in cash or shares of the Company’s common stock. If the Company elects to settle all or any portion of its conversion obligation in cash, the conversion value and the number of shares of the Company’s common stock it will deliver upon conversion (if any) will be based upon a 20 trading day averaging period.

Upon any conversion, the holder will not receive any cash payment representing accumulated and unpaid dividends on the Series B Preferred Stock, whether or not in arrears, except in limited circumstances. The conversion rate is equal to $50 divided by the conversion price at the time. The conversion price is subject to adjustment upon the occurrence of certain events. The conversion price on the conversion date and the number of shares of the Company’s common stock, as applicable, to be delivered upon conversion may be adjusted if certain events occur.

Note 3 — Earnings Per Share

The Company accounts for earnings per share in accordance with ASC Topic 260-10-45. A reconciliation between basic and diluted earnings per share computations (in thousands, except per share amounts) is as follows:

		Income				Shares				Per
For the Three Months Ended March 31, 2011		(Numerator)				(Denominator)				Share Amount
Net income available to common stockholders		$	1,897				61,668
Attributable to participating securities			(45	)			—
BASIC EPS		$	1,852				61,668			$	0.03
Net income available to common stockholders		$	1,897				61,668
Effect of dilutive securities:
Stock options			—				424
Restricted stock			—				926
DILUTED EPS		$	1,897				63,018			$	0.03
		Income				Shares				Per
For the Three Months Ended March 31, 2010		(Numerator)				(Denominator)				Share Amount
Net income available to common stockholders		$	29,717				61,243
Attributable to participating securities			(753	)			—
BASIC EPS		$	28,964				61,243			$	0.47
Net income available to common stockholders		$	29,717				61,243
Effect of dilutive securities:
Stock options			—				368
Restricted stock			—				623
Series B preferred stock			1,280				5,148
DILUTED EPS		$	30,997				67,382			$	0.46

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares during the three-months ended March 31, 2011 were not included in the computation of diluted earnings per share because the inclusion would have been anti-dilutive. Options to purchase 25,000 and 2,150,000 shares of common stock were outstanding during the periods ended March 31, 2011 and 2010, respectively, and were not included in the computation of diluted earnings per share because the options’ exercise prices were in excess of the average market price of the common shares.

Note 4 — Long-Term Debt

On August 19, 2010, PetroQuest Energy, Inc. issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Notes”) in a public offering. The net proceeds of the offering, together with cash on hand, were used to fund the tender offer and consent solicitation and redemption of the Company’s 10⅜% Senior Notes due 2012.

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 March 1 and September 1. At March 31, 2011, $1.3 million had been accrued in connection with the September 1, 2011 interest payment and the Company was in compliance with all of the covenants contained in the Notes.

The Company and PetroQuest Energy, L.L.C. (the “Borrower”) have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows the Company to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 2, 2013. As of March 31, 2011 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement and availability of $100 million.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to the Company’s oil and gas properties as of January 1 and July 1 of each year. The current borrowing base is $100 million effective April 1, 2011. The next borrowing base redetermination is scheduled to occur by September 30, 2011. The Company or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of the assets of the Company and its subsidiaries, including a lien on all equipment and at least 85% of the aggregate total value of the Company’s oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1.625% to 2.625% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2.5% to 3.5% depending on borrowing base usage). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by the Company) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, the Company pays commitment fees of 0.5%.

The Company and its subsidiaries are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of March 31, 2011, the Company was in compliance with all of the covenants contained in the Credit Agreement.

Note 5 — Asset Retirement Obligation

The Company accounts for asset retirement obligations in accordance with ASC Topic 410-20, which requires recording the fair value of an asset retirement obligation associated with tangible long-lived assets in the period incurred. Asset retirement obligations associated with long-lived assets included within the scope of ASC Topic 410-20 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed.

