10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2011

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: 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 Road, Suite 6000

Lafayette, Louisiana 70508

(Address of principal executive offices) (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Stock, par value $.001 per share	New York Stock Exchange
Preferred Stock Purchase Rights	New York Stock Exchange

Securities registered pursuant to Section 12 (g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

¨   Yes     x  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

¨   Yes     x   No

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.

x   Yes     ¨  No

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).

x  Yes     ¨   No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ¨

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. (Check one):

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

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

¨  Yes    x   No

The aggregate market value of the voting common equity held by non-affiliates of the registrant was approximately $302,000,000 as of June 30, 2011 (for purposes of this disclosure, the registrant assumed its directors, executive officers and beneficial owners of 5% or more of the registrant’s common stock were affiliates).

As of February 23, 2012, the registrant had outstanding 64,096,164 shares of Common Stock, par value $.001 per share.

Document incorporated by reference: portions of the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held on May 9, 2012, which are incorporated by reference into Part III of this Form 10-K.

	Page No.
PART I
Items 1 and 2 Business and Properties		3
Item 1A. Risk Factors		16
Item 1B. Unresolved Staff Comments		28
Item 3. Legal Proceedings		28
Item 4. Mine Safety Disclosures		28
PART II
Item  5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6. Selected Financial Data		31
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 7A. Quantitative and Qualitative Disclosure About Market Risk		40
Item 8. Financial Statements and Supplementary Data		41
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		41
Item 9A. Controls and Procedures		41
Item 9B. Other Information		44
PART III
Item 10. Directors, Executive Officers and Corporate Governance		44
Item 11. Executive Compensation		44
Item  12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		44
Item 13. Certain Relationships and Related Transactions, and Director Independence		44
Item 14. Principal Accounting Fees and Services		44
PART IV
Item 15. Exhibits, Financial Statement Schedules		44
Index to Financial Statements		F-1

1

This Form 10-K 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-K are forward looking statements. These forward-looking statements are subject to certain risks, trends and uncertainties that could cause actual results to differ materially from those projected.

Among those risks, trends and uncertainties are:

• the volatility of oil and natural gas prices and depressed natural gas prices since the middle of 2008;

• our indebtedness and the significant amount of cash required to service our indebtedness;

• the recent financial crisis and continuing uncertain economic conditions in the United States and globally;

• ceiling test write-downs resulting, and that could result in the future, from lower oil and natural gas prices;

• our ability to obtain adequate financing when the need arises to execute our long-term strategy and to fund our planned capital expenditures;

• limits on our growth and our ability to finance our operations, fund our capital needs and respond to changing conditions imposed by restrictive debt covenants;

• our ability to find, develop, produce and acquire additional oil and natural gas reserves that are economically recoverable;

• approximately one third of our production being exposed to the additional risk of severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise;

• losses and liabilities from uninsured or underinsured drilling and operating activities;

• our ability to market our oil and natural gas production;

• changes in laws and governmental regulations, increases in insurance costs or decreases in insurance availability, and delays in our offshore exploration and drilling activities that may result from the April 22, 2010 sinking of the Deepwater Horizon and subsequent oil spill in the Gulf of Mexico;

• competition from larger oil and natural gas companies;

• the likelihood that our actual production, revenues and expenditures related to our reserves will differ from our estimates of proved reserves;

• our ability to identify, execute or efficiently integrate future acquisitions;

• losses or limits on potential gains resulting from hedging production;

• the loss of key management or technical personnel;

• the operating hazards attendant to the oil and gas business;

• governmental regulation relating to hydraulic fracturing and environmental compliance costs and environmental liabilities;

• the operation and profitability of non-operated properties; and

• potential conflicts of interest resulting from ownership of working interests and overriding royalty interests in certain of our properties by our officers and directors.

Although we believe that the expectations reflected in these forward looking statements are reasonable, we cannot assure you that such expectations reflected in these forward looking statements will prove to have been correct.

2

When used in this Form 10-K, 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,” “Risk Factors” and elsewhere in this Form 10-K.

You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. You should be aware that the occurrence of any of the events described under “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Risk Factors” and elsewhere in this Form 10-K could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common stock could decline, and you could lose all or part of your investment.

We cannot guarantee any future results, levels of activity, performance or achievements. Except as required by law, we undertake no obligation to update any of the forward-looking statements in this Form 10-K after the date of this Form 10-K.

As used in this Form 10-K, the words “we,” “our,” “us,” “PetroQuest” and the “Company” refer to PetroQuest Energy, Inc., its predecessors and subsidiaries, except as otherwise specified. We have provided definitions for some of the oil and natural gas industry terms used in this Form 10-K in “Glossary of Certain Oil and Natural Gas Terms” beginning on page 48.

PART I

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

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 2011, we have invested approximately $891 million into growing our longer life assets. During the eight year period ended December 31, 2011, we have realized a 95% drilling success rate on 771 gross wells drilled. Comparing 2011 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 212% and estimated proved reserves by 219%. At December 31, 2011, 91% of our estimated proved reserves and 66% of our 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. 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 and 2011, we refocused on the key elements of our business strategy with the goal of growing reserves and production in a fiscally prudent manner. In order to maintain our financial flexibility, we funded our 2011 capital expenditures budget with cash flow from operations, cash on hand and additional proceeds received under the Woodford joint development agreement (see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Source of Capital: Joint Ventures”). As a result of our increased investments during 2010 and 2011, our estimated proved reserves as of December 31, 2011 increased 38% from 2010. Production in the fourth quarter of 2011 was 1% higher than production in the fourth quarter of 2010.

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Business Strategy

Maintain Our Financial Flexibility. Because we operate approximately 77% of our total estimated proved reserves and manage the drilling and completion activities on an additional 9% of such reserves, we expect to be able to control the timing of a substantial portion of our capital investments. Our 2012 capital expenditures, which include capitalized interest and overhead, are expected to range between $90 million and $100 million, a 47% decrease from our capital expenditures during 2011. We expect to be able to actively manage our 2012 capital budget in the event commodity prices, or the health of the global financial markets, do not match our expectations. During 2012, we also plan to maintain our commodity hedging program and, as in during prior years, we may opportunistically dispose of non-core or mature assets to provide capital for higher potential exploration and development properties that fit our long-term growth strategy.

Pursue Balanced Growth and Portfolio Mix. We plan to pursue a risk-balanced approach to the growth and stability of our reserves, production, cash flows and earnings. Our goal is to strike a balance between lower risk development activities and higher risk and higher impact exploration activities. We plan to allocate our 2012 capital investments in a manner that continues to geographically and operationally diversify our asset base, while focusing on oil and natural gas liquids projects as the pricing for these products is presently expected to be more attractive than that of natural gas. Through our portfolio diversification efforts, at December 31, 2011, approximately 91% of our estimated proved reserves were located in longer life and lower risk basins in Oklahoma, Arkansas, Texas and Wyoming and 9% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. This compares to 87% and 77% of our estimated proved reserves located in longer life basins at December 31, 2010 and 2009, respectively. In terms of production diversification, during 2011, 66% of our production was derived from longer life basins versus 54% and 53% in 2010 and 2009, respectively. Our 2011 production was comprised of 81% natural gas, 11% oil and 8% natural gas liquids. In order to further balance our production profile in response to low natural gas prices, we plan to increase natural gas liquids production in 2012 to approximately 11% of our total production.

Target Underexploited Properties with Substantial Opportunity for Upside. We plan to maintain a rigorous prospect selection process that enables us to leverage our operating and technical experience in our core operating areas. During 2012, we intend to primarily target properties that provide us with exposure to oil or natural gas liquids reserves and production. In evaluating these targets, we seek properties that provide sufficient acreage for future exploration and development, as well as properties that may benefit from the latest exploration, drilling, completion and operating techniques to more economically find, produce and develop oil and gas reserves. During 2011, we established positions targeting the Mississippian Lime, a primarily oil focused play, located on the border of Oklahoma and Kansas.

Concentrate in Core Operating Areas and Build Scale. We plan to continue focusing on our operations in Oklahoma, Texas and the Gulf Coast Basin. Operating in concentrated areas helps us better control our overhead by enabling us to manage a greater amount of acreage with fewer employees and minimize incremental costs of increased drilling and production. We have substantial geological and reservoir data, operating experience and partner relationships in these regions. We believe that these factors, combined with the existing infrastructure and favorable geologic conditions with multiple known oil and gas producing reservoirs in these regions, will provide us with attractive investment opportunities.

Manage Our Risk Exposure. We plan to continue several strategies designed to mitigate our operating risks. We have adjusted the working interest we are willing to hold based on the risk level and cost exposure of each project. For example, we typically reduce our working interests in higher risk exploration projects while retaining greater working interests in lower risk development projects. Our partners often agree to pay a disproportionate share of drilling costs relative to their interests, allowing us to allocate our capital spending to maximize our return and reduce the inherent risk in exploration and development activities. We also strive to retain operating control of the majority of our properties to control costs and timing of expenditures and we expect to continue to actively hedge a portion of our future planned production to mitigate the impact of commodity price fluctuations and achieve more predictable cash flows.

2011 Financial and Operational Summary

During 2011, we invested $182.4 million in exploratory, development and acquisition activities. We drilled 95 gross exploratory wells and 23 gross development wells realizing an overall success rate of 99%. These activities were financed through our cash flow from operations, cash on hand and $28 million in additional proceeds received pursuant to the Woodford joint development agreement. During 2011, our production decreased 2% to 30.2 Bcfe as a result of naturally declining production at our Gulf Coast properties, which was largely offset by production increases resulting from our success in our Oklahoma and Texas drilling programs. Our estimated proved reserves at December 31, 2011 increased 38% from 2010 as discussed in greater detail below.

4

Woodford Joint Venture

During February 2012, we amended our Woodford Shale joint development agreement (“JDA”) to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry has been expanded to provide for development in both the Mississippian Lime and the Woodford Shale plays whereby we will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry totals approximately $93 million and will be subject to extensions in one-year intervals.

Oil and Gas Reserves

Our estimated proved reserves at December 31, 2011 increased 38% from 2010 totaling 1,395 MBbls of oil, 15,111 MMcfe of natural gas liquids (Ngls) and 241,926 MMcf of natural gas, with a pre-tax present value, discounted at 10%, of the estimated future net revenues based on average prices during 2011 (“PV-10”) of $341 million. At December 31, 2011, our standardized measure of discounted cash flows, which includes the estimated impact of future income taxes, totaled $303.9 million. Our standardized measure of discounted cash flows at December 31, 2011 was 29% higher than 2010 as we utilized prices of $101.42 per barrel of oil, $8.62 per Mcfe of Ngls and $3.34 per Mcf of natural gas (adjusted for field differentials), compared to $79.72 per barrel of oil, $7.00 per Mcfe of Ngls and $3.56 per Mcf of natural gas (adjusted for field differentials) at December 31, 2010. See the reconciliation of PV-10 to the standardized measure of discounted cash flows below.

Ryder Scott Company, L.P., a nationally recognized independent petroleum engineering firm, prepared the estimates of our proved reserves and future net cash flows (and present value thereof) attributable to such proved reserves at December 31, 2011. Our internal reservoir engineering staff is managed by an individual with 30 years of industry experience as a reservoir and production engineer, including nine years as a reservoir engineering manager with PetroQuest. This individual is responsible for overseeing the estimates prepared by Ryder Scott.

The following table sets forth certain information about our estimated proved reserves as of December 31, 2011.

		September 30,		September 30,		September 30,		September 30,
	Oil (MBbls)		NGL (Mmcfe)		Natural Gas (Mmcf)		Total Mmcfe*
Proved Developed		1,160		11,071		143,441		161,472
Proved Undeveloped		235		4,040		98,485		103,935
Total Proved		1,395		15,111		241,926		265,407

* Oil conversion to Mcfe at one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas

As of December 31, 2011, our proved undeveloped reserves (“PUDs”) totaled 103.9 Bcfe, a 55% increase from our PUD balance at December 31, 2010. This increase was due to positive drilling results and performance revisions primarily in the Woodford Shale totaling approximately 41.5 Bcfe. During 2011, we spent $4.5 million converting 3 Bcfe of PUDs at December 31, 2010 to proved developed at December 31, 2011. Following is an analysis of the change in our PUDs as of December 31, 2011:

		September 30,
	Mmcfe
PUD Balance at December 31, 2010		67,156
PUDs converted to proved developed		(2,957	)
PUDs added from revisions or extensions and discoveries		41,514
PUDs removed for 5 year rule		(1,778	)
PUD Balance at December 31, 2011		103,935

Approximately 84% of our total PUDs at December 31, 2011 were associated with the future development of our Oklahoma properties. We expect all of our PUDs at December 31, 2011 to be developed over the next five years. At December 31, 2011, we had no PUDs that had been booked for longer than five years. Estimated future costs related to the development of PUDs are expected to total $48 million in 2012, $44 million in 2013, $35 million in 2014, $15 million in 2015 and zero in 2016. However, because 95% of our PUDs at December 31, 2011 are comprised of natural gas, the specific timing of the development of PUDs over the next five years is highly dependent upon the prevailing price of natural gas.

5

The estimated cash flows from our proved reserves at December 31, 2011 were as follows:

		September 30,		September 30,		September 30,
	Proved Developed (M$)		Proved Undeveloped (M$)		Total Proved (M$)
Estimated pre-tax future net cash flows (1)	$	469,811	$	165,516	$	635,327
Discounted pre-tax future net cash flows (PV-10) (1)	$	294,139	$	47,234	$	341,373
Total standardized measure of discounted future net cash flows					$	303,881

(1) Estimated pre-tax future net cash flows and discounted pre-tax future net cash flows (PV-10) are non-GAAP measures because they exclude income tax effects. Management believes these non-GAAP measures are useful to investors as they are based on prices, costs and discount factors which are consistent from company to company, while the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. As a result, the Company believes that investors can use these non-GAAP measures as a basis for comparison of the relative size and value of the Company’s reserves to other companies. The Company also understands that securities analysts and rating agencies use these non-GAAP measures in similar ways. The following table reconciles undiscounted and discounted future net cash flows to standardized measure of discounted cash flows as of December 31, 2011:

		September 30,
	Total Proved (M$)
Estimated pre-tax future net cash flows	$	635,327
10% annual discount		(293,954	)
Discounted pre-tax future net cash flows		341,373
Future income taxes discounted at 10%		(37,492	)
Standardized measure of discounted future net cash flows	$	303,881

We have not filed any reports with other federal agencies that contain an estimate of total proved net oil and gas reserves.

Core Areas

The following table sets forth estimated proved reserves and annual production from each of our core areas (in Bcfe) for the years ended December 31, 2011 and 2010.

		September 30,		September 30,		September 30,		September 30,
	2011				2010
	Reserves		Production		Reserves		Production
Oklahoma		184.5		12.8		117.0		10.6
E. Texas		30.9		4.4		26.1		3.5
Gulf Coast Basin		24.7		10.2		25.6		14.4
Arkansas		22.6		2.5		23.6		2.5
Other		2.7		0.3		0.4		—
		265.4		30.2		192.7		31.0

Oklahoma

During late 2006, we began our initial drilling program to evaluate the Woodford Shale formation on a substantial portion of our Oklahoma acreage. During 2011, we continued our evaluation of the Woodford Shale as we drilled and participated in 36 gross wells, achieving a 100% success rate. In total, we invested $56.5 million during 2011 acquiring prospective Woodford Shale acreage and drilling and completing wells. In addition, during 2011 we utilized $27.4 million from our Woodford joint venture partner relative to a drilling carry and plan to continue utilizing the drilling carry during 2012 under the first and second phases our Woodford joint venture. Average daily production from our Oklahoma properties during 2011 totaled 35 MMcfe per day, a 21% increase from 2010 average daily production. We experienced positive performance revisions to our proved reserves, which when combined with reserves added from our 2011 drilling program, resulted in a 58% increase in our estimated proved reserves. We have allocated approximately 25% of our 2012 capital budget to operations in the Woodford Shale as we expect to operate the drilling of approximately 20 gross wells primarily targeting liquids rich gas.

As of December 31, 2011 we had invested $18.3 million to acquire approximately 28,000 net acres of Mississippian Lime acreage in northern Oklahoma and southern Kansas. We have allocated approximately 10% of our 2012 capital budget to explore this primarily oil focused trend. We plan to drill 12 to 15 gross Mississippian Lime wells in 2012, but could accelerate this development plan depending on the drilling results from the initial wells.

6

East Texas

During 2011, we invested $31.4 million in our East Texas properties as we drilled and participated in 10 gross wells, achieving a 90% success rate. Net production from our East Texas assets averaged 12 MMcfe per day during 2011, a 26% increase from 2010 average daily production and our estimated proved reserves increased 19% from 2010, primarily as a result of successful drilling in our Carthage field. We have allocated approximately 20% of our 2012 capital budget to drilling and completing six gross wells in our Carthage field.

Gulf Coast Basin

During 2011, we drilled five gross wells in the Gulf Coast Basin, achieving a 100% success rate. In total, we invested $31.1 million in this area. Production from this area decreased 29% from 2010 totaling 28.1 MMcfe per day in 2011. However, production from our largest discovery in 2011 in the Gulf Coast Basin, our La Cantera prospect, is expected to commence during March 2012. Our estimated proved reserves in this area declined 4% from 2010 primarily as a result of natural production declines, offset in part by the proved reserves associated with the 2011 drilling program. We have allocated approximately 18% of our 2012 capital budget to various drilling and maintenance projects in the Gulf Coast Basin, including a delineation well to our La Cantera discovery.

Arkansas

During 2011, we participated in 58 gross wells in the Fayetteville Shale, all of which were successful. In total, we invested $2.7 million in Arkansas during 2011. Production during 2011 remained at 6.8 MMcfe per day while our estimated proved reserves decreased by approximately 4% during 2011. As a result of low natural gas prices, we have allocated less than 1% of our 2012 capital budget to participating in third-party operated Fayetteville Shale wells. We plan to evaluate divestment opportunities for these assets during 2012.

Markets and Customers

We sell our oil and natural gas production under fixed or floating market contracts. Customers purchase all of our oil and natural gas production at current market prices. The terms of the arrangements generally require customers to pay us within 30 days after the production month ends. As a result, if the customers were to default on their payment obligations to us, near-term earnings and cash flows would be adversely affected. However, due to the availability of other markets and pipeline connections, we do not believe that the loss of these customers or any other single customer would adversely affect our ability to market production. Our ability to market oil and natural gas from our wells depends upon numerous factors beyond our control, including:

• the extent of domestic production and imports of oil and natural gas;

• the proximity of the natural gas production to pipelines;

• the availability of capacity in such pipelines;

• the demand for oil and natural gas by utilities and other end users;

• the availability of alternative fuel sources;

• the effects of inclement weather;

• state and federal regulation of oil and natural gas production; and

• federal regulation of gas sold or transported in interstate commerce.

We cannot assure you that we will be able to market all of the oil or natural gas we produce or that favorable prices can be obtained for the oil and natural gas we produce.

A portion of the production that we operate in Oklahoma is committed to a firm transportation agreement. Under the terms of the agreement we must deliver 9.1 Bcf of natural gas per year through October 31, 2013. Based upon our current proved reserves and on the significant capital spending that we intend to allocate to this area, we expect that this commitment will be met.

In view of the many uncertainties affecting the supply and demand for oil, natural gas and refined petroleum products, we are unable to predict future oil and natural gas prices and demand or the overall effect such prices and demand will have on the Company. During 2011, one customer accounted for 20%, one accounted for 18%, one accounted for 15% and one accounted for 11% of our oil

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and natural gas revenue. During 2010, one customer accounted for 19%, two accounted for 17% each and one accounted for 10% of our oil and natural gas revenue. During 2009, two customers accounted for 17% each, one accounted for 13% and one accounted for 12% of our oil and natural gas revenue. These percentages do not consider the effects of commodity hedges. We do not believe that the loss of any of our oil or natural gas purchasers would have a material adverse effect on our operations due to the availability of other purchasers.

Production, Pricing and Production Cost Data

The following table sets forth our production, pricing and production cost data during the periods indicated. Only one core area, Oklahoma, which includes primarily Woodford Shale reserves, represented greater than 15% of our total estimated proved reserves.

		September 30,		September 30,		September 30,
	Year Ended December 31,
	2011		2010		2009
Production:
Oil (Bbls):
Oklahoma		145		71		502
Other		571,951		663,231		599,622
Total Oil (Bbls)		572,096		663,302		600,124
Gas (Mcf):
Oklahoma		12,736,622		10,577,414		10,579,524
Other		11,726,311		13,924,126		17,485,746
Total Gas (Mcf)		24,462,933		24,501,540		28,065,270
NGL (Mcfe):
Oklahoma		553		683		450
Other		2,287,293		2,469,188		2,532,372
Total NGL (Mcfe)		2,287,846		2,469,871		2,532,822
Total Production (Mcfe):
Oklahoma		12,738,045		10,578,523		10,582,986
Other		17,445,310		20,372,700		23,615,850
Total Production (Mcfe)		30,183,355		30,951,223		34,198,836
Average sales prices (1):
Oil (per Bbl):
Oklahoma	$	89.61	$	69.62	$	52.13
Other	$	105.33	$	79.48	$	59.31
Total Oil (per Bbl)	$	105.33	$	79.47	$	59.31
Gas (per Mcf)
Oklahoma	$	2.42	$	2.80	$	2.27
Other	$	3.86	$	4.31	$	3.74
Total Gas (per Mcf)	$	3.11	$	3.66	$	3.19
NGL (per Mcfe)
Oklahoma	$	5.15	$	3.79	$	4.10
Other	$	9.51	$	7.78	$	5.38
Total NGL (per Mcfe)	$	9.51	$	7.78	$	5.38
Total Per Mcfe:
Oklahoma	$	2.42	$	2.80	$	2.27
Other	$	7.29	$	6.47	$	4.86
Total Per Mcfe	$	5.24	$	5.22	$	4.06
Average Production Cost per Mcfe (2):
Oklahoma	$	0.76	$	0.71	$	0.53
Other	$	1.65	$	1.55	$	1.39
Total Average Production Cost per Mcfe	$	1.28	$	1.26	$	1.13

(1) Does not include the effect of hedges.