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

		Three Months Ended
		March 31,
		2011				2010
Asset retirement obligation, beginning of period		$	24,592			$	23,916
Liabilities incurred			100				—
Liabilities settled			(513	)			(517	)
Accretion expense			752				468
Revisions in estimated cash flows			—				217
Asset retirement obligation, end of period			24,931				24,084
Less: current portion of asset retirement obligation			(674	)			(7,177	)
Long-term asset retirement obligation		$	24,257			$	16,907

Note 6 — Share-Based Compensation

The Company accounts for share-based compensation in accordance with ASC Topic 718. Share-based compensation expense is reflected as a component of the Company’s general and administrative expense. A detail of share-based compensation for the periods ended March 31, 2011 and 2010 is as follows (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Stock options:
Incentive Stock Options		$	83			$	235
Non-Qualified Stock Options			165				572
Restricted stock			784				1,175
Share based compensation		$	1,032			$	1,982

Note 7 — Ceiling Test

The Company uses the full cost method to account for its oil and gas operations. Accordingly, the costs to acquire, explore for and develop oil and gas properties are capitalized. 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, including the effects of cash flow hedges in place, 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 ceiling test write down of oil and gas properties in the quarter in which the excess occurs.

At March 31, 2011, the prices used in computing the estimated future net cash flows from the Company’s proved reserves, including the effect of hedges in place at March 31, 2011, averaged $3.45 per Mcfe and $85.38 per barrel. As a result of lower natural gas prices and their negative impact on certain of the Company’s longer-lived estimated proved reserves and estimated future net cash flows, the Company recognized a ceiling test write-down of $5.9 million during the three months ended March 31, 2011. The Company’s cash flow hedges in place at March 31, 2011 reduced the ceiling test write-down by approximately $1.6 million.

Note 8 — Derivative Instruments

The Company seeks to reduce its exposure to commodity price volatility by hedging a portion of its production through commodity derivative instruments. The Company accounts for commodity derivatives in accordance with ASC Topic 815. When the conditions for hedge accounting specified in ASC Topic 815 are met, the Company may designate its commodity derivatives as cash flow hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative would be recorded in the income statement as derivative income or expense. At March 31, 2011, the Company’s outstanding derivative instruments were considered effective cash flow hedges.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $200,000 and $1,531,000 and oil hedges of ($100,000) and zero for the three months ended March 31, 2011 and 2010, respectively.

As of March 31, 2011, the Company had entered into the following oil and gas contracts accounted for as cash flow hedges:

		Instrument						Weighted
Production Period		Type		Daily Volumes				Average Price
Natural Gas:
April-December 2011		Costless Collar		15,000 Mmbtu				$	4.17 – 4.90
Crude Oil:
April-December 2011		Costless Collar		500 Bbls				$	90.00 – 97.78

At March 31, 2011, the Company recognized a net liability of approximately $1.8 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of March 31, 2011, the Company would realize a $1.1 million loss, net of taxes, during the next 12 months. These losses are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

All of the Company’s derivative instruments at March 31, 2011 were designated as hedging instruments under ASC Topic 815. The following tables reflect the fair value of the Company’s derivative instruments in the consolidated financial statements (in thousands):

Effect of Derivative Instruments on the Consolidated Balance Sheet at March 31, 2011 and December 31, 2010:

		Commodity Derivatives
		Balance Sheet
Period		Location		Fair Value
March 31, 2011		Hedge liability		$	(1,817	)
December 31, 2010		Hedge liability		$	(1,089	)

Effect of Derivative Instruments on the Consolidated Statement of Operations for the three months ended March 31, 2011 and 2010:

		Amount of Gain (Loss)				Location of		Amount of Gain
		Recognized in Other				Gain Reclassified		Reclassified into
Instrument		Comprehensive Income				into Income		Income
Commodity Derivatives at March 31, 2011		$	(728	)		Oil and gas sales		$	100
Commodity Derivatives at March 31, 2010		$	6,569			Oil and gas sales		$	1,531

As defined in ASC Topic 820, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. ASC Topic 820 establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:

•

Level 1: valuations consist of unadjusted quoted prices in active markets for identical assets and liabilities and has the highest priority;

•

Level 2: valuations rely on quoted prices in markets that are not active or observable inputs over the full term of the asset or liability;

•

Level 3: valuations are based on prices or third party or internal valuation models that require inputs that are significant to the fair value measurement and are less observable and thus have the lowest priority.

The Company classifies its commodity derivatives based upon the data used to determine fair value. The Company’s derivative instruments at March 31, 2011 were in the form of costless collars based on NYMEX pricing. The fair value of these derivatives is derived using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of the Company’s default risk for derivative liabilities. As a result, the Company designates its commodity derivatives as Level 2 in the fair value hierarchy.

The following table summarizes the net valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of March 31, 2011 and December 31, 2010 (in thousands):

		Fair Value Measurements Using
		Quoted Prices				Significant Other				Significant
		in Active				Observable				Unobservable
Instrument		Markets (Level 1)				Inputs (Level 2)				Inputs (Level 3)
Commodity Derivatives:
At March 31, 2011		$	—			$	(1,817	)		$	—
At December 31, 2010		$	—			$	(1,089	)		$	—

Note 9 — Gain on Legal Settlement

In January 2010, the Company recorded a gain relative to a $9 million cash settlement received from a lawsuit that was originally filed by the Company in 2008 relating to disputed interests in certain oil and gas assets purchased in 2007. In addition to the cash proceeds received, the Company was assigned additional working interests in certain producing properties. The Company recorded an additional $4.2 million gain representing the estimated fair market value of those interests on the effective date of the settlement.

Note 10 — Income Taxes

The Company typically provides 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. As a result of the ceiling test write-downs recognized, the Company has incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the realizability of its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $2.3 million and $3.2 million as of March 31, 2011 and December 31, 2010, respectively.

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 incorporated in the State of Delaware with operations in Oklahoma, Texas, the Gulf Coast Basin, Arkansas and Wyoming. We seek to grow our production, proved reserves, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. From the commencement of our operations in 1985 through 2002, we were focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow waters of the Gulf of Mexico shelf. During 2003, we began the implementation of our strategic goal of diversifying our reserves and production into longer life and lower risk onshore properties. As part of the strategic shift to diversify our asset portfolio and lower our geographic and geologic risk profile, we refocused our opportunity selection processes to reduce our average working interest in higher risk projects, shift capital to higher probability of success onshore wells and mitigate the risks associated with individual wells by expanding our drilling program across multiple basins.

We have successfully diversified into onshore, longer life basins in Oklahoma, Arkansas, Wyoming and Texas through a combination of selective acquisitions and drilling activity. Beginning in 2003 with our acquisition of the Carthage Field in Texas through 2010, we have invested approximately $733 million into growing our longer life assets. During the seven year period ended December 31, 2010, we have realized a 94% drilling success rate on 653 gross wells drilled. Comparing 2010 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 220% and estimated proved reserves by 131%. At March 31, 2011, 88% of our estimated proved reserves and 59% of our first quarter 2011 production were derived from our longer life assets.

During late 2008, in response to declining commodity prices and the global financial crisis, we shifted our focus from increasing reserves and production to building liquidity and strengthening our balance sheet. Because of our significant operational control, we were able to reduce our capital expenditures from $358 million in 2008 to $59 million in 2009 thus allowing us to utilize our cash flow from operations, combined with proceeds from an equity offering, to repay $130 million of bank debt since the end of 2008. While we achieved our goal of strengthening the financial position of the Company, because of the reduced capital investments during 2009, our production declined by 9% during 2010.

During 2010 we refocused on the key elements of our business strategy with the goal of growing reserves and production in a fiscally prudent manner. Our 2011 capital expenditures, which include capitalized interest and overhead, are expected to range between $115 million and $125 million. In order to maintain our financial flexibility, we plan to fund our 2011 capital expenditures budget with cash flow from operations and $14 million in additional proceeds expected to be received in November 2011 under the Woodford joint development agreement (see Liquidity and Capital Resources-Source of Capital: Joint Ventures). We expect to be able to actively manage our 2011 capital budget in the event commodity prices, or the health of the global financial markets, do not match our expectations.

Critical Accounting Policies

Reserve Estimates

Our estimates of proved oil and gas reserves constitute those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. 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 quantity and quality of available data, engineering and geological interpretation and professional 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. 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. 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.

Disclosure requirements under Staff Accounting Bulletin 113 (“SAB 113”) include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization.

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.

The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.

We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings.

We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate.

Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effect of cash flow hedges in place, 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.

At March 31, 2011, the prices used in computing the estimated future net cash flows from our proved reserves, including the effect of hedges in place at March 31, 2010, averaged $3.45 per Mcfe and $85.38 per barrel. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized a ceiling test write-down of $5.9 million during the three months ended March 31, 2011. Our cash flow hedges in place at March 31, 2011 reduced the ceiling test write-down by approximately $1.6 million.