(2) Production costs do not include production taxes.

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Oil and Gas Drilling Activity

The following table sets forth the wells drilled and completed by us during the periods indicated. All wells were drilled in the continental United States.

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
	2011				2010				2009
	Gross		Net		Gross		Net		Gross		Net
Exploration:
Productive		94		18.15		82		9.55		64		5.84
Non-productive		1		0.50		3		0.76		2		0.48
Total		95		18.65		85		10.31		66		6.32
Development:
Productive		23		1.33		17		1.50		16		1.70
Non-productive		—		—		—		—		—		—
Total		23		1.33		17		1.50		16		1.70

In 2011, 35 gross (9.94 net) exploratory and one gross (.05 net) development wells were drilled in the Woodford Shale. In 2010, 19 gross (7.32 net) exploratory and 1 gross (.81 net) development wells were drilled in the Woodford Shale. In 2009, 13 gross (2.56 net) exploratory and two gross (.93 net) development wells were drilled in the Woodford Shale. All of these wells were productive.

We owned working interests in 34 gross (22 net) producing oil wells and 1,082 gross (292 net) producing gas wells at December 31, 2011. Of the 1,116 gross productive wells at December 31, 2011, three had dual completions. At December 31, 2011, we had 58 gross (10 net) wells in progress primarily in Arkansas and Oklahoma.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2011:

		September 30,		September 30,		September 30,		September 30,
	Leasehold Acreage
	Developed				Undeveloped
	Gross		Net		Gross		Net
Alabama		—		—		222		145
Arkansas		23,378		6,729		6,629		2,120
Kansas		—		—		4,091		4,091
Louisiana		6,043		2,330		6,705		3,852
Mississippi		721		721		—		—
Oklahoma		88,325		41,876		61,725		37,626
Texas		41,926		22,710		8,090		3,944
Wyoming		2,720		680		9,203		2,301
Federal Waters		43,407		25,470		7,343		7,343
Total		206,520		100,516		104,008		61,422

Leases covering 8% of our net undeveloped acreage are scheduled to expire in 2012, 11% in 2013, 23% in 2014 and 58% thereafter. Of the acreage subject to leases scheduled to expire during 2012, less than 5% relates to undeveloped acreage in Texas, Louisiana and Alabama where we do not anticipate any further drilling. We expect to hold the majority of the remaining acreage scheduled to expire in 2012 through drilling.

Title to Properties

We believe that the title to our oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. Our properties are typically subject, in one degree or another, to one or more of the following:

• royalties and other burdens and obligations, express or implied, under oil and gas leases;

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• overriding royalties and other burdens created by us or our predecessors in title;

• a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles;

• back-ins and reversionary interests existing under purchase agreements and leasehold assignments;

• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; pooling, unitization and communitization agreements, declarations and orders; and

• easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect our rights to production revenues, they have been taken into account in calculating our net revenue interests and in estimating the size and value of our reserves. We believe that the burdens and obligations affecting our properties are conventional in the industry for properties of the kind that we own.

Federal Regulations

Sales and Transportation of Natural Gas. Historically, the transportation and sales for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”) and Federal Energy Regulatory Commission (“FERC”) regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act deregulated the price for all “first sales” of natural gas. Thus, all of our sales of gas may be made at market prices, subject to applicable contract provisions. Sales of natural gas are affected by the availability, terms and cost of pipeline transportation. Since 1985, the FERC has implemented regulations intended to make natural gas transportation more accessible to gas buyers and sellers on an open-access, non-discriminatory basis. We cannot predict what further action the FERC will take on these matters. Some of the FERC’s more recent proposals may, however, adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that we will be affected by any action taken materially differently than other natural gas producers, gatherers and marketers with which we compete.

The Outer Continental Shelf Lands Act (the “OCSLA”), which was administered by the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) and, after October 1, 2011, its successors, the Bureau of Ocean Energy Management (the “BOEM”) and the Bureau of Safety and Environmental Enforcement (the “BSEE”), and the FERC, requires that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its NGA jurisdiction. Therefore, we do not believe that any FERC, BOEM or BSEE action taken under OCSLA will affect us in a way that materially differs from the way it affects other natural gas producers, gatherers and marketers with which we compete.

Our natural gas sales are generally made at the prevailing market price at the time of sale. Therefore, even though we sell significant volumes to major purchasers, we believe that other purchasers would be willing to buy our natural gas at comparable market prices.

Natural gas continues to supply a significant portion of North America’s energy needs and we believe the importance of natural gas in meeting this energy need will continue. The impact of the ongoing economic downturn on natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

On August 8, 2005, the Energy Policy Act of 2005 (the “2005 EPA”) was signed into law. This comprehensive act contains many provisions that will encourage oil and gas exploration and development in the U.S. The 2005 EPA directs the FERC, BOEM and other federal agencies to issue regulations that will further the goals set out in the 2005 EPA. The 2005 EPA amends the NGA to make it unlawful for “any entity”, including otherwise non-jurisdictional producers such as us, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by the FERC, in contravention of rules prescribed by the FERC. On January 20, 2006, the FERC issued rules implementing this provision. The rules make it unlawful in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction. It therefore reflects a significant expansion of the FERC’s enforcement authority. We do not anticipate we will be affected any differently than other producers of natural gas.

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In 2007, the FERC issued a final rule on annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing (“Order 704”). Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. The monitoring and reporting required by these rules have increased our administrative costs. We do not anticipate that we will be affected any differently than other producers of natural gas.

Sales and Transportation of Crude Oil. Our sales of crude oil, condensate and natural gas liquids are not currently regulated, and are subject to applicable contract provisions made at market prices. In a number of instances, however, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to the FERC’s jurisdiction under the Interstate Commerce Act. In other instances, the ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes.

The regulation of pipelines that transport crude oil, condensate and natural gas liquids is generally more light-handed than the FERC's regulation of gas pipelines under the NGA. Regulated pipelines that transport crude oil, condensate, and natural gas liquids are subject to common carrier obligations that generally ensure non-discriminatory access. With respect to interstate pipeline transportation subject to regulation of the FERC under the Interstate Commerce Act, rates generally must be cost-based, although market-based rates or negotiated settlement rates are permitted in certain circumstances. Pursuant to FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under this indexing methodology, pipeline rates are subject to changes in the Producer Price Index for Finished Goods, minus one percent. A pipeline can seek to increase its rates above index levels provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can seek to charge market based rates if it establishes that it lacks significant market power. In addition, a pipeline can establish rates pursuant to settlement if agreed upon by all current shippers. A pipeline can seek to establish initial rates for new services through a cost-of-service proceeding, a market-based rate proceeding, or through an agreement between the pipeline and at least one shipper not affiliated with the pipeline.

Federal Leases. We maintain operations located on federal oil and natural gas leases, which are administered by the BOEMRE, BOEM or BSEE, pursuant to the OCSLA. The BOEMRE and its successors, the BOEM and the BSEE, regulate offshore operations, including engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Gulf of Mexico shelf, and removal of facilities.

On January 19, 2011, the U.S. Department of the Interior announced that it would divide offshore oil and gas responsibilities among three separate agencies, with the reorganization to be completed in 2011. The Department of the Interior first created the Office of Natural Resources Revenue to manage revenue collection on October 1, 2010. Effective October 1, 2011, the remaining functions of BOEMRE were split into two federal bureaus, the BOEM, which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, NEPA analysis and environmental studies, and the BSEE, which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we are required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. At this time, we cannot predict the impact that this reorganization, or future regulations of enforcement actions taken by the new agencies, may have on our operations. Our federal oil and natural gas leases are awarded based on competitive bidding and contain relatively standardized terms. These leases require compliance with detailed BOEMRE regulations and orders that are subject to interpretation and change by the BOEM or BSEE. The BOEMRE has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities, structures and pipelines, and the BOEM or the BSEE may in the future amend these regulations. Please read “Risk Factors” beginning on page 16 for more information on new regulations.

To cover the various obligations of lessees on the Outer Continental Shelf (the “OCS”), the BOEMRE and its successors generally require that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be satisfied. The cost of these bonds or assurances can be substantial and there is no assurance that they can be obtained in all cases. We are currently exempt from supplemental bonding requirements. As many regulations are being reviewed, we may be subject to supplemental bonding requirements in the future. Under some circumstances, the BOEM may require any of our operations on federal leases to be suspended or terminated. Any such suspension or termination could materially adversely affect our financial condition and results of operations.

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Hurricanes in the Gulf of Mexico can have a significant impact on oil and gas operations on the OCS. The effects from past hurricanes have included structural damage to pipelines, wells, fixed production facilities, semi-submersibles and jack-up drilling rigs. The BOEMRE has been in the past, and the BOEM and the BSEE will be in the future, concerned about the loss of these facilities and rigs as well as the potential for catastrophic damage to key infrastructure and the resultant pollution from future storms. In an effort to reduce the potential for future damage, the BOEMRE has periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. It is possible that similar, if not more stringent, requirements will be issued by the BOEM or the BSEE for future hurricane seasons. New requirements, if any, could increase our operating costs to future storms.

The Office of Natural Resources Revenue (the “ONRR”) in the U.S. Department of the Interior administers the collection of royalties under the terms of the OCSLA and the oil and natural gas leases issued thereunder. The amount of royalties due is based upon the terms of the oil and natural gas leases as well as the regulations promulgated by the ONRR.

Federal, State or American Indian Leases. In the event we conduct operations on federal, state or American Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (“BLM”) or BOEM or other appropriate federal or state agencies.

The Mineral Leasing Act of 1920 (“Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. We own interests in numerous federal onshore oil and gas leases. It is possible that holders of our equity interests may be citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act.

State Regulations

Most states regulate the production and sale of oil and natural gas, including:

• requirements for obtaining drilling permits;

• the method of developing new fields;

• the spacing and operation of wells;

• the prevention of waste of oil and gas resources; and

• the plugging and abandonment of wells.

The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both.

We may enter into agreements relating to the construction or operation of a pipeline system for the transportation of natural gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state’s administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates that we could charge for gas, the transportation of gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority.

Legislative Proposals

In the past, Congress has been very active in the area of natural gas regulation. New legislative proposals in Congress and the various state legislatures, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on our operations.

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Environmental Regulations

General. Our activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, we believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, regulations and rules regulating the release of materials in the environment or otherwise relating to the protection of human health, safety and the environment will not have a material effect upon our capital expenditures, earnings or competitive position with respect to our existing assets and operations. We cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from our operations could have on our activities.

Our activities with respect to exploration and production of oil and natural gas, including the drilling of wells and the operation and construction of pipelines, plants and other facilities for extracting, transporting, processing, treating or storing natural gas and other petroleum products, are subject to stringent environmental regulation by state and federal authorities, including the United States Environmental Protection Agency (the “USEPA”). Such regulation can increase the cost of planning, designing, installation and operation of such facilities. Although we believe that compliance with environmental regulations will not have a material adverse effect on us, risks of substantial costs and liabilities are inherent in oil and gas production operations, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover it is possible that other developments, such as spills or other unanticipated releases, stricter environmental laws and regulations, and claims for damages to property or persons resulting from oil and gas production, would result in substantial costs and liabilities to us.

Solid and Hazardous Waste. We own or lease numerous properties that have been used for production of oil and gas for many years. Although we have utilized operating and disposal practices standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under these properties. In addition, many of these properties have been operated by third parties that controlled the treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination.

We generate wastes, including hazardous wastes, which are subject to regulation under the federal Resource Conservation and Recovery Act (“RCRA”) and state statutes. The USEPA has limited the disposal options for certain hazardous wastes. Furthermore, it is possible that certain wastes generated by our oil and gas operations which are currently exempt from regulation as “hazardous wastes” may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly disposal requirements.

Naturally Occurring Radioactive Materials (“NORM”) are radioactive materials which precipitate on production equipment during oil and natural gas extraction or processing. NORM wastes are regulated under the RCRA framework, but primary responsibility for NORM regulation has been a state function. Standards have been developed for worker protection; treatment, storage and disposal of NORM waste; management of waste piles, containers and tanks; and limitations upon the release of NORM-contaminated land for unrestricted use. We believe that our operations are in material compliance with all applicable NORM standards.

Superfund. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on certain persons with respect to the release or threatened release of a “hazardous substance” into the environment. These persons include the owner and operator of a site and persons that disposed or arranged for the disposal of hazardous substances at a site. CERCLA also authorizes the USEPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible persons the costs of such action. State statutes impose similar liability.

Under CERCLA, the term “hazardous substance” does not include “petroleum, including crude oil or any fraction thereof,” unless specifically listed or designated and the term does not include natural gas, Ngls, liquefied natural gas, or synthetic gas usable for fuel. While this “petroleum exclusion” lessens the significance of CERCLA to our operations, we may generate waste that may fall within CERCLA’s definition of a “hazardous substance” in the course of our ordinary operations. We also currently own or lease properties that for many years have been used for the exploration and production of oil and natural gas. Although we and, to our knowledge, our predecessors have used operating and disposal practices that were standard in the industry at the time, “hazardous substances” may have been disposed or released on, under or from the properties owned or leased by us or on, under or from other locations where these wastes have been taken for disposal. At this time, we do not believe that we have any liability associated with any Superfund site, and we have not been notified of any claim, liability or damages under CERCLA.

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Oil Pollution Act. The Oil Pollution Act of 1990 (the “OPA”) and regulations thereunder impose a variety of regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A “responsible party” includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.

The OPA establishes a liability limit for onshore facilities of $350 million and for offshore facilities of all removal costs plus $75 million, and lesser limits for some vessels depending upon their size. The regulations promulgated under OPA impose proof of financial responsibility requirements that can be satisfied through insurance, guarantee, indemnity, surety bond, letter of credit, qualification as a self-insurer, or a combination thereof. The amount of financial responsibility required depends upon a variety of factors including the type of facility or vessel, its size, storage capacity, oil throughput, proximity to sensitive areas, type of oil handled, history of discharges and other factors. We carry insurance coverage to meet these obligations, which we believe is customary for comparable companies in our industry. A failure to comply with OPA’s requirements or inadequate cooperation during a spill response action may subject a responsible party to civil or criminal enforcement actions.

As a result of the explosion and sinking of the Deepwater Horizon drilling rig in the Gulf of Mexico in April 2010, the U.S. Congress has considered legislation that could increase our obligations and potential liability under the OPA, including by eliminating the current cap on liability for damages and by increasing minimum levels of financial responsibility. It is uncertain whether, and in what form, such legislation will ultimately be adopted. We are not aware of the occurrence of any action or event that would subject us to liability under OPA, and we believe that compliance with OPA’s financial responsibility and other operating requirements will not have a material adverse effect on us.

Discharges. The Clean Water Act (“CWA”) regulates the discharge of pollutants to waters of the United States, including wetlands, and requires a permit for the discharge of pollutants, including petroleum, to such waters. Certain facilities that store or otherwise handle oil are required to prepare and implement Spill Prevention, Control and Countermeasure Plans and Facility Response Plans relating to the possible discharge of oil to surface waters. We are required to prepare and comply with such plans and to obtain and comply with discharge permits. We believe we are in substantial compliance with these requirements and that any noncompliance would not have a material adverse effect on us. The CWA also prohibits spills of oil and hazardous substances to waters of the United States in excess of levels set by regulations and imposes liability in the event of a spill. State laws further provide civil and criminal penalties and liabilities for spills to both surface and groundwaters and require permits that set limits on discharges to such waters.

Moreover, our exploration and production activities may involve the use of hydraulic fracturing techniques to stimulate wells and maximize natural gas production. Citing concerns over the potential for hydraulic fracturing to impact drinking water, human health and the environment, and in response to a congressional mandate, the USEPA has commissioned a study to identify potential risks associated with hydraulic fracturing. The USEPA finalized its plan for the study in November 2011. The initial study results are expected to be available by late 2012 and the final report will be delivered in 2014. Additionally, the Bureau of Land Management (“BLM”) is preparing a proposal for rules that would not only require operators on public lands to disclose the contents of fracturing fluids, but would also require disclosure of the source of water to be used in fracturing and plans for disposal of flowback, as well as impose well integrity requirements. Depending on the results of the USEPA study and other developments related to the impact of hydraulic fracturing, our drilling activities could be subjected to new or enhanced federal, state and/or local regulatory requirements governing hydraulic fracturing.

Air Emissions. Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may be resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could impose civil and criminal liability for non-compliance. An agency could require us to forego construction or operation of certain air emission sources. We believe that we are in substantial compliance with air pollution control requirements and that, if a particular permit application were denied, we would have enough permitted or permittable capacity to continue our operations without a material adverse effect on any particular producing field.

According to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases (“GHG”) may be contributing to global warming of the earth’s atmosphere and to global climate change. In response to the scientific studies, legislative and regulatory initiatives have been underway to limit GHG emissions. The U.S. Supreme Court determined that GHG emissions fall within the federal Clean Air Act (“CAA”) definition of an “air pollutant”, and in response the USEPA promulgated an endangerment finding paving the way for regulation of GHG emissions under the CAA. The USEPA has also promulgated rules requiring large sources to report their GHG emissions. Sources subject to these reporting requirements include on- and offshore petroleum and natural gas production and onshore natural gas processing and distribution facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year in aggregate emissions from all site sources. We are not subject to greenhouse gas reporting requirements. In addition, the USEPA promulgated rules that significantly increase the GHG emission threshold that would identify major stationary sources of GHG subject to CAA permitting programs. As currently

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written and based on current Company operations, we are not subject to federal GHG permitting requirements. Regulation of GHG emissions is new and highly controversial, and further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the Company. Further, apart from these developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase the Company’s litigation risk for such claims. Due to the uncertainties surrounding the regulation of and other risks associated with GHG emissions, the Company cannot predict the financial impact of related developments on the Company.

USEPA has proposed new rules to address air emissions from the oil and gas industry, among other things by requiring installation of equipment to capture certain gases released from new or refitted wells. The proposals would revise New Source Performance Standards for volatile organic compounds and sulfur dioxide, impose controls on toxics emitted at oil and gas wells, and limit fugitive emissions from associated production, storage and transport equipment. The Company is currently evaluating the impact, if any, from the proposed rules.

Coastal Coordination. There are various federal and state programs that regulate the conservation and development of coastal resources. The federal Coastal Zone Management Act (“CZMA”) was passed to preserve and, where possible, restore the natural resources of the Nation’s coastal zone. The CZMA provides for federal grants for state management programs that regulate land use, water use and coastal development.

The Louisiana Coastal Zone Management Program (“LCZMP”) was established to protect, develop and, where feasible, restore and enhance coastal resources of the state. Under the LCZMP, coastal use permits are required for certain activities, even if the activity only partially infringes on the coastal zone. Among other things, projects involving use of state lands and water bottoms, dredge or fill activities that intersect with more than one body of water, mineral activities, including the exploration and production of oil and gas, and pipelines for the gathering, transportation or transmission of oil, gas and other minerals require such permits. General permits, which entail a reduced administrative burden, are available for a number of routine oil and gas activities. The LCZMP and its requirement to obtain coastal use permits may result in additional permitting requirements and associated project schedule constraints.

The Texas Coastal Coordination Act (“CCA”) provides for coordination among local and state authorities to protect coastal resources through regulating land use, water, and coastal development and establishes the Texas Coastal Management Program (“CMP”) that applies in the nineteen counties that border the Gulf of Mexico and its tidal bays. The CCA provides for the review of state and federal agency rules and agency actions for consistency with the goals and policies of the Coastal Management Plan. This review may affect agency permitting and may add a further regulatory layer to some of our projects.

OSHA. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendments and Reauthorization Act and similar state statutes require us to organize and/or disclose information about hazardous materials used or produced in our operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens.

Management believes that we are in substantial compliance with current applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us.

Corporate Offices

Our headquarters are located in Lafayette, Louisiana, in approximately 48,400 square feet of leased space, with exploration offices in Houston, Texas and Tulsa, Oklahoma, in approximately 5,500 square feet and 11,800 square feet, respectively, of leased space. We also maintain owned or leased field offices in the areas of the major fields in which we operate properties or have a significant interest. Replacement of any of our leased offices would not result in material expenditures by us as alternative locations to our leased space are anticipated to be readily available.

Employees

We had 111 full-time employees as of February 20, 2012. In addition to our full time employees, we utilize the services of independent contractors to perform certain functions. We believe that our relationships with our employees are satisfactory. None of our employees are covered by a collective bargaining agreement.

Available Information

We make available free of charge, or through the “Investors—SEC Documents” section of our website at www.petroquest.com, access to our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as reasonably practicable after such material is filed, or furnished to the Securities and Exchange Commission. Our Code of Business Conduct and Ethics, our Corporate Governance Guidelines and the charters of our Audit, Compensation and Nominating and Corporate Governance Committees are also available through the “Investors—Corporate Governance” section of our website or in print to any stockholder who requests them.

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ITEM 1A. RISK FACTORS

Risks Related to Our Business, Industry and Strategy

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. 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. 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 December 31, 2011, the aggregate amount of our outstanding indebtedness, net of cash on hand, was $127.7 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;

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• 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.

To service our indebtedness, we will require a significant amount of cash. Our ability to generate cash depends on many factors beyond our control, and any failure to meet our debt obligations could harm our business, financial condition and results of operations.

Our ability to make payments on and to refinance our indebtedness, including our 10% notes, and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. To a certain extent, this is subject to general economic, financial, competitive, legislative and regulatory conditions and other factors that are beyond our control, including the prices that we receive for our oil and natural gas production.

We cannot assure you that our business will generate sufficient cash flow from operations or that future borrowings will be available to us under our bank credit facility in an amount sufficient to enable us to pay principal and interest on our indebtedness, including our 10% notes, or to fund our other liquidity needs. If our cash flow and capital resources are insufficient to fund our debt obligations, we may be forced to reduce our planned capital expenditures, sell assets, seek additional equity or debt capital or restructure our debt. We cannot assure you that any of these remedies could, if necessary, be affected on commercially reasonable terms, or at all. In addition, any failure to make scheduled payments of interest and principal on our outstanding indebtedness would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. Our cash flow and capital resources may be insufficient for payment of interest on and principal of our debt in the future, including payments on our 10% notes, and any such alternative measures may be unsuccessful or may not permit us to meet scheduled debt service obligations, which could cause us to default on our obligations and could impair our liquidity.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the United States mortgage market and a declining real estate market in the United States have contributed to increased economic uncertainty and diminished expectations for the global economy. These factors, combined with volatile prices of oil and natural gas, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad continues to deteriorate, demand for petroleum products could diminish, which could impact the price at which we can sell our oil, natural gas and natural gas liquids, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

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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. During 2009 and 2011, we recognized approximately $175 million in ceiling test write-downs as a result of the decline in commodity prices.

We review the net capitalized costs of our properties quarterly, using, effective for fiscal periods ending on or after December 31, 2009, 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. 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.

We may not be able to obtain adequate financing when the need arises to execute our long-term operating strategy.

Our ability to execute our long-term operating strategy is highly dependent on our having access to capital when the need arises. We historically have addressed our long-term liquidity needs through bank credit facilities, second lien term credit facilities, issuances of equity and debt securities, sales of assets, joint ventures and cash provided by operating activities. We will examine the following alternative sources of long-term capital as dictated by current economic conditions:

• borrowings from banks or other lenders;

• the sale of non-core assets;

• the issuance of debt securities;

• the sale of common stock, preferred stock or other equity securities;

• joint venture financing; and

• production payments.

The availability of these sources of capital when the need arises will depend upon a number of factors, some of which are beyond our control. These factors include general economic and financial market conditions, oil and natural gas prices, our credit ratings, interest rates, market perceptions of us or the oil and gas industry, our market value and our operating performance. We may be unable to execute our long-term operating strategy if we cannot obtain capital from these sources when the need arises.

Restrictive debt covenants could limit our growth and our ability to finance our operations, fund our capital needs, respond to changing conditions and engage in other business activities that may be in our best interests.

Our bank credit facility and the indenture governing our 10% notes contain a number of significant covenants that, among other things, restrict or limit our ability to:

• pay dividends or distributions on our capital stock or issue preferred stock;

• repurchase, redeem or retire our capital stock or subordinated debt;

• make certain loans and investments;

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• place restrictions on the ability of subsidiaries to make distributions;

• sell assets, including the capital stock of subsidiaries;

• enter into certain transactions with affiliates;

• create or assume certain liens on our assets;

• enter into sale and leaseback transactions;

• merge or to enter into other business combination transactions;

• enter into transactions that would result in a change of control of us; or

• engage in other corporate activities.

Also, our bank credit facility and the indenture governing our 10% notes require us to maintain compliance with specified financial ratios and satisfy certain financial condition tests. Our ability to comply with these ratios and financial condition tests may be affected by events beyond our control, and we cannot assure you that we will meet these ratios and financial condition tests. These financial ratio restrictions and financial condition tests could limit our ability to obtain future financings, make needed capital expenditures, withstand a future downturn in our business or the economy in general or otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our bank credit facility and the indenture governing our 10% notes impose on us.

A breach of any of these covenants or our inability to comply with the required financial ratios or financial condition tests could result in a default under our bank credit facility and our 10% notes. A default, if not cured or waived, could result in all indebtedness outstanding under our bank credit facility and our 10% notes to become immediately due and payable. If that should occur, we may not be able to pay all such debt or borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us. If we were unable to repay those amounts, the lenders could accelerate the maturity of the debt or proceed against any collateral granted to them to secure such defaulted debt.

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 approximately one third 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. 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. 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.

Approximately one third of our production is exposed to the additional risk of severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise.

At December 31, 2011, approximately one third of our production and approximately 10% of our reserves are located in the Gulf of Mexico and along the Gulf Coast Basin. Operations in this area are subject to severe weather, including hurricanes and tropical storms, as well as flooding, coastal erosion and sea level rise. Some of these adverse conditions can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, certain of our Gulf Coast Basin properties have experienced damages and production downtime as a result of storms including Hurricanes Katrina and Rita, and more recently Hurricanes Gustav and Ike. In addition, according to certain scientific studies, emissions of carbon dioxide, methane, nitrous oxide and other gases commonly known as greenhouse gases may be contributing to global warming of the earth’s atmosphere and to global climate change, which may exacerbate the severity of these adverse conditions. As a result, such conditions may pose increased climate-related risks to our assets and operations.

In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks; however, 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.

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

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

We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or we could experience losses that are not insured or that exceed the maximum limits under our insurance policies. If a significant event that is not fully insured or indemnified occurs, it could materially and adversely affect our financial condition and results of operations.

Factors beyond our control affect our ability to market oil and natural gas.

The availability of markets and the volatility of product prices are beyond our control and represent a significant risk. The marketability of our production depends upon the availability and capacity of natural gas gathering systems, pipelines and processing facilities. The unavailability or lack of capacity of these systems and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Our ability to market oil and natural gas also depends on other factors beyond our control. These factors include:

• the level of domestic production and imports of oil and natural gas;

• the proximity of natural gas production to natural gas pipelines;

• the availability of pipeline capacity;

• the demand for oil and natural gas by utilities and other end users;

• the availability of alternate fuel sources;

• the effect of inclement weather, such as hurricanes;

• state and federal regulation of oil and natural gas marketing; and

• federal regulation of natural gas sold or transported in interstate commerce.

If these factors were to change dramatically, our ability to market oil and natural gas or obtain favorable prices for our oil and natural gas could be adversely affected.

The Macondo well explosion and ensuing oil spill could have broad adverse consequences affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.

In April 2010, there was a fire and explosion aboard the rig drilling the Macondo well operated by another company in ultra-deep water in the U.S. Gulf of Mexico. As a result of the explosion and ensuing fire, the rig sank, causing loss of life, and created a major oil spill that produced economic, environmental and natural resource damage in the U.S. Gulf Coast region. In response to the explosion and spill, there have been many proposals by governmental and private constituencies to address the direct impact of the disaster and to prevent similar disasters in the future. Beginning in May 2010, the U.S. Department of the Interior, initially through its federal Minerals Management Service (the “MMS”), which was subsequently renamed the Bureau of Ocean Energy Management, Regulation and Enforcement (the “BOEMRE”) in June 2010, issued a series of “Notices to Lessees and Operators” (“NTLs”), imposing a variety of new safety measures and permitting requirements, and implementing a moratorium on deepwater drilling activities in the U.S. Gulf of Mexico that effectively shut down deepwater drilling activities until the moratorium was lifted by Secretary of the Interior Ken Salazar in October 2010. Despite the fact that the drilling moratorium was lifted, this spill and its aftermath have led to delays in obtaining drilling permits from the BOEMRE. Effective October 1, 2011, the BOEMRE was split into two federal bureaus, the Bureau of Ocean Energy Management (the “BOEM”), which handles offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, NEPA analysis and environmental studies, and the Bureau of Safety and Environmental Enforcement (the “BSEE”), which is responsible for the safety and enforcement functions of offshore oil and gas operations, including the development and enforcement of safety and environmental regulations, permitting of offshore exploration, development and production activities, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs. Consequently, after October 1, 2011, we will be required to interact with two newly formed federal bureaus to obtain approval of our exploration and development plans and issuance

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of drilling permits, which may result in added plan approval or drilling permit delays as the functions of the former BOEMRE are fully divested and implemented in the two federal bureaus. While legislation was introduced in the U.S. Congress to expedite the process for offshore permits including limitations on the timeframe for environmental and judicial review, there is no guarantee that this or similar legislation will pass.

In addition to the drilling restrictions, new safety measures and permitting requirements already issued by the BOEMRE, there have been numerous additional proposed changes in laws, regulations, guidance and policy in response to the Macondo well explosion and oil spill that could affect our operations and cause us to incur substantial losses or expenditures. Implementation of any one or more of the various proposed responses to the disaster could materially adversely affect operations in the U.S. Gulf of Mexico by raising operating costs, increasing insurance premiums, delaying drilling operations and increasing regulatory costs, and, further, could lead to a wide variety of other unforeseeable consequences that make operations in the U.S. Gulf of Mexico more difficult, more time consuming, and more costly. For example, during the previous session of Congress, a variety of amendments to the OPA, were proposed in response to the Macondo well incident. The OPA and regulations adopted pursuant to the OPA impose a variety of requirements related to the prevention of and response to oil spills into waters of the United States, including the Outer Continental Shelf, which includes the U.S. Gulf of Mexico where we have offshore operations. The OPA subjects operators of offshore leases and owners and operators of oil handling facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from a spill, including, but not limited to, the costs of responding to a release of oil, natural resource damages, and economic damages suffered by persons adversely affected by an oil spill. The OPA also requires owners and operators of offshore oil production facilities to establish and maintain evidence of financial responsibility to cover costs that could be incurred in responding to an oil spill. The OPA currently requires a minimum financial responsibility demonstration of $35 million for companies operating on the Outer Continental Shelf, although the Secretary of Interior may increase this amount up to $150 million in certain situations. Legislation was proposed in the previous session of Congress to amend the OPA to increase the minimum level of financial responsibility to $300 million or more and there exists the possibility that similar legislation could be introduced and adopted during the current session of Congress. If the OPA is amended during the current session of Congress to increase the minimum level of financial responsibility to $300 million, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. If we are unable to provide the level of financial assurance required by the OPA, we may be forced to sell our properties or operations located on the Outer Continental Shelf or enter into partnerships with other companies that can meet the increased financial responsibility requirement, and any such developments could have an adverse effect on the value of our offshore assets and the results of our operations. We cannot predict at this time whether the OPA will be amended or whether the level of financial responsibility required for companies operating on the Outer Continental Shelf will be increased.

Regulatory requirements imposed by the BOEMRE, BOEM or BSEE could significantly delay our ability to obtain permits to drill new wells in offshore waters.

Subsequent to the Macondo well incident in the U.S. Gulf of Mexico, the BOEMRE issued a series of NTLs and other regulatory requirements imposing new standards and permitting procedures for new wells to be drilled in federal waters of the Outer Continental Shelf. These requirements include the following:

• The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements.

• The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers.

• The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain wellbore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams.

• The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system (“SEMS”) in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills.

On September 14, 2011, BOEMRE issued proposed rules that would amend the Workplace Safety Rule by requiring the imposition of certain added safety procedures to a company’s SEMS not covered by the original rule and revising existing obligations that a company’s SEMS be audited by requiring the use of an independent third party auditor who has been pre-approved by the agency to perform the auditing task. As a result of the issuance of these new regulatory requirements, the BOEMRE has been taking much longer than in the past to review and approve permits for drilling operations. Moreover, effective October 1, 2011, the BOEMRE was split into two separate federal bureaus, the BOEM and the BSEE. As the new standards and procedures are being integrated into the existing framework of offshore regulatory programs, we anticipate that there may be increased costs associated with regulatory compliance and delays in obtaining permits for other operations such as recompletions, workovers and abandonment activities.

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We are unsure what long-term effect, if any, the BOEMRE’s, BOEM’s or BSEE’s additional regulatory requirements and permitting procedures will have on our offshore operations. Consequently, we may be subject to a variety of unforeseen adverse consequences arising directly or indirectly from the Macondo well incident.

Regulatory requirements imposed by the BOEMRE, BOEM or BSEE could significantly impact our estimates of future asset retirement obligations from period to period.

We are responsible for plugging and abandoning wellbores and decommissioning associated platforms, pipelines and facilitates on our oil and natural gas properties. In addition to the NTLs discussed previously, the BOEMRE issued NTL No. 2010-G05, effective October 15, 2010, which establishes a more stringent regimen for the timely decommissioning of what is known as “idle iron”—wells, platforms and pipelines that are no longer producing or serving exploration or support functions related to an operator’s lease—in the U.S. Gulf of Mexico. This NTL sets forth more stringent standards for decommissioning timing requirements by applying the requirement that any well that has not been used during the past five years for exploration or production on active leases and is no longer capable of producing in paying quantities must be permanently plugged or temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two years if all of the well’s hydrocarbon and sulphur zones are appropriately isolated. Similarly, platforms or other facilities that are no longer useful for operations must be removed within five years of the cessation of operations. The triggering of these plugging, abandonment and removal activities under what may be viewed as an accelerated schedule in comparison to the industry’s historical decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment and removal costs, which may translate into a need to increase our estimate of future asset retirement obligations required to meet such increased costs. For additional details relating to our asset retirement obligations, please read Note 7 to our audited consolidated financial statements.

Federal and state legislation and regulatory initiatives relating to oil and natural gas development and hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to enhance oil and natural gas production. Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the USEPA is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The USEPA expects to have the initial study results available by late 2012, and the final report is scheduled for completion by 2014. USEPA has also proposed new rules to address air emissions from the oil and gas industry by, among other things, requiring installation of equipment to capture certain gases released from new or refitted wells. The proposals would revise New Source Performance Standards for volatile organic compounds and sulfur dioxide, impose controls on toxics emitted at oil and gas wells, and limit fugitive emissions from associated production, storage and transport requirements. Additionally, the Bureau of Land Management (“BLM”) is preparing a proposal for rules that would not only require operators on public lands to disclose the contents of fracturing fluids, but would also require disclosure of the source of water to be used in fracturing, and plans for disposal of flowback, as well as impose well integrity requirements.

A number of states, including Arkansas, Louisiana, Texas and Wyoming, have required operators or service companies to disclose chemical components in fluids used for hydraulic fracturing. Some states have also imposed, or are considering, more stringent regulation of oil and natural gas exploration and production activities involving hydraulic fracturing by, among other things, promulgating well completion requirements, imposing controls on storage and recycling of flowback fluids, and increasing reporting obligations. In addition, concerns related to the impacts from hydraulic fracturing have led several states to issue moratoria on new natural gas development in various sensitive areas, including some areas overlying the Marcellus Shale. Similar action could be taken to preclude or limit natural gas development in other locations.

Recent seismic events have been observed in some areas (including Arkansas, Oklahoma, Ohio and Texas) where hydraulic fracturing has taken place. Some scientists believe the increased seismic activity may result from deep well fluid injection associated with use of hydraulic fracturing. Additional regulatory measures designed to minimize or avoid damage to geologic formations may be imposed to address such concerns.

Although it is not possible at this time to predict the final outcome of the USEPA’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, management of drilling fluids or well integrity requirements, any new federal or state restrictions imposed on such activities in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to develop oil and natural gas reserves.

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In addition to increased regulation of our business, we may also experience an increase in litigation seeking damages as a result of heightened public concerns related to air quality, water quality, and other environmental impacts.

The adoption and implementation of new statutory and regulatory requirements for derivative transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

In July 2010, federal legislation known as the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, was enacted. The Dodd-Frank Act provides for new statutory and regulatory requirements for derivative transactions, including oil and natural gas hedging transactions. Among other things, the Dodd-Frank Act provides for the creation of position limits for certain derivatives transactions, as well as requiring certain transactions to be cleared on exchanges for which cash collateral will be required. In October 2011, the Commodities Futures Trading Commission, or the CFTC, approved final rules that establish position limits for futures contracts on 28 physical commodities, including four energy commodities, and swaps, futures and options that are economically equivalent to those contracts. The rules provide an exemption for “bona fide hedging” transactions or positions, but this exemption is narrower than the exemption under existing CFTC position limit rules. The new limits generally will go into effect 60 days after the term “swap” is further defined pursuant to Section 721 of the Dodd-Frank Act. These new rules and regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts or reduce the availability of derivatives. Although we believe the derivative contracts that we enter into should not be materially impacted by position limits and other regulatory requirements, the impact upon our businesses will depend on whether the derivative contracts we enter into are exempt from position limits as bona fide hedging transactions.

Depending on the rules adopted by the CFTC or similar rules that may be adopted by other regulatory bodies, we might in the future be required to provide cash collateral for our commodities hedging transactions under circumstances in which we do not currently post cash collateral. Posting of such additional cash collateral could impact liquidity and reduce our cash available for capital expenditures. A requirement to post cash collateral could therefore reduce our ability to execute hedges to reduce commodity price uncertainty and thus protect cash flows. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2012 Budget Proposal includes provisions that would, if enacted, make significant changes to U.S. tax laws. These changes include, but are not limited to, (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) eliminating the deduction from income for domestic production activities relating to oil and natural gas exploration and development and (iii) implementing certain international tax reforms. These proposed changes in the U.S. tax laws, if adopted, could adversely affect our business, financial condition, results of operations and cash flows.

We face strong competition from larger oil and natural gas companies that may negatively affect our ability to carry on operations.

We operate in the highly competitive areas of oil and natural gas exploration, development and production. Factors that affect our ability to compete successfully in the marketplace include:

• the availability of funds and information relating to a property;

• the standards established by us for the minimum projected return on investment; and

• the transportation of natural gas.

Our competitors include major integrated oil companies, substantial independent energy companies, affiliates of major interstate and intrastate pipelines and national and local natural gas gatherers, many of which possess greater financial and other resources than we do. If we are unable to successfully compete against our competitors, our business, prospects, financial condition and results of operations may be adversely affected.

Our estimates of proved reserves have been prepared under revised SEC rules which went into effect for fiscal years ending on or after December 31, 2009, which may make comparisons to prior periods difficult and could limit our ability to book additional proved undeveloped reserves in the future.

This Form 10-K presents estimates of our proved reserves as of December 31, 2011, which have been prepared and presented under revised SEC rules. These revised rules were effective for fiscal years ending on or after December 31, 2009, and require SEC reporting companies to prepare their reserve estimates using revised reserve definitions and revised pricing based on twelve-month

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unweighted first-day-of-the-month average pricing. The previous rules required that reserve estimates be calculated using last-day-of-the-year pricing. As a result of these changes, direct comparisons to our reserve amounts reported prior to the year ending on December 31, 2009 may be more difficult.

Another impact of the revised SEC rules is a general requirement that, subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This revised rule may limit our potential to book additional proved undeveloped reserves as we pursue our drilling program. Moreover, we may be required to write down our proved undeveloped reserves if we do not drill on those reserves within the required five-year time frame. We removed approximately 1.8 Bcfe of proved undeveloped reserves in 2011 as a result of the five year rule.

Our actual production, revenues and expenditures related to our reserves are likely to differ from our estimates of proved reserves. We may experience production that is less than estimated and drilling costs that are greater than estimated in our reserve report. These differences may be material.

Although the estimates of our oil and natural gas reserves and future net cash flows attributable to those reserves were prepared by Ryder Scott Company, L.P., our independent petroleum and geological engineers, we are ultimately responsible for the disclosure of those estimates. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, including:

• historical production from the area compared with production from other similar producing wells;

• the assumed effects of regulations by governmental agencies;

• assumptions concerning future oil and natural gas prices; and

• assumptions concerning future operating costs, severance and excise taxes, development costs and work-over and remedial costs.

Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:

• the quantities of oil and natural gas that are ultimately recovered;

• the production and operating costs incurred;

• the amount and timing of future development expenditures; and

• future oil and natural gas sales prices.

Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same available data. Historically, the difference between our actual production and the production estimated in a prior year’s reserve report has not been material. Our 2011 production was approximately 14% greater than amounts projected in our 2010 reserve report. We cannot assure you that these differences will not be material in the future.

Approximately 39% of our estimated proved reserves at December 31, 2011 are undeveloped and 6% were developed, non-producing. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop and produce our reserves. Although we have prepared estimates of our oil and natural gas reserves and the costs associated with these reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the actual results will be as estimated. In addition, the recovery of undeveloped reserves is generally subject to the approval of development plans and related activities by applicable state and/or federal agencies. Statutes and regulations may affect both the timing and quantity of recovery of estimated reserves. Such statutes and regulations, and their enforcement, have changed in the past and may change in the future, and may result in upward or downward revisions to current estimated proved reserves.

You should not assume that the standardized measure of discounted cash flows is the current market value of our estimated oil and natural gas reserves. In accordance with SEC requirements, the standardized measure of discounted cash flows from proved reserves at December 31, 2011 are based on twelve-month average prices and costs as of the date of the estimate. These prices and costs will change and may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by oil and natural gas purchasers or in governmental regulations or taxation may also affect actual future net cash flows. The timing of both the production and the expenses from the development and production of oil and natural gas properties will affect

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the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor we use when calculating standardized measure of discounted cash flows for reporting requirements in compliance with accounting requirements is not necessarily the most appropriate discount factor. The effective interest rate at various times and the risks associated with our operations or the oil and natural gas industry in general will affect the accuracy of the 10% discount factor.

We may be unable to successfully identify, execute or effectively integrate future acquisitions, which may negatively affect our results of operations.

Acquisitions of oil and gas businesses and properties have been an important element of our business, and we will continue to pursue acquisitions in the future. In the last several years, we have pursued and consummated acquisitions that have provided us opportunities to grow our production and reserves. Although we regularly engage in discussions with, and submit proposals to, acquisition candidates, suitable acquisitions may not be available in the future on reasonable terms. If we do identify an appropriate acquisition candidate, we may be unable to successfully negotiate the terms of an acquisition, finance the acquisition or, if the acquisition occurs, effectively integrate the acquired business into our existing business. Negotiations of potential acquisitions and the integration of acquired business operations may require a disproportionate amount of management’s attention and our resources. Even if we complete additional acquisitions, continued acquisition financing may not be available or available on reasonable terms, any new businesses may not generate revenues comparable to our existing business, the anticipated cost efficiencies or synergies may not be realized and these businesses may not be integrated successfully or operated profitably. The success of any acquisition will depend on a number of factors, including the ability to estimate accurately the recoverable volumes of reserves, rates of future production and future net revenues attainable from the reserves and to assess possible environmental liabilities. Our inability to successfully identify, execute or effectively integrate future acquisitions may negatively affect our results of operations.