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 further 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.

Derivative Instruments

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

Our hedges are specifically referenced to NYMEX prices. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At March 31, 2011, our derivative instruments were considered effective cash flow hedges.

Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we calculate the fair value of our commodity derivatives using an independent third-party’s valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties’ default risk for derivative assets and an estimate of our default risk for derivative liabilities.

Results of Operations

The following table sets forth certain information with respect to our oil and gas operations for the periods noted. These historical results are not necessarily indicative of results to be expected in future periods.

		Three Months Ended
		March 31,
		2011				2010
Production:
Oil (Bbls)			175,264				144,641
Gas (Mcf)			5,777,340				6,245,248
Ngl (Mcfe)			540,470				614,615
Total Production (Mcfe)			7,369,394				7,727,709
Sales:
Total oil sales		$	17,172,700			$	11,377,113
Total gas sales			19,125,695				30,772,115
Total ngl sales			5,247,610				5,395,516
Total oil and gas sales		$	41,546,005			$	47,544,744
Average sales prices:
Oil (per Bbl)		$	97.98			$	78.66
Gas (per Mcf)			3.31				4.93
Ngl (per Mcfe)			9.71				8.78
Per Mcfe			5.64				6.15

The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $200,000 and $1,531,000 and oil hedges of ($100,000) and zero for the three months ended March 31, 2011 and 2010, respectively.

Net income available to common stockholders totaled $1,897,000 and $29,717,000 for the quarters ended March 31, 2011 and 2010, respectively. The primary fluctuations were as follows:

Production Total production decreased 5% during the three month period ended March 31, 2011 as compared to the 2010 period. Gas production during the quarter ended March 31, 2011 decreased 7% from the comparable period in 2010. The decrease in gas production was primarily the result of normal production declines in the Gulf Coast area. Because approximately 75% of our 2011 scheduled drilling program is allocated to our longer-life assets, we expect 2011 gas production to approximate 2010 as we continue to experience normal declines in the Gulf Coast area, offset by increased long-lived gas production.

Oil production during the three month period ended March 31, 2011 increased 21% from the 2010 period due to successful recompletions at our Ship Shoal 72 field as well as continued improvements at our Ship Shoal 225 field, which was restored to production in 2010. Our first well in the Niobrara Shale commenced production in the fourth quarter of 2010 and represented 2.5% of our total oil production during the first quarter of 2011. With our entry into the Niobrara Shale and Eagle Ford Shale, which are both typically oil bearing formations, we expect to increase oil production during 2011.

Ngl production during the three month period ended March 31, 2011 decreased 12% from the 2010 period due to the general decline in Gulf Coast gas production.

Prices Including the effects of our hedges, average gas prices per Mcf for the three month period ended March 31, 2011 were $3.31, as compared to $4.93 for the 2010 period. Average oil prices per Bbl for the three months ended March 31, 2011 were $97.98, as compared to $78.66 for the 2010 period and average Ngl prices per Mcfe were $9.71 and $8.78 during 2011 and 2010, respectively. Stated on an Mcfe basis, unit prices received during the three months ended March 31, 2011 were 8% lower than the prices received during the comparable 2010 period.

Revenue Including the effects of hedges, oil and gas sales during the three months ended March 31, 2011 decreased 13% to $41,546,000, as compared to oil and gas sales of $47,545,000 during the 2010 period. The decreased revenue during 2011 was primarily the result of lower gas prices and production realized during the quarter ended March 31, 2011.

Expenses Lease operating expenses for the quarter ended March 31, 2011 decreased to $9,503,000 as compared to $9,695,000 during the 2010 period. Per unit lease operating expenses totaled $1.29 per Mcfe during the three month period ended March 31, 2011 as compared to $1.25 per Mcfe during the 2010 period. Per unit lease operating expenses increased primarily due to the overall reduction in produced volumes. Lease operating expenses in 2011 are expected to generally approximate lease operating expenses in 2010.