Even though we perform due diligence reviews (including a review of title and other records) of the major properties we seek to acquire that we believe is consistent with industry practices, these reviews are inherently incomplete. It is generally not feasible for us to perform an in-depth review of every individual property and all records involved in each acquisition. However, even an in-depth review of records and properties may not necessarily reveal existing or potential problems or permit us to become familiar enough with the properties to assess fully their deficiencies and potential. Even when problems are identified, we may assume certain environmental and other risks and liabilities in connection with the acquired businesses and properties. The discovery of any material liabilities associated with our acquisitions could harm our results of operations.

In addition, acquisitions of businesses may require additional debt or equity financing, resulting in additional leverage or dilution of ownership. Our bank credit facility contains certain covenants that limit, or which may have the effect of limiting, among other things acquisitions, capital expenditures, the sale of assets and the incurrence of additional indebtedness.

Hedging production may limit potential gains from increases in commodity prices or result in losses.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedge at December 31, 2011 is a costless collar placed with the commodity trading branch of JPMorgan Chase Bank which participates in our bank credit facility. We cannot assure you that this or future counterparties will not become credit risks in the future. Hedging arrangements expose us to risks in some circumstances, including situations when the counterparty to the hedging contract defaults on the contractual obligations or there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil and natural gas. Oil and natural gas hedges increased our total oil and gas sales by approximately $2.4 million, $17.5 million and $79.9 million during 2011, 2010 and 2009, respectively. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices.

The loss of key management or technical personnel could adversely affect our ability to operate.

Our operations are dependent upon a diverse group of key senior management and technical personnel. In addition, we employ numerous other skilled technical personnel, including geologists, geophysicists and engineers that are essential to our operations. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of any of these key management or technical personnel could have an adverse effect on our operations.

Operating hazards may adversely affect our ability to conduct business.

Our operations are subject to risks inherent in the oil and natural gas industry, such as:

• unexpected drilling conditions including blowouts, cratering and explosions;

25

• uncontrollable flows of oil, natural gas or well fluids;

• equipment failures, fires or accidents;

• pollution and other environmental risks; and

• shortages in experienced labor or shortages or delays in the delivery of equipment.

These risks could result in substantial losses to us from injury and loss of life, damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Our offshore operations are also subject to a variety of operating risks peculiar to the marine environment, such as hurricanes or other adverse weather conditions and more extensive governmental regulation. These regulations may, in certain circumstances, impose strict liability for pollution damage or result in the interruption or termination of operations.

Environmental compliance costs and environmental liabilities could have a material adverse effect on our financial condition and operations.

Our operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

• require the acquisition of permits before drilling commences;

• restrict the types, quantities and concentration of various substances that can be released into the environment from drilling and production activities;

• limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;

• require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells; and

• impose substantial liabilities for pollution resulting from our operations.

The trend toward stricter standards in environmental legislation and regulation is likely to continue. The enactment of stricter legislation or the adoption of stricter regulations could have a significant impact on our operating costs, as well as on the oil and natural gas industry in general.

Our operations could result in liability for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We could also be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred which could have a material adverse effect on our financial condition and results of operations. We maintain insurance coverage for our operations, including limited coverage for sudden and accidental environmental damages, but this insurance may not extend to the full potential liability that could be caused by sudden and accidental environmental damages and further may not cover environmental damages that occur over time. Accordingly, we may be subject to liability or may lose the ability to continue exploration or production activities upon substantial portions of our properties if certain environmental damages occur.

The Oil Pollution Act of 1990 imposes a variety of regulations on “responsible parties” related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act, could have a material adverse impact on us.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:

• timing and amount of capital expenditures;

• expertise and diligence in adequately performing operations and complying with applicable agreements;

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• financial resources;

• inclusion of other participants in drilling wells; and

• use of technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

Ownership of working interests and overriding royalty interests in certain of our properties by certain of our officers and directors potentially creates conflicts of interest.

Certain of our executive officers and directors or their respective affiliates are working interest owners or overriding royalty interest owners in certain properties. In their capacity as working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners they are entitled to receive their proportionate share of revenues in the normal course of business. There is a potential conflict of interest between us and such officers and directors with respect to the drilling of additional wells or other development operations with respect to these properties.

Risks Relating to Our Outstanding Common Stock

Our stock price could be volatile, which could cause you to lose part or all of your investment.

The stock market has from time to time experienced significant price and volume fluctuations that may be unrelated to the operating performance of particular companies. In particular, the market price of our common stock, like that of the securities of other energy companies, has been and may continue to be highly volatile. During 2011, the sales price of our stock ranged from a low of $5.11 per share (on October 3, 2011) to a high of $9.54 per share (on March 30, 2011). Factors such as announcements concerning changes in prices of oil and natural gas, the success of our acquisition, exploration and development activities, the availability of capital, and economic and other external factors, as well as period-to-period fluctuations and financial results, may have a significant effect on the market price of our common stock.

From time to time, there has been limited trading volume in our common stock. In addition, there can be no assurance that there will continue to be a trading market or that any securities research analysts will continue to provide research coverage with respect to our common stock. It is possible that such factors will adversely affect the market for our common stock.

Issuance of shares in connection with financing transactions or under stock incentive plans will dilute current stockholders.

We have issued 1,495,000 shares of Series B Preferred Stock, which are presently convertible into 5,147,734 shares of our common stock. In addition, pursuant to our stock incentive plan, our management is authorized to grant stock awards to our employees, directors and consultants. You will incur dilution upon the conversion of the Series B Preferred Stock, the exercise of any outstanding stock awards or the grant of any restricted stock. In addition, if we raise additional funds by issuing additional common stock, or securities convertible into or exchangeable or exercisable for common stock, further dilution to our existing stockholders will result, and new investors could have rights superior to existing stockholders.

The number of shares of our common stock eligible for future sale could adversely affect the market price of our stock.

At December 31, 2011, we had reserved approximately 1.9 million shares of common stock for issuance under outstanding options and approximately 5.1 million shares issuable upon conversion of the Series B Preferred Stock. All of these shares of common stock are registered for sale or resale on currently effective registration statements. We may issue additional restricted securities or register additional shares of common stock under the Securities Act in the future. The issuance of a significant number of shares of common stock upon the exercise of stock options, the granting of restricted stock or the conversion of the Series B Preferred Stock, or the availability for sale, or sale, of a substantial number of the shares of common stock eligible for future sale under effective registration statements, under Rule 144 or otherwise, could adversely affect the market price of the common stock.

Provisions in our certificate of incorporation and bylaws could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.

Certain provisions of our certificate of incorporation and bylaws may delay, discourage, prevent or render more difficult an attempt to obtain control of our company, whether through a tender offer, business combination, proxy contest or otherwise. These provisions include:

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• the charter authorization of “blank check” preferred stock;

• provisions that directors may be removed only for cause, and then only on approval of holders of a majority of the outstanding voting stock;

• a restriction on the ability of stockholders to call a special meeting and take actions by written consent; and

• provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders.

We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.

We have not paid dividends on our common stock, cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. We are currently restricted from paying dividends on our common stock by our bank credit facility, the indenture governing the 10% senior notes and, in some circumstances, by the terms of our Series B Preferred Stock. Any future dividends also may be restricted by our then-existing debt agreements.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 3. LEGAL PROCEEDINGS

PetroQuest is involved in litigation relating to claims arising out of its operations in the normal course of business, including worker’s compensation claims, tort claims and contractual disputes. Some of the existing known claims against us are covered by insurance subject to the limits of such policies and the payment of deductible amounts by us. Management believes that the ultimate disposition of all uninsured or unindemnified matters resulting from existing litigation will not have a material adverse effect on PetroQuest’s business or financial position.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITES

The following graph illustrates the yearly percentage change in the cumulative stockholder return on our common stock, compared with the cumulative total return on the NYSE/AMEX Stock Market (U.S. Companies) Index and the NYSE Stocks—Crude Petroleum and Natural Gas Index, for the five years ended December 31, 2011.

Comparison of 5 Year Cumulative Total Return

Assumes Initial Investment of $100

December 2011

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Market Price of and Dividends on Common Stock

Our common stock trades on the New York Stock Exchange under the symbol “PQ.” The following table lists high and low sales prices per share for the periods indicated:

		September 30,		September 30,
	High		Low
2010
1st Quarter	$	7.20	$	4.70
2nd Quarter		8.84		5.01
3rd Quarter		7.29		5.15
4th Quarter		7.92		5.35
2011
1st Quarter	$	9.54	$	7.01
2nd Quarter		9.49		6.43
3rd Quarter		8.63		5.50
4th Quarter		8.00		5.11

As of February 23, 2012, there were 336 common stockholders of record.

We have never paid a dividend on our common stock, cash or otherwise, and intend to retain our cash flow from operations for the future operation and development of our business. In addition, under our bank credit facility, the indenture governing the 10% senior notes, and, in some circumstances, the terms of our Series B Preferred Stock, we are restricted from paying cash dividends on our common stock. The payment of future dividends, if any, will be determined by our Board of Directors in light of conditions then existing, including our earnings, financial condition, capital requirements, restrictions in financing agreements, business conditions and other factors. See Item 1A. “Risk Factors – Risks Relating to our Outstanding Common Stock – We do not intend to pay dividends on our common stock and our ability to pay dividends on our common stock is restricted.”

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

		September 30,		September 30,		September 30,		September 30,
	Total Number of Shares Purchased (1)		Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plan or Program		Maximum Number (or Approximate Dollar Value) of Shares that May be Purchased Under the Plans or Programs
October 1—October 31, 2011		24,842	$	6.79		—		—
November 1—November 30, 2011		1,243	$	7.48		—		—
December 1—December 31, 2011		1,656	$	6.63		—		—

(1) All shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards.

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ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth, as of the dates and for the periods indicated, selected financial information for the Company. The financial information for each of the five years in the period ended December 31, 2011 has been derived from the audited Consolidated Financial Statements of the Company for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and notes thereto. The following information is not necessarily indicative of future results of the Company. All amounts are stated in U.S. dollars unless otherwise indicated.

		September 30,		September 30,		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011 (1)		2010		2009 (2)			2008 (3)			2007
	(in thousands except per share data)
Revenues	$	160,700	$	179,263	$	218,684		$	313,958		$	262,334
Net income (loss) available to common stockholders		5,409		41,987		(95,330	)		(102,100	)		39,245
Net income (loss) available to common stockholders per share:
Basic		0.08		0.67		(1.72	)		(2.08	)		0.79
Diluted		0.08		0.66		(1.72	)		(2.08	)		0.78
Oil and gas properties, net		405,351		312,940		321,875			512,861			554,850
Total assets		516,166		439,517		410,459			670,249			644,347
Long-term debt		150,000		150,000		178,267			278,998			148,755
Stockholders’ equity		222,390		208,162		162,105			237,487			302,317

(1) The year ended December 31, 2011 includes a ceiling test write-down of $18.9 million.

(2) The year ended December 31, 2009 includes a ceiling test write-down of $156.1 million.

(3) The year ended December 31, 2008 includes a ceiling test write-down of $266.2 million.

ITEM 7. 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 2011, we have invested approximately $891 million into growing our longer life assets. During the eight year period ended December 31, 2011, we have realized a 95% drilling success rate on 771 gross wells drilled. Comparing 2011 metrics with those in 2003, the year we implemented our diversification strategy, we have grown production by 212% and estimated proved reserves by 219%. At December 31, 2011, 91% of our estimated proved reserves and 66% of our 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. 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 and 2011, we refocused on the key elements of our business strategy with the goal of growing reserves and production in a fiscally prudent manner. In order to maintain our financial flexibility, we funded our 2011 capital expenditures budget with cash flow from operations, cash on hand and additional proceeds received under the Woodford joint development agreement (see

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“Liquidity and Capital Resources-Source of Capital: Joint Ventures”). As a result of our increased investments during 2010 and 2011, our estimated proved reserves as of December 31, 2011 increased 38% from 2010. Production in the fourth quarter of 2011 was 1% higher than production in the fourth quarter of 2010.

During February 2012, we amended our Woodford Shale joint development agreement (“JDA”) to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry has been expanded to provide for development in both the Mississippian Lime and the Woodford Shale plays whereby we will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry totals approximately $93 million and will be subject to extensions in one-year intervals. See “Liquidity and Capital Resources-Source of Capital: Joint Ventures”.

Critical Accounting Policies and Estimates

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. Companies also have 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 is also 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.

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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.

As a result of lower natural gas prices and higher estimated future development costs, and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, during the first and second quarters of 2011, we recognized ceiling test write-downs totaling $18.9 million.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from estimated 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 December 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.

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Results of Operations

The following table sets forth certain operating information with respect to our oil and gas operations for the years ended December 31, 2011, 2010 and 2009. Our historical results are not necessarily indicative of results to be expected in future periods.

		September 30,		September 30,		September 30,
	Year Ended December 31,
	2011		2010		2009
Production:
Oil (Bbls)		572,096		663,302		600,124
Gas (Mcf)		24,462,933		24,501,540		28,065,270
Ngl (Mcfe)		2,287,846		2,469,871		2,532,822
Total Production (Mcfe)		30,183,355		30,951,223		34,198,836
Sales:
Total oil sales	$	60,064,426	$	52,715,434	$	41,150,657
Total gas sales		78,664,373		107,117,320		163,867,613
Total ngl sales		21,756,917		19,205,726		13,625,642
Total oil and gas sales	$	160,485,716	$	179,038,480	$	218,643,912
Average sales prices:
Oil (per Bbl)	$	104.99	$	79.47	$	68.57
Gas (per Mcf)		3.22		4.37		5.84
Ngl (per Mcfe)		9.51		7.78		5.38
Per Mcfe		5.32		5.78		6.39

The above sales and average sales prices include increases (decreases) to revenue related to the settlement of gas hedges of $2,609,000, $17,538,000 and $74,333,000 and oil hedges of ($192,000), $0 and $5,559,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

Comparison of Results of Operations for the Years Ended December 31, 2011 and 2010

Net income available to common stockholders totaled $5,409,000 and $41,987,000 for the years ended December 31, 2011 and 2010, respectively. The primary reasons for the fluctuations were as follows:

Production Total production decreased 2% during the year ended December 31, 2011 as compared to the 2010 period. However, total production in the fourth quarter of 2011 increased 8% as compared to the third quarter of 2011. Gas production during the year ended December 31, 2011 decreased less than one percent from the comparable period in 2010. The decrease in gas production was primarily the result of normal production declines in the Gulf Coast Basin, offset by increases in gas production from our longer-life basins. As a result of continued drilling in our longer-life basins, we expect our average daily gas production in 2012 to increase as compared to 2011.

Oil production during the twelve month period ended December 31, 2011 decreased 14% from the comparable 2010 period. The decrease in oil production is primarily the result of normal production declines in the Gulf Coast Basin. Partially offsetting this decrease were increases due to the inception of production in the Niobrara Shale, where our first well began production in the fourth quarter of 2010 and three subsequent wells began production during 2011, and in the Eagle Ford Shale, where our first five wells began production in the third quarter of 2011. These Niobrara and Eagle Ford Shale wells represented 8% of our total oil production during 2011. Although we expect to increase oil production from drilling operations in the Mississippian Lime, the Eagle Ford Shale and our La Cantera prospect, such increase is not expected to completely offset normal declines in the Gulf Coast area. As a result, we expect a small decrease in our average daily oil production during 2012 as compared to 2011.

Ngl production during the twelve months ended December 31, 2011 decreased 7% from the comparable 2010 period due to the general decline in Gulf Coast gas production. As a result of ongoing drilling in our Texas, Oklahoma and Gulf Coast assets, we expect our daily Ngl production in 2012 to increase significantly as compared to 2011.

Prices Including the effects of our hedges, average gas prices per Mcf for the twelve months ended December 31, 2011 were $3.22 as compared to $4.37 for the 2010 period. Average oil prices per Bbl for the twelve months ended December 31, 2011 were $104.99 as compared to $79.47 for the 2010 period. Average Ngl prices per Mcfe for the twelve months ended December 31, 2011 were $9.51 compared to $7.78 during the 2010 period. Stated on an Mcfe basis, unit prices received during the twelve month period ended December 31, 2011 were 8% lower than the prices received during the comparable 2010 period.

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Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2011 decreased 10% to $160,486,000 as compared to oil and gas sales of $179,038,000 during the 2010 period. The decreased revenue during 2011 was primarily the result of lower gas prices and decreased oil production partially offset by higher oil prices.

Expenses Lease operating expenses for the twelve months ended December 31, 2011 decreased to $38,571,000 as compared to $39,012,000 during the 2010 period. Per unit lease operating expenses totaled $1.28 per Mcfe during the twelve month period ended December 31, 2011 as compared to $1.26 per Mcfe during the 2010 period. Per unit lease operating expenses in 2012 are expected to be slightly lower than per unit lease operating expenses in 2011.

Production taxes decreased during the twelve months ended December 31, 2011 to $3,100,000 from $4,917,000 during the comparable 2010 period. The decrease was primarily the result of refunds received totaling $2,934,000 during 2011 with respect to severance tax previously paid on Oklahoma and East Texas wells as compared to $1,887,000 received during 2010.

General and administrative expenses during the twelve months ended December 31, 2011 totaled $20,436,000 as compared to expenses of $21,341,000 during the 2010 period. Included in general and administrative expenses was share-based compensation expense related to ASC Topic 718, as follows (in thousands):

		September 30,		September 30,
	Years Ended
	December 31,
	2011		2010
Stock options:
Incentive Stock Options	$	493	$	793
Non-Qualified Stock Options		703		2,081
Restricted stock		3,637		4,263
Share-based compensation	$	4,833	$	7,137

We capitalized $11,176,000 of general and administrative costs during the twelve month period ended December 31, 2011 and $11,894,000 of such costs during the comparable 2010 period. General and administrative expenses in 2012 are expected to approximate 2011.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the twelve months ended December 31, 2011 totaled $57,143,000, or $1.89 per Mcfe, as compared to $58,172,000, or $1.88 per Mcfe, during the comparable 2010 period.

As a result of higher estimated future development costs and low natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recorded non-cash ceiling test write-downs of our oil and gas properties of $18,907,000 during the year ended December 31, 2011. There were no ceiling test write-downs of our oil and gas properties in the 2010 period. See Note 11, “Ceiling Test” for further discussion of the ceiling test write-downs.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $9,648,000 during the twelve months ended December 31, 2011 as compared to $9,952,000 during the 2010 period. We capitalized $7,034,000 of interest during the twelve month period of 2011, and $7,771,000 during the respective 2010 period. The decrease in capitalized interest during the year ended December 31, 2011 was due to the sale of a portion of our unevaluated properties pursuant to the Woodford joint development agreement during the second quarter of 2010. Total interest costs were 6% lower during the twelve months ended December 31, 2011 as compared to the same period in 2010 as a result of the refinancing our 10 3/8% Senior Notes due 2012 with our 10% Senior Notes due 2017 in August 2010.

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.

As a result of the early redemption of our 10 ³/8% Senior Notes due 2012, we incurred a loss during the third quarter of 2010 totaling $5,973,000. Approximately $1,785,000 of the loss related to non-cash amortization of deferred financing costs and discount associated with the 10 ³/8% Senior Notes due 2012.

Income tax expense (benefit) during the twelve months ended December 31, 2011 totaled ($1,810,000) as compared to $1,630,000 during the 2010 period. 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.

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As a result of the ceiling test write-downs recognized during prior years, we 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 future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of the deferred tax asset in prior periods. During the third quarter of 2011, we reversed the remaining valuation allowance as future reversals of existing deferred tax liabilities were sufficient to realize the entire deferred tax asset and we had a net deferred tax liability of $551,000 at December 31, 2011.

Comparison of Results of Operations for the Years Ended December 31, 2010 and 2009

Net income (loss) available to common stockholders totaled $41,987,000 and ($95,330,000) for the years ended December 31, 2010 and 2009, respectively. The primary fluctuations were as follows:

Production Total production decreased 9% during the twelve month period ended December 31, 2010 as compared to the 2009 period. Gas production during the year ended December 31, 2010 decreased 13% from the comparable period in 2009. The decrease in gas production was primarily the result of reduced capital spending during 2009 and normal production declines in the Gulf Coast area.

Oil production during the twelve month period ended December 31, 2010 increased 11% from the 2009 period due to the restoration of production at our Ship Shoal 225 field after repairs and a recompletion following Hurricanes Katrina and Rita. In addition, our oil production rates increased from the drilling success of our Turtle Bayou prospect in 2010 and workovers at our Ft. Trinidad field in E. Texas.

Ngl production during the twelve month period ended December 31, 2010 decreased 2% from the 2009 period due to the general decline in Gulf Coast and Texas gas production.

Prices Including the effects of our hedges, average gas prices per Mcf for the twelve month period ended December 31, 2010 were $4.37, as compared to $5.84 for the 2009 period. Average oil prices per Bbl for the twelve months ended December 31, 2010 were $79.47, as compared to $68.57 for the 2009 period and average Ngl prices per Mcfe were $7.78 and $5.38 during 2010 and 2009, respectively. Stated on an Mcfe basis, unit prices received during the twelve months ended December 31, 2010 were 10% lower than the prices received during the comparable 2009 period.

Revenue Including the effects of hedges, oil and gas sales during the twelve months ended December 31, 2010 decreased 18% to $179,038,000, as compared to oil and gas sales of $218,644,000 during the 2009 period. The decreased revenue during 2010 was primarily the result of lower production and a decrease in hedge settlements realized during the year ended December 31, 2010.

Expenses Lease operating expenses for the year ended December 31, 2010 increased to $39,012,000 as compared to $38,541,000 during the 2009 period. Per unit lease operating expenses totaled $1.26 per Mcfe during the twelve month period ended December 31, 2010 as compared to $1.13 per Mcfe during the 2009 period. Per unit lease operating expenses increased primarily due to the overall reduction in produced volumes as well as the general increase in the costs of services and materials.