General and administrative expenses during the quarter ended March 31, 2011 totaled $4,398,000 as compared to expenses of $4,509,000 during 2010. Included in general and administrative expenses was share-based compensation expense related to ASC Topic 718, as follows (in thousands):

		Three Months Ended
		March 31,
		2011				2010
Stock options:
Incentive Stock Options		$	83			$	235
Non-Qualified Stock Options			165				572
Restricted stock			784				1,175
Share based compensation		$	1,032			$	1,982

We capitalized $3,144,000 and $2,624,000 of general and administrative costs during the three month periods ended March 31, 2011 and 2010, respectively. General and administrative expenses in 2011 are expected to approximate 2010 expenses.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the three months ended March 31, 2011 totaled $13,809,000, or $1.87 per Mcfe, as compared to $14,736,000, or $1.91 per Mcfe, during the comparable 2010 period.

The prices of oil and gas used in computing the estimated future net cash flows from our estimated proved reserves at March 31, 2011 had a negative impact on our estimated proved reserves from certain of our longer-life properties and reduced the estimated discounted cash flow from our estimated proved reserves. As a result, we recorded a non-cash ceiling test write-down of our oil and gas properties as of March 31, 2011 totaling $5,934,000. See Note 7, “Ceiling Test” for further discussion of the ceiling test write-down.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,694,000 during the three months ended March 31, 2011 as compared to $1,810,000 during the 2010 period. During the second quarter of 2010, we sold a portion of our unevaluated properties pursuant to the Woodford joint development agreement, which resulted in a decrease in the amount of interest capitalized to oil and gas properties. During the first quarter of 2011 our capitalized interest totaled $1,393,000, as compared to $2,640,000 during the 2010 period. We have reduced the outstanding borrowings under our bank credit facility from $29 million at December 31, 2009 to zero at March 31, 2011. We also retired our 10 3/8% Senior Notes due 2012 during August 2010 in connection with the issuance of our 10% Senior Notes due 2017, which we expect will result in a decrease in our cash interest payments during 2011.

In January 2010, we recorded a gain relative to a $9,000,000 cash settlement received from a lawsuit filed by us in 2008 relating to disputed interests in certain oil and gas assets purchased in 2007. In addition to the cash proceeds received, we were assigned additional working interests in certain producing properties. We recorded an additional $4,164,000 gain representing the estimated fair market value of those interests on the effective date of the settlement.

Income tax expense (benefit) during the three months ended March 31, 2011 and 2010 totaled $560 and ($3,891,000), respectively. We typically 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.

As a result of the ceiling test write-downs recognized, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $2,253,000 and $3,195,000 as of March 31, 2011 and December 31, 2010, respectively. Our effective tax rate in 2011 will be impacted by adjustments to the valuation allowance.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, second lien term credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At March 31, 2011, we had a working capital surplus of $57.8 million compared to a surplus of $59.1 million at December 31, 2010.

Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas 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 oil and natural gas 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. Lower prices and reduced cash flow may also make it difficult to incur debt, including under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. See “Source of Capital: Debt” below. Our ability to comply with the covenants in our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as oil and natural gas prices.

Source of Capital: Operations

Net cash flow from operations decreased from $52,708,000 in the quarter ended March 31, 2010 to $18,259,000 during the 2011 period. The decrease in operating cash flow during 2011 as compared to 2010 was primarily attributable to cash received during the first quarter of 2010 in connection with a legal settlement, the increase in our joint interest billing receivables, which is related to the increase in drilling activity, and the impact of lower natural gas prices in the first quarter of 2011.

Source of Capital: Debt

On August 19, 2010, we issued $150 million in principal amount of 10% Senior Notes due 2017 (the “Notes”) in a public offering. The net proceeds of the offering, together with cash on hand, were used to fund our tender offer and consent solicitation and redemption of our 10⅜% Senior Notes due 2012.

At March 31, 2011, the estimated fair value of the Notes was $159.4 million, based upon a market quote provided by an independent broker. 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 March 1 and September 1. At March 31, 2011, $1.3 million had been accrued in connection with the September 1, 2011 interest payment and we were in compliance with all of the covenants contained in the Notes.

We have a Credit Agreement (as amended, the “Credit Agreement”) with JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the available borrowing base as determined in accordance with the Credit Agreement. The Credit Agreement also allows us to use up to $25 million of the borrowing base for letters of credit. The credit facility matures on October 2, 2013. As of March 31, 2011 we had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement and availability of $100 million.