General and administrative expenses during the year ended December 31, 2010 totaled $21,341,000 as compared to expenses of $18,869,000 during 2009. Included in general and administrative expenses was share-based compensation expense related to ASC Topic 718, as follows (in thousands):

		September 30,		September 30,
	Years Ended
	December 31,
	2010		2009
Stock options:
Incentive Stock Options	$	793	$	835
Non-Qualified Stock Options		2,081		2,024
Restricted stock		4,263		3,469
Share based compensation	$	7,137	$	6,328

Approximately $455,000 of share based compensation expense during the year ended December 31, 2010 was the result of the voluntary early cancellation of certain stock options and accelerated recognition of associated compensation expense. In total, general and administrative expenses increased 13% in 2010 as compared to 2009 as a result of employee related costs including higher incentive compensation. We capitalized $11,894,000 and $9,330,000 of general and administrative costs during the twelve month periods ended December 31, 2010 and 2009, respectively.

The price of natural gas used in computing our estimated proved reserves during 2009 had a negative impact on our estimated proved reserves from certain of our longer-life properties and reduced the estimated future net cash flows from our estimated proved reserves. As a result, we recorded non-cash ceiling test write-downs of our oil and gas properties during 2009 totaling $156,134,000. No such write-down was recorded during 2010.

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Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for the twelve months ended December 31, 2010 totaled $58,172,000, or $1.88 per Mcfe, as compared to $83,613,000, or $2.44 per Mcfe, during the comparable 2009 period. The decline in our DD&A per Mcfe was primarily the result of the ceiling test write-down of a substantial portion of our proved oil and gas properties during 2009 due to lower commodity prices, the impact of the Woodford Shale joint development agreement, as well as reserve additions during 2010 from our Oklahoma and Arkansas assets.

Interest expense, net of amounts capitalized on unevaluated properties, totaled $9,952,000 during the twelve months ended December 31, 2010 as compared to $12,615,000 during the 2009 period. We capitalized $7,771,000 of interest during the twelve month period ended December 31, 2010 and $8,679,000 during the 2009 period. We reduced the outstanding borrowings under our bank credit facility from $130 million at December 31, 2008 to zero at December 31, 2010. 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.

As a result of the early retirement of our 10 3/8% Senior Notes, we incurred a loss during the third quarter of 2010 totaling $5,973,000. Approximately $1,785,000 of the loss related to non-cash amortization of deferred financing costs and discount associated with the 10 ³/8% Senior Notes.

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. The gain was reduced by $775,000 of costs incurred by us directly related to the settlement. 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.

Other expense during 2010 included an accrual for potential liabilities associated with certain pending legal matters. During 2009, other expense included $5,673,000 related to payments made in connection with a drilling rig contract. Because we elected to idle this drilling rig, there were no corresponding assets to record in connection with the fixed payments required under this contract, regardless of actual rig usage. As a result, the costs were recorded as a component of other expense. This contract expired during July 2009. Other expense during 2009 also included $913,000 related to drill pipe inventory which was impaired to reflect the lower of cost or market.

Income tax expense (benefit) during the twelve months ended December 31, 2010 and 2009 totaled $1,630,000 and ($14,635,000), respectively. 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.

As a result of the ceiling test write-downs recognized during 2008 and 2009, we incurred a cumulative three-year loss. As a result of this cumulative loss and the impact it has on the determination of the recoverability of deferred tax assets through future earnings, we established a valuation allowance for a portion of our deferred tax assets. We reduced the valuation allowance by $20,488,000 during the year ended December 31, 2010, the impact of which is included in our effective tax rate. The valuation allowance was $3,195,000 as of December 31, 2010.

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 December 31, 2011, we had a working capital deficit of $14.0 million compared to a surplus of $59.1 million at December 31, 2010. This decrease was primarily the result of increased operational activities during 2011 as compared to 2010, as we utilized a portion of our cash on hand to fund our capital expenditures in excess of our operational cash flow.

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.

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Source of Capital: Operations

Net cash flow from operations decreased from $131,644,000 during 2010 to $117,890,000 during 2011. 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 and the impact of lower natural gas prices in 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 10 ³/8% Senior Notes due 2012.

At December 31, 2011, the estimated fair value of the Notes was $151.5 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 December 31, 2011, $5.0 million had been accrued in connection with the March 1, 2012 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., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank. The Credit Agreement provides us with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and 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 3, 2016. As of December 31, 2011 we had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

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 $125 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders is currently $100 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2012. 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 80% 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 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). 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 based on a sliding scale of 0.375% to 0.5% depending on total commitments.

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. However, the Credit Agreement permits us to repurchase up to $10 million of our common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase our Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of December 31, 2011, we were in compliance with all of the covenants contained in the Credit Agreement.

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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: 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 are currently exploring divestment opportunities for our Wyoming and Arkansas assets. We cannot assure you that we will be able to sell any of our assets in the future.

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 $57.4 million in cash at closing, net of $2.6 million in transaction fees, and an additional $14 million on November 30, 2011. In addition, since May 2010, WSGP has funded a share of our drilling costs under a drilling program. We achieved certain production performance metrics, as outlined in the joint development agreement, relative to the first 18 wells drilled under the drilling program. As a result, we received an additional $14 million during December 2011.

During February 2012, we amended the joint development agreement with WSGP. The amendment provides additional funding for a share of our drilling costs relative to our 2012 drilling programs in both our Woodford Shale and Mississippian Lime project areas. WSGP will continue to earn 50% of our undeveloped Woodford Shale acreage as they continue to fund a share of our drilling costs.

Use of Capital: Exploration and Development

Our 2012 drilling capital budget, which includes capitalized interest and general and administrative costs, is expected to range between $90 million and $100 million. We plan to fund our 2012 capital budget with cash flow from operations and cash on hand. In addition, we could utilize available borrowings under the bank credit facility or proceeds from the sale of assets to fund a portion of our drilling budget.

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. In September 2011, we acquired approximately 28,000 acres in Pawnee County, Oklahoma targeting the Mississippian Lime, and subsequently sold a 50% interest in this acreage position for approximately $14.5 million. As of December 31, 2011, we had invested approximately $18 million to acquire our 28,000 net acre position in the Mississippian Lime. We plan to drill our first well in this oil play during the first quarter of 2012. During 2011, we invested approximately $31.4 million in leasehold acquisitions, which were funded through a combination of cash flow and cash on hand.

We expect to finance our future acquisition 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.

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Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2011 (in thousands):

		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,		September 30,
													After
	Total		2012		2013		2014		2015		2016		2016
10% senior notes (1)	$	235,000	$	15,000	$	15,000	$	15,000	$	15,000	$	15,000	$	160,000
Operating leases (2)		2,290		1,100		396		245		228		178		143
Capital projects (3)		30,427		3,110		2,889		1,357		803		20,642		1,626
Purchase commitments (4)		20,679		20,117		562		—		—		—		—
Total	$	288,396	$	39,327	$	18,847	$	16,602	$	16,031	$	35,820	$	161,769

(1) Includes principal and estimated interest.

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

(3) Consists of estimated future obligations to abandon our oil and gas properties.

(4) Consists of certain drilling rig contracts.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

Our revenues are derived from the sale of our crude oil and natural gas production. Based on projected annual sales volumes for 2012, a 10% decline in the estimated average prices we expect to receive for our crude oil and natural gas production would have an approximate $9.4 million impact on our 2012 revenues.

We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparties to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparties this difference multiplied by the quantity hedged. During 2011, we received approximately $2.4 million from the counterparties to our derivative instruments 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 JPMorgan Chase Bank and Wells Fargo Bank, both of whom 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 December 31, 2011, we had entered into the following gas hedge contract accounted for as a cash flow hedge:

	Instrument			Weighted
Production Period	Type	Daily Volumes		Average Price
Natural Gas:
2012	Costless Collar		10,000 Mmbtu		$5.00—5.29

At December 31, 2011, we recognized an asset of approximately $6.4 million related to the estimated fair value of this derivative instrument. Based on estimated future commodity prices as of December 31, 2011, we would realize a $4.0 million gain, net of taxes, as an increase to oil and gas sales during the next 12 months. This gain is expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contracts.

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During January 2012, we entered into the following additional hedge contracts accounted for as cash flow hedges:

		September 30,		September 30,		September 30,
	Instrument				Weighted
Production Period	Type		Daily Volumes		Average Price
Natural Gas:
March—October 2012		Swap		20,000 Mmbtu	$	2.60
Crude Oil:
February—December 2012		Swap		250 Bbl	$	100.77

After executing the above transactions, the Company has approximately 8.6 Bcfe of gas volumes, with an average floor of $3.63 per Mcf, and approximately 84,000 barrels of oil volumes at $100.77 per barrel, hedged for 2012.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Information concerning this Item begins on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

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

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

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 quarter ended December 31, 2011 that have materially affected, or that are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Management is responsible for establishing and maintaining adequate internal control over financial reporting, and for performing an assessment of the effectiveness of internal control over financial reporting as of December 31, 2011. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our system of internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally

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accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management performed an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2011 based upon criteria in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, management believes that our internal control over financial reporting was effective as of December 31, 2011 based on these criteria.

Ernst & Young LLP, our independent registered public accounting firm, has issued their report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2011.

March 2, 2012

/s/ Charles T. Goodson

Charles T. Goodson

Chairman and

Chief Executive Officer

/s/ J. Bond Clement

J. Bond Clement

Executive Vice President-

Chief Financial Officer

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

PetroQuest Energy, Inc.

We have audited PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). PetroQuest Energy, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, PetroQuest Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2011, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows, stockholders’ equity and comprehensive income for each of the three years in the period ended December 31, 2011 and our report dated March 2, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 2, 2012

43

ITEM 9B. OTHER INFORMATION

NONE

PART III

ITEMS 10, 11, 12, 13 & 14

Pursuant to General Instruction G of Form 10-K, the information concerning Item 10. Directors, Executive Officers and Corporate Governance, Item 11. Executive Compensation, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, Item 13. Certain Relationships and Related Transactions, and Director Independence and Item 14. Principal Accounting Fees and Services, is incorporated by reference to the information set forth in the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held May 9, 2012, to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 with the Securities and Exchange Commission.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a) 1. FINANCIAL STATEMENTS

The following financial statements of the Company and the Report of the Company’s Independent Registered Public Accounting Firm thereon are included on pages F-1 through F-24 of this Form 10-K:

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2011 and 2010

Consolidated Statements of Operations for the three years ended December 31, 2011

Consolidated Statements of Cash Flows for the three years ended December 31, 2011

Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2011

Consolidated Statements of Comprehensive Income for the three years ended December 31, 2011

Notes to Consolidated Financial Statements

2. FINANCIAL STATEMENT SCHEDULES:

All schedules are omitted because the required information is inapplicable or the information is presented in the Financial Statements or the notes thereto.

3. EXHIBITS:

2.1	Plan and Agreement of Merger by and among Optima Petroleum Corporation, Optima Energy (U.S.) Corporation, its wholly-owned subsidiary, and Goodson Exploration Company, NAB Financial L.L.C., Dexco Energy, Inc., American Explorer, L.L.C. (incorporated herein by reference to Appendix G of the Proxy Statement on Schedule 14A filed July 22, 1998).
3.1	Certificate of Incorporation of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed September 16, 1998).
3.2	Certificate of Amendment to Certificate of Incorporation dated May 14, 2008 (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed June 23, 2009).
3.3	Bylaws of PetroQuest Energy, Inc., as amended of December 20, 2007 (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed December 21, 2007).
3.4	Certificate of Domestication of Optima Petroleum Corporation (incorporated herein by reference to Exhibit 4.4 to Form 8-K filed September 16, 1998).
3.5	Certificate of Designations, Preferences, Limitations and Relative Rights of The Series a Junior Participating Preferred Stock of PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit A of the Rights Agreement attached as Exhibit 1 to Form 8-A filed November 9, 2001).

44

3.6	Certificate of Designations establishing the 6.875% Series B cumulative convertible perpetual preferred stock, dated September 24, 2007 (incorporated herein by reference to Exhibit 3.1 to Form 8-K filed on September 24, 2007).
4.1	Rights Agreement dated as of November 7, 2001 between PetroQuest Energy, Inc. and American Stock Transfer & Trust Company, as Rights Agent, including exhibits thereto (incorporated herein by reference to Exhibit 1 to Form 8-A filed November 9, 2001).
4.2	Form of Rights Certificate (incorporated herein by reference to Exhibit C of the Rights Agreement attached as Exhibit 1 to Form 8-A filed November 9, 2001).
4.3	Indenture, dated May 11, 2005, among PetroQuest Energy, Inc., PetroQuest Energy, LLC, the Subsidiary Guarantors identified therein, and the Bank of New York Trust Company, N.A. (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed May 11, 2005).
4.4	First Supplemental Indenture, dated August 19, 2010, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed on August 19, 2010).
4.5	Indenture, dated August 19, 2010, between PetroQuest Energy, Inc. and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed on August 19, 2010).
4.6	First Supplemental Indenture, dated August 19, 2010, among PetroQuest Energy, Inc., the Subsidiary Guarantors identified therein, and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.3 to Form 8-K filed on August 19, 2010).
†10.1	PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective May 14, 2008 (the “Incentive Plan”) (incorporated herein by reference to Appendix A of the Proxy Statement on Schedule 14A filed April 9, 2008).
†10.2	Form of Incentive Stock Option Agreement for executive officers (including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Mark K. Stover, and J. Bond Clement) under the Incentive Plan (incorporated herein by reference to Exhibit 10.2 to Form 10-K filed February 27, 2009).
†10.3	Form of Nonstatutory Stock Option Agreement under the Incentive Plan (incorporated herein by reference to Exhibit 10.3 to Form 10-K filed February 27, 2009).
†10.4	Form of Restricted Stock Agreement for executive officers (including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Mark K. Stover, and J. Bond Clement) under the Incentive Plan (incorporated herein by reference to Exhibit 10.4 to Form 10-K filed February 27, 2009).
†10.5	PetroQuest Energy, Inc. Annual Incentive Plan (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on May 13, 2010).
†10.6	PetroQuest Energy, Inc. Annual Incentive Plan, as amended and restated (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on June 8, 2010).
10.7	Credit Agreement dated as of October 2, 2008, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A., and Whitney National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed October 6, 2008).
10.8	First Amendment to Credit Agreement dated as of March 24, 2009, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed March 24, 2009).

45

10.9	Second Amendment to Credit Agreement dated as of September 30, 2009, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Calyon New York Branch, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed October 1, 2009).
10.10	Third Amendment to Credit Agreement dated as of August 5, 2010, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Credit Agricole Corporate and Investment Bank, Bank of America, N.A., Wells Fargo Bank, N.A. and Whitney National Bank (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on August 6, 2010).
10.11	Fourth Amendment to Credit Agreement dated as of October 3, 2011, among PetroQuest Energy, Inc., PetroQuest Energy, L.L.C., TDC Energy LLC, JPMorgan Chase Bank, N.A., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank (incorporated herein by reference to Exhibit 10.1 to the Form 8-K filed on October 4, 2011).
†10.12	Amended Executive Employment Agreement dated effective as of December 31, 2008, between Charles T. Goodson and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed January 6, 2009).
†10.13	Amended Executive Employment Agreement dated effective as of December 31, 2008, between W. Todd Zehnder and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed January 6, 2009).
†10.14	Amended Executive Employment Agreement dated effective as of December 31, 2008, between Arthur M. Mixon, III and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed January 6, 2009).
†10.15	Amended Executive Employment Agreement dated effective as of December 31, 2008, between Daniel G. Fournerat and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.4 to Form 8-K filed January 6, 2009).
†10.16	Amended Executive Employment Agreement dated effective as of December 31, 2008, between Mark K. Stover and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.19 to Form 10-K filed February 27, 2009).
†10.17	Amended Executive Employment Agreement dated effective as of December 31, 2008, between J. Bond Clement and PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit 10.20 to Form 10-K filed February 27, 2009).
†10.18	Form of Amended Termination Agreement between the Company and each of its executive officers, including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Mark K. Stover, and J. Bond Clement (incorporated herein by reference to Exhibit 10.6 to Form 8-K filed January 6, 2009).
†10.19	Form of Indemnification Agreement between PetroQuest Energy, Inc. and each of its directors and executive officers, including Charles T. Goodson, W. Todd Zehnder, Arthur M. Mixon, III, Daniel G. Fournerat, Mark K. Stover, J. Bond Clement, William W. Rucks, IV, E. Wayne Nordberg, Michael L. Finch, W.J. Gordon, III and Charles F. Mitchell, II (incorporated herein by reference to Exhibit 10.21 to Form 10-K filed March 13, 2002).
10.20	Form of Surrender and Cancellation Agreement for Directors and Executive Officers (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed on September 16, 2010).
10.21	Joint Development Agreement dated May 17, 2010, among PetroQuest Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a Delaware limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited liability company (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed on August 5, 2010).
*10.22	Second Amendment to the Joint Development Agreement dated February 24, 2012, among PetroQuest Energy, L.L.C., a Louisiana limited liability company, WSGP Gas Producing, LLC, a Delaware limited liability company, and NextEra Energy Gas Producing, LLC, a Delaware limited liability company.

46

14.1	Code of Business Conduct and Ethics (incorporated herein by reference to Exhibit 14.1 to Form 10-K filed March 8, 2006).
*21.1	Subsidiaries of the Company.
*23.1	Consent of Independent Registered Public Accounting Firm.
*23.2	Consent of Ryder Scott Company, L.P.
*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.
*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.
*32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive Officer.
*32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial Officer.
*99.1	Reserve report letter as of December 31, 2011, as prepared by Ryder Scott Company, L.P.
101.INS	XBRL Instance Document.
101.SCH	XBRL Taxonomy Extension Schema Document.
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.

* Filed herewith.

† Management contract or compensatory plan or arrangement

(b) Exhibits. See Item 15 (a) (3) above.

(c) Financial Statement Schedules. None

47

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas used in this Form 10-K.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil or other liquid hydrocarbons.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Block. A block depicted on the Outer Continental Shelf Leasing and Official Protraction Diagrams issued by the U.S. Minerals Management Service or a similar depiction on official protraction or similar diagrams issued by a state bordering on the Gulf of Mexico.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

Extension well. A well drilled to extend the limits of a known reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in a natural gas and oil lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a "farm-in" while the interest transferred by the assignor is a "farm-out."

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have potential for the discovery of commercial hydrocarbons.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

48

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Ngl. Natural gas liquid.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or wells, as the case may be.

Possible reserves. Those additional reserves that are less certain to be recovered than probable reserves.

Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

Probable reserves. Those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved area. The part of a property to which proved reserves have been specifically attributed.

Proved oil and gas reserves. 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.

Proved properties. Properties with proved reserves.

Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

Reliable technology. A grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

49

Resources. Quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

Stratigraphic test well. A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Unproved properties. Properties with no proved reserves

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

50

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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, on March 2, 2012.

PETROQUEST ENERGY, INC.
By:	/s/ Charles T. Goodson
	CHARLES T. GOODSON
	Chairman of the Board, President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 2, 2012.

By:	/s/ Charles T. Goodson	Chairman of the Board, President, Chief Executive Officer and Director
	CHARLES T. GOODSON	(Principal Executive Officer)
By:	/s/ J. Bond Clement	Executive Vice President, Chief Financial Officer, Treasurer
	J. BOND CLEMENT	(Principal Financial and Accounting Officer)
By:	/s/ W.J. Gordon, III	Director
	W.J. GORDON, III
By:	/s/ Michael L. Finch	Director
	MICHAEL L. FINCH
By:	/s/ Charles F. Mitchell, II, M.D.	Director
	CHARLES F. MITCHELL, II, M.D.
By:	/s/ E. Wayne Nordberg	Director
	E. WAYNE NORDBERG
By:	/s/ William W. Rucks, IV	Director
	WILLIAM W. RUCKS, IV

51

INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets of PetroQuest Energy, Inc. as of December 31, 2011 and 2010	F-3
Consolidated Statements of Operations of PetroQuest Energy, Inc. for the years ended December  31, 2011, 2010 and 2009	F-4
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc. for the years ended December  31, 2011, 2010 and 2009	F-5
Consolidated Statements of Stockholders’ Equity of PetroQuest Energy, Inc. for the years ended December 31, 2011, 2010 and 2009	F-6
Consolidated Statements of Comprehensive Income (Loss) of PetroQuest Energy, Inc. for the years ended December 31, 2011, 2010 and 2009	F-7
Notes to Consolidated Financial Statements	F-8

F-1

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

PetroQuest Energy, Inc.

We have audited the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2011 and 2010, and the related consolidated statements of operations, cash flows, stockholders’ equity and comprehensive income (loss) for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of PetroQuest Energy, Inc. at December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed the reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2011, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2012 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 2, 2012

F-2

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)

		September 30,			September 30,
	December 31,
	2011			2010
ASSETS
Current assets:
Cash and cash equivalents	$	22,263		$	63,237
Revenue receivable		15,860			13,386
Joint interest billing receivable		47,445			12,193
Other receivable		—			13,795
Hedge asset		6,418			—
Prepaid drilling costs		2,900			789
Drilling pipe inventory		4,070			11,711
Other current assets		2,965			1,827
Total current assets		101,921			116,938
Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		1,600,546			1,433,642
Unevaluated oil and gas properties		70,408			54,851
Accumulated depreciation, depletion and amortization		(1,265,603	)		(1,175,553	)
Oil and gas properties, net		405,351			312,940
Gas gathering assets		4,177			4,177
Accumulated depreciation and amortization of gas gathering assets		(1,794	)		(1,496	)
Total property and equipment		407,734			315,621
Other assets, net of accumulated depreciation and amortization of $8,066 and $6,435, respectively		6,511			6,958
Total assets	$	516,166		$	439,517
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	50,750		$	26,097
Advances from co-owners		33,867			7,963
Oil and gas revenue payable		13,764			7,220
Accrued interest and preferred stock dividend		6,167			6,575
Hedge liability		—			1,089
Asset retirement obligation		3,110			1,517
Other accrued liabilities		8,250			7,380
Total current liabilities		115,908			57,841
10% Senior Notes		150,000			150,000
Asset retirement obligation		27,317			23,075
Deferred income taxes		551			—
Other liabilities		—			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 62,148 and 61,565 shares, respectively		62			62
Paid-in capital		270,606			266,907
Accumulated other comprehensive income (loss)		4,031			(1,089	)
Accumulated deficit		(52,310	)		(57,719	)
Total stockholders’ equity		222,390			208,162
Total liabilities and stockholders’ equity	$	516,166		$	439,517

See accompanying Notes to Consolidated Financial Statements.

F-3

PETROQUEST ENERGY, INC.

Consolidated Statements of Operations

(Amounts in Thousands, Except Per Share Data)

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Revenues:
Oil and gas sales	$	160,486		$	179,038		$	218,644
Gas gathering revenue		214			225			40
		160,700			179,263			218,684
Expenses:
Lease operating expenses		38,571			39,012			38,541
Production taxes		3,100			4,917			4,656
Depreciation, depletion and amortization		58,243			59,326			84,772
Ceiling test writedown		18,907			—			156,134
General and administrative		20,436			21,341			18,869
Accretion of asset retirement obligation		2,049			1,306			2,452
Interest expense		9,648			9,952			12,615
		150,954			135,854			318,039
Gain on legal settlement		—			12,400			—
Loss on early extinguishment of debt		—			(5,973	)		—
Gain on sale of assets		—			—			485
Other expense		(1,008	)		(1,080	)		(5,955	)
Income (loss) from operations		8,738			48,756			(104,825	)
Income tax expense (benefit)		(1,810	)		1,630			(14,635	)
Net income (loss)		10,548			47,126			(90,190	)
Preferred stock dividend		5,139			5,139			5,140
Net income (loss) available to common stockholders	$	5,409		$	41,987		$	(95,330	)
Earnings per common share:
Basic
Net income (loss) per share	$	0.08		$	0.67		$	(1.72	)
Diluted
Net income (loss) per share	$	0.08		$	0.66		$	(1.72	)
Weighted average number of common shares:
Basic		61,937			61,415			55,363
Diluted		62,325			61,789			55,363

See accompanying Notes to Consolidated Financial Statements.

F-4

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(Amounts in Thousands)

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	10,548		$	47,126		$	(90,190	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)		(1,810	)		1,630			(14,635	)
Depreciation, depletion and amortization		58,243			59,326			84,772
Ceiling test writedown		18,907			—			156,134
Non-cash gain on legal settlement		—			(4,164	)		—
Loss on early extinguishment of debt		—			5,973			—
Gain on sale of assets		—			—			(485	)
Accretion of asset retirement obligation		2,049			1,306			2,452
Pipe inventory impairment		—			—			913
Share-based compensation expense		4,833			7,137			6,328
Amortization costs and other		625			1,334			1,512
Payments to settle asset retirement obligations		(905	)		(6,274	)		(1,803	)
Changes in working capital accounts:
Revenue receivable		(2,474	)		3,071			3,617
Joint interest billing receivable		(35,252	)		(401	)		11,937
Prepaid drilling and pipe costs		5,530			9,180			14,828
Accounts payable and accrued liabilities		34,599			3,368			(51,375	)
Advances from co-owners		25,904			4,301			(1,687	)
Other		(2,907	)		(1,269	)		(496	)
Net cash provided by operating activities		117,890			131,644			121,822
Cash flows from investing activities:
Investment in oil and gas properties		(194,536	)		(103,926	)		(63,420	)
Investment in gas gathering assets		—			—			(204	)
Proceeds from sale of unevaluated properties		28,461			22,473			—
Proceeds from sale of oil and gas properties and other		14,000			35,000			7,451
Net cash used in investing activities		(152,075	)		(46,453	)		(56,173	)
Cash flows from financing activities:
Net payments for share based compensation		(1,133	)		(210	)		(366	)
Deferred financing costs		(517	)		(12	)		(114	)
Proceeds from common stock offering		—			—			38,036
Costs of common stock offering		—			—			(258	)
Payment of preferred stock dividend		(5,139	)		(5,137	)		(5,139	)
Repayment of bank borrowings		(22,000	)		(29,000	)		(101,000	)
Proceeds from bank borrowings		22,000			—			—
Redemption of 10 3/8% Senior Notes		—			(150,000	)		—
Costs to redeem 10 3/8% Senior Notes		—			(4,187	)		—
Proceeds from issuance of 10% Senior Notes		—			150,000			—
Costs to issue 10% Senior Notes		—			(4,180	)		—
Net cash used in financing activities		(6,789	)		(42,726	)		(68,841	)
Net increase (decrease) in cash and cash equivalents		(40,974	)		42,465			(3,192	)
Cash and cash equivalents at beginning of period		63,237			20,772			23,964
Cash and cash equivalents at end of period	$	22,263		$	63,237		$	20,772
Supplemental disclosure of cash flow information
Cash paid during the period for:
Interest	$	16,017		$	11,195		$	20,335
Income taxes	$	51		$	192		$	227

See accompanying Notes to Consolidated Financial Statements.

F-5

PETROQUEST ENERGY, INC.

Consolidated Statements of Stockholders’ Equity

(Amounts in Thousands)

		September 30,		September 30,		September 30,			September 30,			September 30,			September 30,
								Other						Total
	Common		Preferred		Paid-In			Comprehensive			Accumulated			Stockholders’
	Stock		Stock		Capital			Income (Loss)			Deficit			Equity
December 31, 2008	$	49	$	1	$	216,253		$	25,560		$	(4,376	)	$	237,487
Options exercised		—		—		65			—			—			65
Retirement of shares upon vesting of restricted stock		—		—		(431	)		—			—			(431	)
Issuance of common stock		12		—		37,766			—			—			37,778
Share-based compensation expense		—		—		6,328			—			—			6,328
Derivative fair value adjustment, net of tax		—		—		—			(23,792	)		—			(23,792	)
Preferred stock dividend		—		—		—			—			(5,140	)		(5,140	)
Net loss		—		—		—			—			(90,190	)		(90,190	)
December 31, 2009	$	61	$	1	$	259,981		$	1,768		$	(99,706	)	$	162,105
Options exercised		1		—		296			—			—			297
Retirement of shares upon vesting of restricted stock		—		—		(507	)		—			—			(507	)
Share-based compensation expense		—		—		7,137			—			—			7,137
Derivative fair value adjustment, net of tax		—		—		—			(2,857	)		—			(2,857	)
Preferred stock dividend		—		—		—			—			(5,139	)		(5,139	)
Net income		—		—		—			—			47,126			47,126
December 31, 2010	$	62	$	1	$	266,907		$	(1,089	)	$	(57,719	)	$	208,162
Options exercised		—		—		234			—			—			234
Retirement of shares upon vesting of restricted stock		—		—		(1,368	)		—			—			(1,368	)
Share-based compensation expense		—		—		4,833			—			—			4,833
Derivative fair value adjustment, net of tax		—		—		—			5,120			—			5,120
Preferred stock dividend		—		—		—			—			(5,139	)		(5,139	)
Net income		—		—		—			—			10,548			10,548
December 31, 2011	$	62	$	1	$	270,606		$	4,031		$	(52,310	)	$	222,390

See accompanying Notes to Consolidated Financial Statements.

F-6

PETROQUEST ENERGY, INC.

Consolidated Statements of Comprehensive Income (Loss)

(Amounts in Thousands)

		September 30,		September 30,			September 30,
	Year Ended December 31,
	2011		2010			2009
Net income (loss)	$	10,548	$	47,126		$	(90,190	)
Change in fair value of derivative instruments, accounted for as hedges, net of tax benefit (expense) of ($2,388), $1,028 and $13,983, respectively		5,120		(2,857	)		(23,792	)
Comprehensive income (loss)	$	15,668	$	44,269		$	(113,982	)

See accompanying Notes to Consolidated Financial Statements.

F-7

PETROQUEST ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Summary of Significant Accounting Policies

PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest” or the “Company”) is an independent oil and gas company headquartered in Lafayette, Louisiana with exploration offices in Houston, Texas and Tulsa, Oklahoma. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Oklahoma, Arkansas, Wyoming and Texas as well as onshore and in the shallow waters offshore the Gulf Coast Basin.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC. All intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reserve Estimates and Oil and Gas Properties

On December 29, 2008, the SEC adopted revised rules related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements 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 revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised 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. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize 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 rather than year-end prices. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules were effective for reserve estimates beginning December 31, 2009.

The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and administrative costs, which can be directly identified with acquisition, exploration or development of oil and gas properties. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property costs. Transactions involving sales of reserves in place, unless significant, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded from this calculation until the costs are evaluated and proved reserves established or impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers.

The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net cash flow from proved reserves based on first of the month average twelve-month oil and gas prices, including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of ASC Topic 410-20 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test.

F-8

Cash and Cash Equivalents

The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial bank accounts, which result in available funds the next business day.

Accounts Receivable and Other Accrued Liabilities

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. As of December 31, 2011 and 2010, the Company had $1.0 million and $0.6 million, respectively, recorded related to an allowance for doubtful accounts. Other accrued liabilities at December 31, 2011 and 2010 included $7.0 million and $6.3 million, respectively, related to accrued incentive compensation costs.

Gas Gathering Assets

During 2006, the Company acquired an interest in a gas gathering system used in the transportation of natural gas. The costs related to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years.

Other Assets

Other assets includes furniture and fixtures, which are depreciated over their useful lives ranging from 3-7 years, and deferred financing costs, which are amortized over the life of the related debt.

Drilling Pipe Inventory

Drilling pipe inventory, which is included in current assets, consists of tubular goods and pipe that the Company either utilizes in its ongoing exploration and development activities or has available for sale. The cost basis of drilling pipe inventory to be utilized is depreciated as a component of oil and gas properties once the inventory is used in drilling or other capitalized operations.

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs. Other financial and income tax reporting differences occur primarily as a result of statutory depletion.

Revenue Recognition

The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 2011 and 2010 were not significant.

F-9

Certain Concentrations

The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.

The following table identifies customers from whom the Company derived 10% or more of its net oil and gas revenues during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its business or financial condition.

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Laclede Energy		20	%		17	%		12	%
Shell Trading Co.		18	%		19	%		17	%
Texon LP		15	%		17	%		17	%
Gary Williams		11	%		10	%		(a	)
Atmos Energy		(a	)		(a	)		13	%

(a) Less than 10 percent

Fair Value of Financial Instruments

The fair value of cash and cash equivalents, accounts receivable and accounts payable approximates book value at December 31, 2011 and 2010 due to the short-term nature of these accounts. Hedging instruments are reflected as an asset on the balance sheet at an estimated fair value of approximately $6.4 million at December 31, 2011 and as a liability at an estimated fair value of approximately $1.1 million at December 31, 2010, as required under ASC Topic 815. The estimated fair value of the 10% senior notes due 2017 (the “Notes”) at December 31, 2011 was $151.5 million, as compared to the book value of $150 million. At December 31, 2010, the fair value of the Notes was $154.5 million, as compared to the book value of $150 million. The estimated fair value of the Notes was provided by independent brokers using the actual year-end market quotes for the Notes.

Derivative Instruments

Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for cash flow hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. All of the Company’s derivative instruments qualified for cash flow hedge accounting during the periods presented. As a result, the changes in fair value of these instruments were recorded to other comprehensive income (loss). The cash settlements of cash flow hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues include additions related to the net settlement of hedges totaling $2,417,000, $17,538,000 and $79,892,000 during 2011, 2010 and 2009, respectively.

The Company’s hedges are specifically referenced to NYMEX prices. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2011, the Company’s hedging contracts were considered effective cash flow hedges. See Note 8 for further discussion of the Company’s derivative instruments.

F-10

Note 2—Convertible Preferred Stock

During 2007, the Company completed the public offering of 1,495,000 shares of its 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”).

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

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

Mandatory conversion. After October 20, 2010, 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—Common Stock Offering

On June 30, 2009, the Company received $38 million in net proceeds through the public offering of 11.5 million shares of its common stock, which included the issuance of 1.5 million shares pursuant to the underwriters’ over-allotment option.

Note 4—Woodford Joint Development Agreement

In May 2010, PetroQuest Energy, L.L.C. entered into a joint development agreement (“JDA”) with WSGP Gas Producing LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of the Company’s Woodford proved undeveloped reserves (PUDs) as well as the right to earn 50% of the Company’s undeveloped Woodford acreage position through a two phase drilling program. The Company received $57.4 million in cash at closing net of $2.6 million in fees incurred in relation to the transaction, and recorded a $14 million receivable for a contractual payment that was to be received in 2011. The Company received the $14 million contractual payment on November 30, 2011. The Company recorded the total consideration of approximately $71 million during 2010 as an adjustment to capitalized costs with no gain or loss recognized. Certain defined production performance metrics were achieved during the fourth quarter of 2011 and the Company received an additional $14 million during December 2011, which was also recorded as a reduction of capitalized costs. Additionally, since May 2010, WSGP has funded a share of the Company’s drilling costs under a long-term drilling program.

During February 2012, the Company amended its Woodford Shale JDA to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry has been expanded to provide for development in both the Mississippian Lime and the Woodford Shale plays whereby the Company will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry totals approximately $93 million and will be subject to extensions in one-year intervals.

F-11

Note 5—Earnings Per Share

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

		September 30,			September 30,		September 30,
	Income			Shares		Per
For the Year Ended December 31, 2011	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	5,409			61,937
Attributable to participating securities		(154	)		—
BASIC EPS	$	5,255			61,937	$	0.08
Net income available to common stockholders	$	5,409			61,937
Effect of dilutive securities:
Stock options		—			388
Attributable to participating securities		(153	)		—
DILUTED EPS	$	5,256			62,325	$	0.08

		September 30,			September 30,		September 30,
	Income			Shares		Per
For the Year Ended December 31, 2010	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	41,987			61,415
Attributable to participating securities		(1,029	)		—
BASIC EPS	$	40,958			61,415	$	0.67
Net income available to common stockholders	$	41,987			61,415
Effect of dilutive securities:
Stock options		—			374
Attributable to participating securities		(1,023	)		—
DILUTED EPS	$	40,964			61,789	$	0.66

		September 30,			September 30,		September 30,
	Loss			Shares		Per
For the Year Ended December 31, 2009	(Numerator)			(Denominator)		Share Amount
Net loss available to common stockholders	$	(95,330	)		55,363	$	(1.72	)
Effect of dilutive securities:
Stock options		—			—
Restricted stock		—			—
Series B preferred stock		—			—
DILUTED EPS	$	(95,330	)		55,363	$	(1.72	)

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares during 2011, 2010 and 2009 were not included in the computation of diluted earnings per share because the inclusion would have been anti-dilutive. No restricted stock or stock options were included in the computation of diluted earnings per share for the year ended December 31, 2009 because the inclusion would have been anti-dilutive as a result of the net loss reported for the year. Options to purchase 0.1 million and 1.7 million shares of common stock were outstanding during the year ended December 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.

F-12

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 years ended December 31, 2011, 2010 and 2009 is as follows (in thousands):

		September 30,		September 30,		September 30,
	Years Ended
	December 31,
	2011		2010		2009
Stock options:
Incentive Stock Options	$	493	$	793	$	835
Non-Qualified Stock Options		703		2,081		2,024
Restricted stock		3,637		4,263		3,469
Share-based compensation	$	4,833	$	7,137	$	6,328

During the years ended December 31, 2011, 2010 and 2009, the Company recorded income tax benefits of approximately $1.6 million, $2.4 million and $2 million, respectively, related to share-based compensation expense recognized during those periods. Share-based compensation expense for the year ended December 31, 2010 included a charge of approximately $0.5 million related to the voluntary early cancellation of certain stock options and accelerated recognition of associated compensation expense. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented.

At December 31, 2011, the Company had $10.3 million of unrecognized compensation cost related to granted restricted stock and stock options. This amount will be recognized as an expense over a weighted average period of approximately two years.

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 and expected term based on historical activity 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.

The following table outlines the assumptions used in computing the fair value of stock options granted during 2011, 2010 and 2009:

		September 30,		September 30,		September 30,
	Years Ended December 31,
	2011		2010		2009
Dividend yield		0%		0%		0%
Expected volatility		78.5% - 79.7%		78.2% - 80.3%		75.5% - 78.4%
Risk-free rate		1.1% - 2.2%		1.5% - 3.0%		2.3% - 2.5%
Expected term		6 years		6 years		6 years
Forfeiture rate		5.0%		5.0%		5.0%
Stock options granted (1)		395,280		69,500		638,486
Wgtd. avg. grant date fair value per share	$	5.09	$	4.21	$	4.77
Fair value of grants (1)	$	2,011,000	$	293,000	$	3,045,000

(1) Prior to applying estimated forfeiture rate

F-13

The following table details stock option activity during the year ended December 31, 2011:

		September 30,			September 30,		September 30,		September 30,
	Number of Options			Wgtd. Avg. Exercise  Price		Wgtd. Avg. Remaining  Life		Aggregate Intrinsic  Value (000’s)
Outstanding at beginning of year		1,625,551		$	5.09
Granted		395,280			7.49
Expired/cancelled/forfeited		(39,756	)		8.77
Exercised		(58,667	)		3.45
Outstanding at end of year		1,922,408			5.56		5.69 years	$	2,699
Options exercisable at end of year		1,283,674		$	4.73		4.09 years	$	2,653
Options expected to vest		606,797			7.23		8.89 years	$	44

The intrinsic value of options exercised was immaterial for all periods presented.

The following table summarizes information regarding stock options outstanding at December 31, 2011:

		September 30,		September 30,		September 30,		September 30,		September 30,
Range of	Options		Wgtd. Avg.		Wgtd. Avg.		Options		Wgtd. Avg.
Exercise	Outstanding		Remaining		Exercise		Exercisable		Exercise
Price	12/31/11		Contractual Life		Price		12/31/11		Price
$0.0—$3.17		508,167		2.0 years	$	2.95		508,167	$	2.95
$3.17—$5.91		339,065		3.3 years	$	4.24		312,398	$	4.14
$5.91—$7.08		681,896		7.4 years	$	6.99		453,109	$	7.01
$7.08—$9.99		393,280		9.5 years	$	7.59		10,000	$	9.99
		1,922,408		5.7 years	$	5.56		1,283,674	$	4.73

Restricted Stock

The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock at the date of grant, and compensation expense is recognized assuming a 5% estimated forfeiture rate. Restricted stock granted to employees prior to 2011 generally vests over a five-year period with one-fourth vesting on each of the first, second, third and fifth anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant. Restricted stock granted to directors generally vests evenly over a three year period. Beginning January 1, 2011, restricted stock granted to employees generally vests evenly over a three year period. 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.

The following table details restricted stock activity during 2011:

		September 30,			September 30,
	Number of Shares			Wgtd. Avg. Fair Value  per Share
Outstanding at beginning of year		1,638,809		$	6.57
Granted		1,134,917			7.54
Expired/cancelled/forfeited		(88,416	)		5.04
Lapse of restrictions		(696,708	)		8.01
Outstanding at December 31, 2011		1,988,602		$	6.69

At December 31, 2011, the weighted average remaining life of restricted stock outstanding was three years and the intrinsic value of restricted stock outstanding, using the closing stock price on December 31, 2011, was $13.1 million.

F-14

Note 7—Asset Retirement Obligations

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 summarizes the changes to the Company’s asset retirement obligation liability (in thousands):

		September 30,			September 30,
	Years Ended December 31,
	2011			2010
Asset retirement obligation, beginning of period	$	24,592		$	23,916
Liabilities incurred		220			275
Liabilities settled		(905	)		(7,362	)
Accretion expense		2,049			1,306
Revisions in estimates		4,471			6,457
Asset retirement obligation, end of period		30,427			24,592
Less: current portion of asset retirement obligation		(3,110	)		(1,517	)
Long-term asset retirement obligation	$	27,317		$	23,075

Liabilities settled during 2010 included two offshore fields that were completely decommissioned and the liability for an additional offshore platform in the amount of $1.1 million that was transferred to a third party related to a farmout, which represents a non-cash investing activity for purposes of the Statement of Cash Flows. Revisions in estimates during 2011 and 2010 primarily represent increased cost estimates to decommission the Company’s offshore fields including platforms and pipelines and to plug and abandon the related wells.

Note 8—Derivatives

As of December 31, 2011, the Company had entered into the following natural gas contract accounted for as a cash flow hedge:

	Instrument			Weighted
Production Period	Type	Daily Volumes		Average Price
Natural Gas:
2012	Costless Collar		10,000 Mmbtu		$5.00—5.29

At December 31, 2011, the Company had an asset of $6.4 million related to the estimated fair value of this derivative instrument. Based on estimated future commodity prices as of December 31, 2011, the Company would realize a $4 million gain, net of taxes, as an increase to gas sales during the next 12 months. This gain is expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contract.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $2,609,000, $17,538,000 and $74,333,000 and oil hedges of ($192,000), zero and $5,559,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

During January 2012, the Company entered into the following additional oil and gas hedge contracts accounted for as cash flow hedges:

		September 30,		September 30,		September 30,
	Instrument				Weighted
Production Period	Type		Daily Volumes		Average Price
Natural Gas:
March—October 2012		Swap		20,000 Mmbtu	$	2.60
Crude Oil:
February—December 2012		Swap		250 Bbl	$	100.77

F-15

All of the Company’s derivative instruments at December 31, 2011 and 2010 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 as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

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

	September 30,		September 30,
	Commodity Derivatives
	Balance Sheet
Period	Location	Fair Value
December 31, 2011	Hedging asset	$	6,418
December 31, 2010	Hedging liability	$	(1,089	)

Effect of Derivative Instruments on the Consolidated Statement of Operations for the twelve months ended December 31, 2011, 2010 and 2009:

		September 30,		September 30,		September 30,
	Commodity Derivatives
	Amount of Gain (Loss)			Location of	Amount of Gain
	Recognized in Other			Gain Reclassified	Reclassified into
Period	Comprehensive Income (Loss)			into Income	Income
December 31, 2011	$	5,120		Oil and gas sales	$	2,417
December 31, 2010	$	(2,857	)	Oil and gas sales	$	17,538
December 31, 2009	$	(23,792	)	Oil and gas sales	$	79,892

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 instrument at December 31, 2011 is in the form of a costless collar based on NYMEX pricing. The fair value of this derivative 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.