The borrowing base under the Credit Agreement is based upon the valuation of the reserves attributable to our oil and gas properties as of January 1 and July 1 of each year. The current borrowing base is $100 million effective April 1, 2011. The next borrowing base redetermination is scheduled to occur by September 30, 2011. We or the lenders may request two additional borrowing base redeterminations each year. Each time the borrowing base is to be re-determined, the administrative agent under the Credit Agreement will propose a new borrowing base as it deems appropriate in its sole discretion, which must be approved by all lenders if the borrowing base is to be increased, or by lenders holding two-thirds of the amounts outstanding under the Credit Agreement if the borrowing base remains the same or is reduced.

The Credit Agreement is secured by a first priority lien on substantially all of our assets, including a lien on all equipment and at least 85% of the aggregate total value of our oil and gas properties. Outstanding balances under the Credit Agreement bear interest at the alternate base rate (“ABR”) plus a margin (based on a sliding scale of 1.625% to 2.625% depending on borrowing base usage) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 2.5% to 3.5% depending on borrowing base usage). The alternate base rate is equal to the highest of (i) the JPMorgan Chase prime rate, (ii) the Federal Funds Effective Rate plus 0.5% or (iii) the adjusted LIBO rate plus 1%. For the purposes of the definition of alternative base rate only, the adjusted LIBO rate is equal to the rate at which dollar deposits of $5,000,000 with a one month maturity are offered by the principal London office of JPMorgan Chase Bank, N.A. in immediately available funds in the London interbank market. For all other purposes, the adjusted LIBO rate is equal to the rate at which Eurodollar deposits in the London interbank market for one, two, three or six months (as selected by us) are quoted, as adjusted for statutory reserve requirements for Eurocurrency liabilities. Outstanding letters of credit are charged a participation fee at a per annum rate equal to the margin applicable to Eurodollar loans, a fronting fee and customary administrative fees. In addition, we pay commitment fees of 0.5%.

We are subject to certain restrictive financial covenants under the Credit Agreement, including a maximum ratio of total debt to EBITDAX, determined on a rolling four quarter basis, of 3.0 to 1.0 and a minimum ratio of consolidated current assets to consolidated current liabilities of 1.0 to 1.0, all as defined in the Credit Agreement. The Credit Agreement also includes customary restrictions with respect to debt, liens, dividends, distributions and redemptions, investments, loans and advances, nature of business, international operations and foreign subsidiaries, leases, sale or discount of receivables, mergers or consolidations, sales of properties, transactions with affiliates, negative pledge agreements, gas imbalances and swap agreements. As of March 31, 2011, we were in compliance with all of the covenants contained in the Credit Agreement.

Source of Capital: Issuance of Securities

During October 2010, our shelf registration statement was declared effective, which allows us to publicly offer and sell up to $250 million of any combination of debt securities, shares of common and preferred stock, depositary shares and warrants. The registration statement does not provide any assurance that we will or could sell any such securities.

Source of Capital: Joint Ventures

In May 2010, we entered into a joint development agreement with WSGP, a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of our Woodford proved undeveloped reserves as well as the right to earn 50% of our undeveloped Woodford acreage position through a two phase drilling program. We received approximately $57 million in cash at closing, net of $2.6 million in transaction fees, and will receive an additional $14 million on November 30, 2011. If certain production performance metrics are achieved, we will receive an additional $14 million during the drilling program. Additionally, WSGP will fund a share of our future drilling costs under a long-term drilling program.

The additional capital provided by this agreement allows us to accelerate the pace of our development of the Woodford Shale and pursue opportunities in other basins. We have also entered into an Eagle Ford Shale Joint Acquistion Interim Agreement and a Marcellus Shale Joint Acquisition Interim Agreement with NextEra Energy Gas Producing, LLC (“NEGP”), a subsidiary of Nextera Energy Resources, LLC, whereby NEGP will have the option to participate as a 50% partner in the leasing and development of these shale plays.

Source of Capital: Divestitures

We do not budget property divestitures; however, we are continuously 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 liquidity to strengthen our balance sheet or capital to be reinvested in higher rate of return projects. We cannot assure you that we will be able to sell any of our assets in the future.