F-16

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

		September 30,		September 30,			September 30,
	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—2011		—	$	6,418			—
Commodity Derivatives—2010		—	$	(1,089	)		—

Note 9—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 10 ³/8% Senior Notes due 2012. The Company incurred a loss totaling $6.0 million relating to the redemption of the 10 ³/8% Senior Notes. Approximately $1.8 million of the loss related to non-cash amortization of deferred financing costs and discount associated with the 10 ³/8% Senior 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 March 1 and September 1. At December 31, 2011, $5.0 million had been accrued in connection with the March 1, 2012 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., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and 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 3, 2016. As of December 31, 2011 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

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 $125 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders is currently $100 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2012. 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 80% 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 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). 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 based on a sliding scale of 0.375% to 0.5% depending on total commitments.

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. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of December 31, 2011, the Company was in compliance with all of the covenants contained in the Credit Agreement.

F-17

Note 10—Related Party Transactions

Three of the Company’s senior officers, Charles T. Goodson, Stephen H. Green, and Mark K. Stover, or their affiliates, are working interest owners and overriding royalty interest owners and E. Wayne Nordberg and William W. Rucks, IV, two of the Company’s directors, are working interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners they are entitled to receive their proportionate share of revenues in the normal course of business.

During 2011, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover or their affiliates, in the amounts of $293,000, $546,000 and $328,000 and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $9. During 2010, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover or their affiliates, in the amounts of $103,000, $520,000 and $261,000 and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $100. No such disbursements were made to Mr. Rucks during 2011 and 2010. During 2009, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover and Nordberg, or their affiliates, in the amounts of $218,000, $559,000, $64,000 and $7,000 and with respect to Mr. Rucks, costs in the amount of $43,000 were billed with no revenue disbursed. With respect to Mr. Goodson, gross revenues attributable to interests, properties or participation rights held by him prior to joining the Company as an officer and director on September 1, 1998 represent substantially all of the gross revenue received by him in 2011.

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. At December 31, 2011, the Company’s joint interest billing receivable included approximately $11,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents less than 1% of the Company’s total joint interest billing receivable at December 31, 2011.

Periodically, the Company charters private aircraft for business purposes. During 2011, 2010 and 2009, the Company paid approximately $128,200, $169,400 and $13,500, respectively, to a third party operator in connection with the Company’s use of flight hours owned by Charles T. Goodson through a fractional ownership arrangement with the third party operator. These amounts represent the cost of the hours purchased by Mr. Goodson. The Company’s use of flight hours purchased by Mr. Goodson was pre-approved by the Company’s Audit Committee and there is no agreement or obligation by or on behalf of the Company to utilize this aircraft arrangement.

Note 11—Ceiling Test

The Company uses the full cost method to account for its oil and natural gas operations. Accordingly, the costs to acquire, explore for and develop oil and natural 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. The Company recorded $18.9 million and $156.1 million of ceiling test write-downs during 2011 and 2009, respectively. No such write-down occurred during 2010.

F-18

Note 12—Investment in Oil and Gas Properties

The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore the continental United States:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

(amounts in thousands)

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Acquisition costs:
Proved	$	2,720		$	10,421		$	427
Unproved		43,207			11,310			1,592
Divestitures—unproved (1)		(14,461	)		(36,139	)		—
Exploration costs:
Proved		92,466			34,310			16,495
Unproved		5,919			10,384			3,249
Development costs		34,400			34,286			19,333
Capitalized general and administrative and interest costs		18,210			19,665			18,009
Total costs incurred	$	182,461		$	84,237		$	59,105

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,175,553	)	$	(1,082,381	)	$	(832,290	)
Provision for DD&A		(57,143	)		(58,172	)		(83,613	)
Ceiling test writedown		(18,907	)		—			(156,134	)
Sale of proved properties and other (1)		(14,000	)		(35,000	)		(10,344	)
Balance, end of year	$	(1,265,603	)	$	(1,175,553	)	$	(1,082,381	)
DD&A per Mcfe	$	1.89		$	1.88		$	2.44

(1) During 2010, the Company recorded $71 million in consideration from its Woodford joint development agreement. During 2011, the Company received an additional $14 million payment associated with the achievement of certain production metrics stipulated under the joint development agreement (See Note 4). In addition, during 2011, the Company sold a portion of its unproved Mississippian Lime acreage for $14.5 million.

At December 31, 2011 and 2010, unevaluated oil and gas properties totaled $70,408,000 and $54,851,000, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2011 included $5,919,000 of costs related to 44 exploratory wells in progress at year-end. These costs will be transferred to evaluated oil and gas properties during 2012 upon the completion of drilling. At December 31, 2010, unevaluated costs included $10,384,000 related to 28 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2011. The Company capitalized $7,034,000, $7,771,000 and $8,679,000 of interest during 2011, 2010 and 2009, respectively. Of the total unevaluated oil and gas property costs of $70,408,000 at December 31, 2011, $38,918,000 or 55%, was incurred in 2011, $11,316,000, or 16%, was incurred in 2010 and $20,174,000 or 29% was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2011 will be evaluated within the next three years, including $24,186,000 that the Company expects to be evaluated during 2012.

Note 13—Income Taxes

The Company follows the provisions of ASC Topic 740, which provides for recognition of deferred tax assets and liabilities for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards, net of a valuation allowance for any asset for which it is more likely than not will not be realized in the Company’s tax return. As a result of the ceiling test write-downs during 2009 and 2008, 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 with respect to a portion of its deferred tax assets. The valuation allowance was $3.2 million and $23.3 million as of December 31, 2010 and 2009, respectively. During 2011, the Company reversed the remaining valuation allowance as future reversals of existing deferred tax liabilities were sufficient to realize the entire deferred tax asset.

F-19

An analysis of the Company’s deferred taxes follows (amounts in thousands):

		September 30,			September 30,
	December 31,
	2011			2010
Net operating loss carryforwards	$	2,409		$	4,737
Percentage depletion carryforward		6,103			3,596
Alternative minimum tax credit		784			776
Contributions carryforward and other		130			90
Temporary differences:
Oil and gas properties—full cost		(10,541	)		(10,141	)
Hedges		(2,388	)		405
Share-based compensation		2,952			3,732
Valuation allowance		—			(3,195	)
Deferred tax liability	$	(551	)	$	—

At December 31, 2011, the Company had approximately $17,973,000 of operating loss carryforwards, of which $11,497,000 relates to excess tax benefits with respect to share-based compensation that have not been recognized in the financial statements. If not utilized, approximately $8,732,000 of such carryforwards would expire in 2025 and the remainder would expire by the year 2031. The Company has available for tax reporting purposes $17,437,000 in statutory depletion deductions that may be carried forward indefinitely.

Income tax expense (benefit) for each of the years ended December 31, 2011, 2010 and 2009 was different than the amount computed using the Federal statutory rate (35%) for the following reasons (amounts in thousands):

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Amount computed using the statutory rate	$	3,058		$	17,065		$	(36,689	)
Increase (reduction) in taxes resulting from:
State & local taxes		192			1,073			(2,306	)
Percentage depletion carryforward		(2,507	)		(252	)		(725	)
Allowance for alternative minimum tax		8			575			—
Non-deductible stock option expense (1)		183			295			311
Share-based compensation (2)		346			3,041			1,334
Other		(300	)		321			161
Change in valuation allowance		(2,790	)		(20,488	)		23,279
Income tax expense (benefit)	$	(1,810	)	$	1,630		$	(14,635	)

(1) Relates to compensation expense recognized on the vesting of Incentive Stock Options

(2) Relates to the write-off of deferred tax assets associated with share based compensation that will not be recognized for tax purposes.

Note 14—Commitments and Contingencies

The Company is a party to ongoing litigation in the normal course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material. At December 31, 2010 the Company had accrued $2.25 million in connection with estimated liabilities related to certain legal matters. All of these matters were settled during 2011, which resulted in an additional charge of $1.43 million included in other expense for the year ended December 31, 2011.

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. The gain was

F-20

reduced by approximately $0.8 million of costs incurred by the Company directly related to the settlement. 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 non-cash gain representing the estimated fair market value of those interests on the effective date of the settlement, which represents a non-cash investing activity for purposes of the Statement of Cash Flows.

A portion of the production that the Company operates in Oklahoma is committed to a firm transportation agreement. Under the terms of the agreement, the Company must deliver 9.1 Bcf of natural gas per year through October 31, 2013.

Lease Commitments

The Company has operating leases for office space and equipment, which expire on various dates through 2017.

Future minimum lease commitments as of December 31, 2011 under these operating leases are as follows (in thousands):

		September 30,
2012	$	1,100
2013		396
2014		245
2015		228
2016		178
Thereafter		143
	$	2,290

Total rent expense under operating leases was approximately $1,342,000, $1,090,000 and $1,082,000 in 2011, 2010 and 2009, respectively.

Note 15—Oil and Gas Reserve Information—Unaudited

The Company’s net proved oil and gas reserves at December 31, 2011 have been estimated by independent petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission.

The 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. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

On December 29, 2008, the SEC issued a revision to Staff Accounting Bulletin 113 (“SAB 113”) which established guidelines related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements 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 revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised 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. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a historical 12-month average price based on 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 rather than year-end prices. In addition, the 12-month average is used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules are effective for reserve estimates beginning December 31, 2009.

During 2011, the Company’s estimated proved reserves increased by 38%. This increase was primarily due to a successful drilling program in Oklahoma in the Woodford Shale. Additionally, reserves increased due to positive performance revisions from the Company’s Oklahoma assets. In total, the Company added approximately 70 Bcfe of proved reserves in Oklahoma, 8 Bcfe from the La Cantera discovery and 9 Bcfe in the Carthage Field from horizontal drilling in the Cotton Valley during 2011. Overall, the Company had a 99% drilling success rate during 2011 on 118 gross wells drilled.

F-21

The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate) and gas reserves, all located onshore and offshore the continental United States:

		September 30,			September 30,			September 30,			September 30,
	Oil			NGL			Natural Gas			Total
	in			in			in			Reserves
	MBbls			MMcfe			MMcf			in MMcfe
Proved reserves as of December 31, 2008		2,201			13,405			158,781			185,392
Revisions of previous estimates		321			(664	)		(9,953	)		(8,691	)
Extensions, discoveries and other additions		9			300			39,003			39,357
Sale of reserves in place		—			—			(2,913	)		(2,913	)
Production		(600	)		(2,533	)		(28,065	)		(34,198	)
Proved reserves as of December 31, 2009		1,931			10,508			156,853			178,947
Revisions of previous estimates		187			187			20,958			22,267
Extensions, discoveries and other additions		168			150			47,681			48,839
Purchase of producing properties		—			—			2,336			2,336
Sale of reserves in place		—			—			(28,761	)		(28,761	)
Production		(663	)		(2,472	)		(24,501	)		(30,951	)
Proved reserves as of December 31, 2010		1,623			8,373			174,566			192,677
Revisions of previous estimates		(294	)		308			8,418			6,962
Extensions, discoveries and other additions		595			8,627			82,113			94,310
Purchase of producing properties		43			91			1,292			1,641
Sale of reserves in place		—			—			—			—
Production		(572	)		(2,288	)		(24,463	)		(30,183	)
Proved reserves as of December 31, 2011		1,395			15,111			241,926			265,407
Proved developed reserves
As of December 31, 2009		1,775			7,134			93,294			111,078
As of December 31, 2010		1,474			6,078			110,599			125,521
As of December 31, 2011		1,160			11,071			143,441			161,472
Proved undeveloped reserves
As of December 31, 2009		156			3,372			63,559			67,867
As of December 31, 2010		149			2,295			63,967			67,156
As of December 31, 2011		235			4,040			98,485			103,935

F-22

The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by the FASB. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.

Standardized Measure

		September 30,			September 30,			September 30,
	December 31,
	2011			2010			2009
Future cash flows	$	1,080,392		$	810,131		$	614,293
Future production costs		(264,219	)		(223,175	)		(193,427	)
Future development costs		(180,846	)		(144,451	)		(148,595	)
Future income taxes		(86,612	)		(41,156	)		(3,166	)
Future net cash flows		548,715			401,349			269,105
10% annual discount		(244,834	)		(164,974	)		(94,817	)
Standardized measure of discounted future net cash flows	$	303,881		$	236,375		$	174,288

Changes in Standardized Measure

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Standarized measure at beginning of year	$	236,375		$	174,288		$	314,787
Sales and transfers of oil and gas produced, net of production costs		(116,398	)		(117,572	)		(95,555	)
Changes in price, net of future production costs		(10,219	)		93,702			(100,150	)
Extensions and discoveries, net of future production and development costs		178,901			42,028			2,790
Changes in estimated future development costs, net of development costs incurred during this period		915			5,803			38,407
Revisions of quantity estimates		11,236			46,373			(15,045	)
Accretion of discount		25,565			17,700			32,719
Net change in income taxes		(18,215	)		(16,568	)		9,698
Purchase of reserves in place		4,805			1,478			—
Sale of reserves in place		—			(798	)		(2,138	)
Changes in production rates (timing) and other		(9,084	)		(10,059	)		(11,225	)
Standardized measure at end of year	$	303,881		$	236,375		$	174,288

The weighted average prices of oil, ngls and gas used for the above tables at December 31, 2011, 2010 and 2009 were $101.42, $79.72 and $60.57 per barrel of oil, respectively, $8.62, $7.00 and $4.89 per Mcfe of natural gas liquids, respectively, and $3.34, $3.56 and $2.84 per Mcf of natural gas, respectively.

F-23

Note 16—Summarized Quarterly Financial Information—Unaudited

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

		September 30,		September 30,			September 30,		September 30,
	Quarter Ended
	March 31		June 30			September 30		December 31
2011:
Revenues	$	41,610	$	41,978		$	39,029	$	38,083
Income (loss) from operations (1)		3,178		(2,088	)		4,749		2,899
Net income (loss) available to common stockholders (1)		1,897		(3,045	)		3,727		2,830
Earnings per share:
Basic	$	0.03	$	(0.05	)	$	0.06	$	0.04
Diluted	$	0.03	$	(0.05	)	$	0.06	$	0.04
2010:
Revenues	$	47,614	$	41,918		$	46,274	$	43,457
Income from operations		27,106		9,046			6,525		6,079
Net income available to common stockholders		29,717		5,248			4,939		2,083
Earnings per share:
Basic	$	0.47	$	0.08		$	0.08	$	0.03
Diluted	$	0.46	$	0.08		$	0.08	$	0.03

(1) Income (loss) from operations and net income (loss) available to common stockholders reported during the three months ended March 31 and June 30, 2011 include non-cash ceiling test write-downs of $5.9 million and $13.0 million, respectively.

F-24

EX-10.22

Exhibit 10.22

SECOND AMENDMENT TO JOINT DEVELOPMENT AGREEMENT

THIS SECOND AMENDMENT TO JOINT DEVELOPMENT AGREEMENT (“Amendment”) effective as of March 1, 2012 (the “Amendment Date”), is entered into by and among PetroQuest Energy, L.L.C., a Louisiana limited liability company whose address is 400 East Kaliste Saloom Road, Suite 6000, Lafayette, Louisiana 70508 (“PetroQuest”), WSGP Gas Producing, LLC, a Delaware limited liability company whose address is 1000 Louisiana, Suite 5550, Houston, Texas 77002 (“WSGP”) and NextEra Energy Gas Producing, LLC, a Delaware limited liability company, whose address is 1000 Louisiana, Suite 5550, Houston, Texas 77002 (“NEGP”). PetroQuest, WSGP and NEGP are referred to herein collectively as a the “Parties” and each individually as a “Party”).

RECITALS:

A. The Parties entered into that certain Joint Development Agreement on May 17, 2010, as amended (jointly, the “Agreement), with respect to the purchase and sale of certain oil and gas leasehold interests and the joint participation in, and development of, certain oil and gas properties, all as more particularly described in the Agreement.

B. The Parties desire to further modify and amend the Agreement as follows, but in particular (i) to memorialize the Parties’ decision to jointly pursue Phase 2 effective as of the Amendment Date to run concurrently with Phase I, and (ii) to set forth their agreement that the Carried Amount under the Agreement may be utilized and applied to certain wells drilled under the ML Agreement (as hereinafter defined) between the Parties and certain wells drilled pursuant to the Territory Agreement (as hereinafter defined); in each case, subject to the specific terms and provisions of this Amendment.

AGREEMENTS:

NOW, THEREFORE, in consideration of Ten Dollars ($10.00) and other good and valuable consideration, the receipt and sufficiency of which are hereby mutually acknowledged, the Parties agree as follows:

1. All capitalized terms not otherwise defined herein shall have the meanings ascribed thereto in the Agreement.

2. The Agreement is hereby modified by replacing the term “6-Month Tranche” in all instances with the term “12-Month Tranche” including, without limitation, such references in Sections 1.1.2,4.3.2,4.3.3,4.5.7 and 4.5.8 of the Agreement.

3. The following additional Defined Terms are appended to Article I of the Agreement:

1.1.102 “Completed Well Costs” shall mean the combined working interest shares of PetroQuest and WSGP of the costs of drilling, completing and equipping any Program Well, Development Well, ML Well or PUD Well, as applicable, not to exceed 115% of the original AFE amount for drilling, completing and equipping such well.

1.1.103 “ML Agreement” means that certain Purchase, Sale and Development Agreement (Mississippian Lime Undeveloped Leasehold) between PetroQuest, WSGP and NEGP dated as of February 17, 2012.

1.1.104 “ML Well” means either (i) any well defined as an Acquisition Well under the ML Agreement, or (ii) any well drilled pursuant to and on the acreage covered by the Territory Agreement.

1.1.105 “Second Amendment” means that certain amendment to the Agreement styled as such between PetroQuest, WSGP and NEGP dated effective as of January 1, 2012.

1.1.106 “Payout Amount” means, for purposes of Section 4.3.2.1 an amount equal to one hundred and twelve percent (112%) of 25% of the Completed Well Costs for any ML Well respecting which PetroQuest has elected to pursue a ML AFS.

1.1.107 “Territory Agreement” means that certain Purchase and Sale Agreement between the Parties covering the “Territory Acquisition” dated as of September 9, 2011, as amended.

1.1.108 “Woodford Well” means any well drilled pursuant to and on the acreage covered by the Agreement.

4. Article IV of the Agreement is hereby modified as follows:

Section 4.3, WSGP’s Carry. All references in Section 4.3 of the Agreement to the ratio 1.6:1 (i.e., respecting WSGP’s Carry) are hereby changed to 1.5:1 with respect to any and ail Development Wells and Program Wells and, if contained in an agreed Drilling Program and 12-Month Tranche, ML Wells, whose Spud Dates are after March 1, 2012; provided, however, that if Phase 2 is terminated by WSGP before completion of Phase 1 and before PetroQuest has applied and benefited

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from the full Carried Amount, WSGP’s Carry of 1.5:1 shall revert to 1.6:1 with respect to any Program Wells and/or Development Wells thereafter drilled under the Drilling Program during Phase 1 until the earlier of (a) the completion of Phase 1, or (b) the Carried Amount has been fully applied.

Section 4.3.1, Phase 1. The Parties agree that Schedule 4.3.1. attached hereto, shall represent the Drilling Program for Phase 1 and Phase 2 for calendar year 2012 as such program may be amended by mutual agreement of the Parties (the “2012 Drilling Program”). The Parties shall agree to the Drilling Program for Phase 1, if applicable, and Phase 2 for each year subsequent to calendar year 2012 during the Quarterly Meeting during the fourth quarter of the prior calendar year. The Parties agree that their execution of this Amendment serves as satisfaction of PetroQuest’s obligation under Section 4.3.1 of the Agreement to deliver the Phase 2 Notice. Further, the Parties hereby add the following paragraph at the end of Section 4.3.1 of the Agreement:

For all PUD Wells drilled during Phase 1 in which WSGP participates and having a Spud Date after March 1, 2012, PetroQuest will have the right, but not the obligation, to cause WSGP to provide an alternative funding structure (“Phase 1 PUD AFS”) for PetroQuest’s share of Completed Well Costs, as follows:

(a) WSGP will pay one hundred percent (100%) of the Completed Well Costs attributable to WSGP’s and PetroQuest’s working interest for such PUD Well, after which point the Parties will bear all costs associated with such PUD Well in accordance with their working interests in the applicable PUD Well;

(b) Upon completion of the PUD Well, PetroQuest will permanently relinquish and assign to WSGP a gross thirty percent (30%) of its gross fifty percent (50%) interest in such PUD Well, retaining only a gross twenty percent (20%) of its gross fifty percent (50%) interest in such PUD Well, with all ownership interests being proportionately reduced;

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(c) PetroQuest’s right to be paid proceeds of production from such PUD Well (i.e., as to its remaining 20% interest) will vest and be payable to PetroQuest from the date of first sales from such PUD Well; and

(d) PetroQuest’s relinquishment to WSGP of thirty percent (30%) of its interest due to its election to utilize the Phase 1 PUD AFS shall be limited to the wellbore of the applicable PUD Well only.