Use of Capital: Exploration and Development

Our 2011 capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $115 million and $125 million, of which $24.9 million was incurred during the first quarter of 2011. Because we operate the majority of our drilling activities, we expect to be able to control the timing of a substantial portion of our capital investments. As a result, we plan to fund our 2011 capital budget with cash flow from operations and the $14 million in additional proceeds expected to be received in November 2011 from the Woodford joint development agreement.

However, if commodity prices decline or if actual production or costs vary significantly from our expectations, our 2011 exploration and development activities could be reduced or could be financed through a combination of cash on hand or borrowings under the bank credit facility.

Use of Capital: Acquisitions

We do not budget acquisitions; however, we are continuously evaluating opportunities to expand our existing asset base or establish positions in new core areas. During 2010, we acquired acreage positions in the Niobrara Shale and the Eagle Ford Shale with development activities currently ongoing. We plan to actively pursue opportunities to expand these positions during 2011, as well as increase the scope of certain of our other assets and enter new areas. We expect to finance these activities, if consummated, through cash on hand or available borrowings under our bank credit facility. We may also utilize sales of equity or debt securities, sales of properties or assets or joint venture arrangements with industry partners, if necessary. We cannot assure you that such additional financings will be available on acceptable terms, if at all.

Disclosure Regarding Forward Looking Statements

This Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in and incorporated by reference into this Form 10-Q are forward-looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected. Among those risks, trends and uncertainties are our ability to find oil and natural gas reserves that are economically recoverable, the volatility of oil and natural gas prices and significantly depressed natural gas prices since the middle of 2008, the uncertain economic conditions in the United States and globally, the declines in the values of our properties that have resulted and may in the future result in additional 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 prospect development and property acquisitions or dispositions and in projecting future rates of production or future reserves, the timing of development expenditures and drilling of wells, hurricanes and other natural disasters, changes in laws and regulations as they relate to our operations, including our fracing operations in shale plays or our operations in the Gulf of Mexico, and the operating hazards attendant to the oil and gas business. In particular, careful consideration should be given to cautionary statements made in the various reports the Company has filed with the Securities and Exchange Commission. The Company undertakes no duty to update or revise these forward-looking statements.

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

Item 3.		QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We experience market risks primarily in two areas: commodity prices and interest rates. 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 2011, a 10% change in the prices we receive for our crude oil and natural gas production would have an approximate $12.3 million impact on our revenues.

We seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During the quarters ended March 31, 2011 and 2010, we received from the counterparties to our derivative instruments $100,000 and $1,531,000, respectively, in connection with net hedge settlements.

We are required to pay the difference between the floating price and the fixed price (when the floating price exceeds the fixed price) regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent us from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge.

Our Credit Agreement requires that the counterparties to our hedge contracts be lenders under the Credit Agreement or, if not a lender under the Credit Agreement, rated A/A2 or higher by S&P or Moody’s. Currently, the counterparties to our existing hedge contracts are lenders under the Credit Agreement. To the extent we enter into additional hedge contracts, we would expect that certain of the lenders under the Credit Agreement would serve as counterparties.

As of March 31, 2011, 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:
April-December 2011		Costless Collar		15,000 Mmbtu				$	4.17 – 4.90
Crude Oil:
April-December 2011		Costless Collar		500 Bbls				$	90.00 – 97.78

At March 31, 2011, we recognized a net liability of approximately $1.8 million related to the estimated fair value of these derivative instruments. Based on estimated future commodity prices as of March 31, 2011, we would realize a $1.1 million loss, net of taxes, during the next 12 months. These losses are expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

During April, 2011, we entered into the following gas contract, to be accounted for as a cash flow hedge:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

May — December 2011

Swap

10,000 Mmbtu

$

4.52

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.

Notwithstanding the foregoing, there can be no assurance that the Company’s disclosure controls and procedures will detect or uncover all failures of persons within the Company and its consolidated subsidiaries to disclose material information otherwise required to be set forth in the Company’s periodic reports. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.

Changes in Internal Control Over Financial Reporting

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

Oil and natural gas prices are volatile, and natural gas prices have been significantly depressed since the middle of 2008. An extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations and results of operations.

Our future financial condition, revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties depend primarily on the prices we receive for our oil and natural gas production. Our ability to maintain or increase our borrowing capacity and to obtain additional capital on attractive terms also substantially depends upon oil and natural gas prices. Prices for natural gas have been significantly depressed since the middle of 2008 and future oil and natural gas prices are subject to large fluctuations in response to a variety of factors beyond our control.

These factors include:

•

relatively minor changes in the supply of or the demand for oil and natural gas;

•

the condition of the United States and worldwide economies;

•

market uncertainty;

•

the level of consumer product demand;

•

weather conditions in the United States, such as hurricanes;

•

the actions of the Organization of Petroleum Exporting Countries;

•

domestic and foreign governmental regulation and taxes, including price controls adopted by the Federal Energy Regulatory Commission;

•

political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America;

•

the price and level of foreign imports of oil and natural gas; and

•

the price and availability of alternate fuel sources.

We cannot predict future oil and natural gas prices and such prices may decline further. An extended decline in oil and natural gas prices may adversely affect our financial condition, liquidity, ability to meet our financial obligations and results of operations. Lower prices have reduced and may further reduce the amount of oil and natural gas that we can produce economically and has required and may require us to record additional ceiling test write-downs and may cause our estimated proved reserves at December 31, 2011 to decline compared to our estimated proved reserves at December 31, 2010. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices. Our sales are not made pursuant to long-term fixed price contracts.

To attempt to reduce our price risk, we periodically enter into hedging transactions with respect to a portion of our expected future production. We cannot assure you that such transactions will reduce the risk or minimize the effect of any decline in oil or natural gas prices. Any substantial or extended decline in the prices of or demand for oil or natural gas would have a material adverse effect on our financial condition, liquidity, ability to meet our financial obligations 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, 2011, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $95 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 outstanding indebtedness, including 10% senior notes due 2017, which we refer to as our 10% 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 agreements governing such 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 and may limit our flexibility in operating our business;

•

we will need to use a substantial portion of our cash flows to pay interest on our debt, approximately $15 million per year for interest on our 10% notes alone, and to pay quarterly dividends, if declared by our Board of Directors, on our Series B Preferred Stock of approximately $5.1 million per year, 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 in the future may be at variable rates of interest, which, if interest rates increase, could result in higher interest expense;

•

we may 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 extended or further 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.

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% notes, and meet our other obligations. If we do not have enough cash to service our debt, we may be required to refinance all or part of our existing debt, including our 10% 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.

Lower oil and natural gas prices may cause us to record ceiling test write-downs, which could negatively impact our results of operations.

We use the full cost method of accounting to account for our oil and natural gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop oil and natural gas properties. Under full cost accounting rules, the net capitalized costs of oil and natural gas properties may not exceed a “full cost ceiling” which is based upon the present value of estimated future net cash flows from proved reserves, including the effect of hedges in place, discounted at 10%, plus the lower of cost or fair market value of unproved properties. If at the end of any fiscal period we determine that the net capitalized costs of oil and natural gas properties exceed the full cost ceiling, we must charge the amount of the excess to earnings in the period then ended. This is called a “ceiling test write-down.” This charge does not impact cash flow from operating activities, but does reduce our net income and stockholders’ equity. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

We review the net capitalized costs of our properties quarterly, using a single price based on the beginning of the month average of oil and natural gas prices for the prior 12 months. We also assess investments in unproved properties periodically to determine whether impairment has occurred. The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. As a result of the decline in commodity prices, we recognized a $5.9 million ceiling test write-down during the first quarter of 2011. We may experience further ceiling test write-downs or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.

Item 2.		UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

The following table sets forth certain information with respect to repurchases of our common stock during the quarter ended March 31, 2011.

														Maximum Number (or
										Total Number of				Approximate Dollar
										Shares Purchased as				Value) of Shares that
										Part of Publicly				May be Purchased
		Total Number of				Average Price				Announced				Under the Plans or
		Shares Purchased (1)				Paid Per Share				Plan or Program				Programs
January 1 - January 31, 2011			381			$	7.36				—				—
February 1 - February 28, 2011			39,089				8.50				—				—
March 1 - March 31, 2011			33,584				8.10				—				—
Total			73,054			$	8.31				—				—

Item 3.		DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4.		(REMOVED AND RESERVED)

Item 5.		OTHER INFORMATION

NONE.

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.

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.