Section 4.3.2, Phase 2. Subject to the remaining terms and provisions of this Amendment, WSGP hereby elects to pursue Phase 2 in accordance with Section 4.3.2 of the Agreement, notwithstanding that Phase 1 has not yet been fully completed as of the date of this Amendment. The Parties acknowledge that Phase 2 shall be deemed to commence effective March 1, 2012 and that Phase 1 and Phase 2 can occur concurrently. Further, the Parties agree that there is no change to the 12-Well Minimum Content and/or Minimum Commitment under Section 4.3.2 of the Agreement, other than all references to the term “6-Month Tranche” are, as previously indicated, replaced with “12-Month Tranche”, and the sentence “Phase 2 shall be divided into six (6) month periods of time, the first of which commencing upon WSGP’s agreement to enter into Phase 2 (each such six (6) month period a “6-Month Tranche”).” shall be replaced in its entirety with the sentence “Phase 2 shall be divided into twelve (12) month periods of time, the first of which commencing upon WSGP’s agreement to enter into Phase 2 or on a date otherwise agreed by the Parties (each such twelve (12) month period a 12-Month Tranche).” The Parties agree that Schedule 4.3.1, attached hereto, shall represent the Drilling Program for Phase 1 and Phase 2 for the twelve (12) months following March 1, 2012, which such Drilling Program may include, if applicable, ML Wells. The Parties agree that (a) Woodford Wells appearing on Schedule 4.3.1 will be Phase 1 wells until the completion of Phase 1, and Woodford Wells drilled after the completion of Phase 1 will constitute Phase 2 wells, and (b) all ML Wells appearing on Schedule 4.3.1 shall constitute Phase 2 wells. The Parties shall agree to the Drilling Program for Phase 2 for each twelve (12) month period subsequent to the 2012 Drilling Program at the Quarterly Meeting held during the fourth quarter of the calendar year prior to the calendar year containing the date of commencement of the applicable 12-Month Tranche and may include, if agreed to by the Parties, ML Wells. Finally, the Parties hereby add to the Agreement the following Section 4.3.2.1:

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4.3.2.1 Miss Lime Development: AFS. While the Parties acknowledge that the proposal by PetroQuest of ML Wells shall be generally controlled by the terms and provisions of their applicable agreements, with respect to the total Carried Amount applicable to Phase 2 under the Agreement (i.e., $92,600,000) (the “Phase 2 Drilling Carry”), a portion of such Phase 2 Drilling Carry equivalent to $7,500.000 per 12-Month Tranche (the “Phase 2 ML Available Drilling Carry”) shall be available to PetroQuest to apply to any such ML Wells drilled during each such 12-Month Tranche of Phase 2, to the extent such ML Wells are included in an agreed Drilling Program and an agreed 12-Month Tranche; subject, however, to the following:

(a) Application of the Phase 2 ML Available Drilling Carry will be in addition to, not in substitution for, the separate $5,000,000 “Drilling Carry” prescribed under the ML Agreement (the “ML Drilling Carry”), but shall be applied in the same manner as the ML Drilling Carry is applied under the ML Agreement, subject to the express provisions of this Amendment;

(b) For any ML Well respecting which PetroQuest wishes to utilize either the Phase 2 ML Available Drilling Carry or the separate ML Drilling Carry, PetroQuest will provide WSGP written notice indicating which “carry bucket” applies to the original AFE for the applicable ML Well. The priority of “carry bucket” application shall first be the ML Drilling Carry followed by utilization of the Phase 2 ML Available Drilling Carry. In the event the ML Drilling Carry is depleted to zero and is therefore insufficient to fund the amount applicable to the prescribed drilling carry attributable to PetroQuest’s interest in an ML Well, then, with respect to such well, PetroQuest may apply an amount from the Phase 2 ML Available Drilling Carry sufficient to make up the difference, but only to the extent of PetroQuest’s prescribed drilling carry;

(c) The Phase 2 ML Available Drilling Carry will, as indicated in Section 4.3 above, be subject to the 1.5:1 rather than the 1.6:1 ratio for any ML Well for which the Phase 2 ML Available Drilling Carry is otherwise available;

(d) Notwithstanding anything to the contrary, if the amount applicable to PetroQuest’s prescribed drilling carry attributable to the mutually agreed upon 2012 Drilling Program requires an expenditure for ML Wells above the amount of $7,500,000 (as attributed to the “Phase 2 ML Available Drilling Carry” set forth above), then the Phase 2 ML

5

Available Drilling Carry shall be increased to cover such increased amount, but only to the extent attributable to the mutually agreed upon 2012 Drilling Program; provided that, for the avoidance of doubt, in the event of such an increase, the Phase 2 Drilling Carry shall be reduced in the amount of such increase.

(e) For the avoidance of doubt, (i) any payment by WSGP of the Phase 2 ML Available Drilling Carry will be credited to WSGP as a payment of the Carried Amount under the Agreement; (ii) any ML Well that is drilled by the Parties shall not be deemed to be subject to the Agreement, whether as a Program Well or otherwise (notwithstanding the fact that an ML Well may be included in the Drilling Program), except as expressly set forth in the Second Amendment, (iii) no part of the Agreement or this Amendment, including the Phase 2 ML Available Drilling Carry, shall be deemed to be a burden on any ML Wells or any lands subject to the ML Agreement and/or the Territory Agreement, (iv) any contract entered into by PetroQuest for the purposes of developing ML Wells shall be subject to Vendor Penalties, (v) no ML Well shall be subject to the Administrative Fee, and (vi) after the expiration of the applicable agreed Drilling Program and/or agreed 12-Month Tranche, any unused portion of the agreed Phase 2 ML Available Drilling Carry shall cease to be available for use with respect to ML Wells;

(f) The Parties may increase the amount of the Phase 2 ML Available Drilling Carry upon mutual written agreement of all of the Parties; and

(g) PetroQuest shall have the option, but not the obligation, of causing WSGP to provide an alternative funding structure for any ML Well in which PetroQuest properly elects to apply the Phase 2 ML Available Drilling Carry (the “ML AFS”), in which case the following shall apply:

(i) WSGP will pay one hundred percent (100%) of the Completed Well Costs for such ML Well, after which point the Parties will bear all costs associated with such ML Well in accordance with their respective working interests in the applicable ML Well;

6

(ii) WSGP will receive all proceeds of production attributable to the joint interests of the Parties in such ML Well, as applicable, until WSGP has received proceeds of production from PetroQuest’s proportionate fifty percent (50%) share equal to fifty percent (50%) of the Payout Amount, at which time PetroQuest will back in for its original fifty percent (50%) share, with all ownership interests being proportionately reduced; and

(iii) The 25% share of PetroQuest’s Completed Well Costs not considered part of the Payout Amount applicable to such ML Well (i.e, being that portion not being recouped by WSGP under clause (ii) above) will be applied, dollar-for-dollar, against the Phase 2 ML Available Drilling Carry.

PetroQuest must submit its election to use the ML AFS to WSGP in the original AFE for the applicable ML Well. All funding elections made by PetroQuest under this Section 4.3.2.1 must be made in accordance with the time periods prescribed for AFE elections under Section 4.4 of the Agreement. Finally, should the Parties discontinue the drilling of ML Wells (whether such discontinuance is due to technical obstacles, geologic reasons or otherwise), the Parties’ commitment to drill PUD Wells, Program Wells and/or Development Wells (i.e., Woodford Weils), if any, under the Agreement will remain unaltered.

5. Article V of the Agreement, Assignments to WSGP, is hereby amended by adding the following provisions:

5.3 Phase 2 Assignments. No later than sixty (60) Business Days following the execution of the Second Amendment, PetroQuest shall (subject to its contingent right of reassignment under Section 5.4 below) prepare, execute and deliver to WSGP an assignment, in the form attached as Exhibit “F” (the “Phase 2 Assignment”), of an undivided 50% of PetroQuest’s right, title and interest in and to the Remaining Assets; the intent being that WSGP will receive an Assignment of all Transaction Assets with respect to which WSGP has not previously received a PUD Assignment or Program Well Assignment under the Agreement. PetroQuest hereby reaffirms, as of the date of the Second Amendment, with respect to the acreage subject to the Phase 2 Assignment, all of the representations and warranties made with respect to the Transaction Assets in Section 6.1 of the Agreement.

7

5.4 Contingent Duty to Reassign. Should WSGP exercise its election rights with respect to Phase 2 in such a manner that Phase 2 terminates before PetroQuest has received the full benefit of the Phase 2 Drilling Carry, WSGP shall, no later than sixty (60) days following the termination or expiration of Phase 2, prepare, execute and deliver to PetroQuest an assignment, in the form attached as Exhibit “F”. of the applicable Reassigned Percentage on such date of WSGP’s right, title and interest in and to the Remaining Assets received by WSGP under the Phase 2 Assignment that would not have otherwise been required to be assigned to WSGP under the Agreement, but for the Phase 2 Assignment, as of such date, whether as PUD Assignments, Program Well Assignments or otherwise (such portion of the Remaining Assets assigned in the Phase 2 Assignment, the “Unearned Acreage”). The Reassigned Percentage shall be calculated as follows:

	September 30,	September 30,
Applicable Percentage	X	Assigned Percentage             =            Reassigned Percentage
where:
Applicable Percentage	=	The unexpended amount of Phase 2 Drilling Carry divided by the Phase 2 Drilling Carry
Assigned Percentage	=	undivided percentage working interest (out of 100%) in the applicable tract of Unearned Acreage that was assigned in the Phase 2 Assignment
Reassigned Percentage	=	WSGP’s undivided percentage interest in the tract of Unearned Acreage to be reassigned

For example, if the Phase 2 Assignment to WSGP covered an undivided 50% working interest in an applicable tract of Unearned Acreage and if Phase 2 effectively terminates with only $62,000,000 of the Phase 2 Drilling Carry having been expended, WSGP would reassign to PetroQuest under this Section 5.4 an undivided 33% of the interest it received under the Phase 2 Assignment in the tract of Unearned Acreage, or an undivided 16.5% working interest in such Unearned Acreage (i.e., $30.6mm/$92.6mm x 50%).

6. The right to the Phase 1 PUD AFS, the ML AFS and the use of the Phase 2 ML Available Drilling Carry on ML Wells is unique to PetroQuest and may not be transferred in any manner without the express prior written consent of WSGP.

7. Except as expressly amended hereby, the Agreement and all rights and obligations created thereby or thereunder are in all respects ratified and confirmed and remain in full force and effect. Where any section, subsection or clause of the Agreement is modified or deleted by

8

this Amendment, any unaltered provision of such section, subsection or clause of the Amendment shall remain in full force and effect. However, where any provision of this Amendment conflicts or is inconsistent with the Agreement, the provision of this Amendment shall control.

8. Sections 18.1,18.4,18.5,18.6,18.7,18.8,18.9,18.10,18.11,18.12,18.13,18.15, 18.16,18.18,18.19 and 18.22 of the Agreement are hereby incorporated by reference as if set out in full herein and shall apply to this Amendment. Each Party represents to the other Party that the execution, delivery and performance of this Amendment have been duly authorized, and this Amendment has been duly executed and delivered by the signatory so authorized, and the obligations contained herein constitute the valid and binding obligations of such Party.

[Signature Page Follows]

9

The undersigned have caused this Amendment to be executed effective as of the date first set forth above.

PETROQUEST:
PetroQuest Energy, L.L.C.
By:	/s/ Mark K. Stover
	Mark K. Stover, Executive Vice
	President—Exploration & Development
WSGP:
WSGP Gas Producing, LLC
By:	/s/ Lawrence A. Wall
	Lawrence A. Wall, Jr., President
NEGP:
NextEra Energy Gas Producing, LLC
By:	/s/ Lawrence A. Wall
	Lawrence A. Wall, Jr., President

10

EX-21.1

Exhibit 21.1

Exhibit 21.1—Subsidiaries of PetroQuest Energy, Inc.

Name	Jurisdiction
PetroQuest Energy, L.L.C.1	Louisiana
PetroQuest Oil and Gas, L.L.C.1	Louisiana
TDC Energy LLC1	Louisiana
Pittrans, Inc.2	Oklahoma
Sea Harvester Energy Development Company, L.L.C.3	Louisiana

¹  100% owned by PetroQuest Energy, Inc.

²  100% owned by PetroQuest Energy, L.L.C.

³  92% owned by TDC Energy LLC

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the Registration Statements (Form S-3 Nos. 333-169973, 333-124746, 333-42520 and 333-89961 and Form S-8 Nos. 333-174260, 333-151296, 333-134161, 333-102758, 333-88846, 333-67578, 333-52700 and 333-65401) of PetroQuest Energy, Inc. and in the related Prospectuses of our reports dated March 2, 2012, with respect to the consolidated financial statements of PetroQuest Energy, Inc. and the effectiveness of internal control over financial reporting of PetroQuest Energy, Inc., included in this Annual Report (Form 10-K) for the year ended December 31, 2011.

/s/ Ernst & Young LLP

New Orleans, Louisiana

March 2, 2012

EX-23.2

Exhibit 23.2

  

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5235	TELEPHONE (713) 651-9191

CONSENT OF RYDER SCOTT COMPANY, L.P.

We hereby consent to (i) the inclusion of our reserve report relating to certain estimated quantities of the proved reserves of oil and gas, future net income and discounted future net income, effective December 31, 2011 of PetroQuest Energy, Inc. (the “Company”) in this Annual Report on Form 10-K prepared by the Company for the year ending December 31, 2011, filed as Exhibit 99.1 of the Form 10-K, and (ii) the incorporation by reference in this Annual Report on Form 10-K prepared by the Company for the year ending December 31, 2011, and to the incorporation by reference thereof into the Company’s previously filed Registration Statements on Form S-3 (File Nos. 333-169973, 333-124746, 333-42520 and 333-89961) and Form S-8 (File Nos. 333-174260, 333-151296, 333-134161, 333-102758, 333-88846, 333-67578, 333-52700 and 333-65401), of information contained in our report relating to certain estimated quantities of the Company’s proved reserves of oil and gas, future net income and discounted future net income, effective December 31, 2011. We further consent to references to our firm under the headings “Business—Oil and Gas Reserves” and “Risk Factors,” and included in or made a part of the Annual Report on Form 10-K prepared by the Company for the year ended December 31, 2011.

We further wish to advise that we are not employed on a contingent basis and that at the time of the preparation of our report, as well as at present, neither Ryder Scott Company, L.P. nor any of its employees had, or now has, a substantial interest in PetroQuest Energy, Inc. or any of its subsidiaries, as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.

\s\ Ryder Scott Company, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

March 2, 2012

1015 4TH STREET, S.W. SUITE 600	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX(403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

EX-31.1

EXHIBIT 31.1

I, Charles T. Goodson, certify that:

1. I have reviewed this Form 10-K of PetroQuest Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Charles T. Goodson            

Charles T. Goodson

Chief Executive Officer

March 2, 2012

EX-31.2

EXHIBIT 31.2

I, J. Bond Clement, certify that:

1. I have reviewed this Form 10-K of PetroQuest Energy, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

March 2, 2012

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Charles T. Goodson, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles T. Goodson

Charles T. Goodson

Chief Executive Officer

March 2, 2012

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO SECTION 906

OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of PetroQuest Energy, Inc. (the “Company”) on Form 10-K for the year ending December 31, 2011 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, J. Bond Clement, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ J. Bond Clement

J. Bond Clement

Chief Financial Officer

March 2, 2012

A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

PETROQUEST ENERGY, INC.

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold and Royalty Interests

(SEC Parameters)

As of

December 31, 2011

        \s\ James F. Latham        

James F. Latham, P.E.

TBPE License No. 49586

Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

  

TBPE REGISTERED ENGINEERING FIRM F-1580		FAX (713) 651-0849
1100 LOUISIANA SUITE 3800	HOUSTON, TEXAS 77002-5235	TELEPHONE (713) 651-9191

February 13, 2012

PetroQuest Energy, Inc.

400 East Kaliste Saloom Rd, Suite 6000

Lafayette, Louisiana 70508

Gentlemen:

At your request, Ryder Scott Company (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold and royalty interests of PetroQuest Energy, Inc. (PetroQuest) as of December 31, 2011. The subject properties are located in the states of Arkansas, Louisiana, Oklahoma, Texas and Wyoming and in the federal waters offshore Louisiana and Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on January 13, 2012 and presented herein, was prepared for public disclosure by PetroQuest in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott represent 100 percent of the total net proved liquid hydrocarbon reserves and 100 percent of the total net proved gas reserves of PetroQuest as of December 31, 2011.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2011, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized below.

SUITE 600,1015 4TH STREET, S.W.	CALGARY, ALBERTA T2R 1J4	TEL (403) 262-2799	FAX (403) 262-2790
621 17TH STREET, SUITE 1550	DENVER, COLORADO 80293-1501	TEL (303) 623-9147	FAX (303) 623-4258

PetroQuest Energy, Inc.

February 13, 2012

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold and Royalty Interests of

PetroQuest Energy, Inc.

As of December 31, 2011

		September 30,		September 30,		September 30,		September 30,
	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Remaining Reserves
Oil/Condensate – Barrels		671,255		488,697		234,849		1,394,801
Plant Products – Barrels		1,484,047		361,040		673,515		2,518,602
Gas – MMCF		132,841		10,600		98,485		241,926
Income Data
Future Gross Revenue	$	554,915,917	$	113,633,248	$	360,974,484	$	1,029,523,649
Deductions		147,307,818		51,429,392		195,458,949		394,196,159
Future Net Income (FNI)	$	407,608,099	$	62,203,856	$	165,515,535	$	635,327,490
Discounted FNI @ 10%	$	243,877,840	$	50,260,797	$	47,233,873	$	341,372,510

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. Except where noted, hereafter, references to percentages of reserves are expressed in BCFe (billions of cubic feet equivalent) based on a conversion of 6 Mcf (thousands of cubic feet) per barrel of hydrocarbon liquid.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income. Gas reserves account for approximately 75 percent and liquid hydrocarbon reserves account for the remaining 25 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

		September 30,
	Discounted Future Net Income
	As of December 31, 2011
Discount Rate	Total
Percent	Proved
5	$	442,193,448
15	$	279,298,415
20	$	236,884,598
30	$	182,141,314

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 3

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Definitions” in this report. The proved developed non-producing reserves included herein consist of the shut-in and behind pipe categories.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The proved gas volumes included herein do not attribute gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves, and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At PetroQuest’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “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”. The proved reserves included herein were estimated using both deterministic and probabilistic methods. Where deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered;” whereas, probabilistic methods are used to assess the uncertainty in the estimated quantities of reserves based on the probability that the quantities actually recovered will equal or exceed the estimate. For proved reserves, there should be at least a 90% probability (P90) that the actual quantities recovered will equal or exceed the estimate.

Proved reserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 4

PetroQuest’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which PetroQuest owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 5

The proved reserves for the properties included herein were estimated by performance methods, the volumetric method, analogy, probabilistic methods or a combination of methods. Approximately 72 percent of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods or a combination of methods. These performance methods include, but may not be limited to, decline curve analysis or material balance methods which utilized extrapolations of historical production and pressure data available through December, 2011 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by PetroQuest or obtained from public data sources and were considered sufficient for the purpose thereof. The remaining 28 percent of the proved producing reserves were estimated by the volumetric method or analogy. The data utilized from the analogues as well as well and seismic data incorporated into our volumetric analysis were considered sufficient for the purpose thereof. These methods were used where there were inadequate historical performance data to establish a definitive trend and where the use of production performance data as a basis for the reserve estimates was considered to be inappropriate.

Approximately 95 percent of the proved developed non-producing reserves included herein were estimated by the volumetric method. The volumetric analysis utilized pertinent well and seismic data furnished to Ryder Scott by PetroQuest or which we have obtained from public data sources that were available through December, 2011. The remaining 5 percent of the proved developed non-producing reserves were based on performance methods outlined above.

Of the proved undeveloped reserves included in this report, 73 percent of the reserves were based on probabilistic analysis, all attributable to two adjacent areas in the Woodford Shale Gas resource play in Pittsburg County, Oklahoma, the Hoss and Lake McAlester fields. Such estimates conform to SEC requirements that there should be at least a 90% probability (P90) that the actual quantities recovered will equal or exceed the estimate, and rigorously conform to the guidelines, criteria and recommended practices contained in SPEE Monograph 3, “Guidelines for the Practical Evaluation of Undeveloped Reserves in Resource Plays.” The remaining 27 percent of undeveloped reserves contained herein were based on the volumetric method or analogy.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data that cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

PetroQuest has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by PetroQuest with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage,

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 6

product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by PetroQuest. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by PetroQuest. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 7

PetroQuest furnished us with the above mentioned average prices in effect on December 31, 2011. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area(s) included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices that were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, gathering and transportation fees and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by PetroQuest. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by PetroQuest to determine these differentials.

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for each of the geographic areas included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
United States	Oil/Condensate	WTI Cushing	$ 96.19/Bbl	$ 101.42/Bbl
	NGLs	WTI Cushing	$ 96.19/Bbl	$ 51.72/Bbl
	Gas	Henry Hub	$ 4.12/MMBTU	$ 3.34/MCF

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report were furnished to us by PetroQuest, and were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the operating cost data used by PetroQuest. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs may include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by PetroQuest and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were significant. The estimates of the net abandonment costs furnished by PetroQuest were accepted without independent verification.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 8

The proved developed non-producing and undeveloped reserves in this report have been incorporated herein in accordance with PetroQuest’s plans to develop these reserves as of December 31, 2011. The implementation of PetroQuest’s development plans as presented to us and incorporated herein is subject to the approval process adopted by PetroQuest’s management. As the result of our inquiries during the course of preparing this report, PetroQuest has informed us that the development activities included herein have been subjected to and received the internal approvals required by PetroQuest’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to PetroQuest. PetroQuest has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, PetroQuest has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by PetroQuest were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

We are independent petroleum engineers with respect to PetroQuest. Neither we nor any of our employees have any interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PetroQuest Energy, Inc.

February 13, 2012

Page 9

Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by PetroQuest.

For filings made with the SEC under the 1933 Securities Act, we have provided our written consent for the references to our name as well as to the references to our third party report in the registration statement(s) on Form S-3 by PetroQuest. Our consent for such use is included as a separate exhibit to the filings made with the SEC by PetroQuest.

PetroQuest makes periodic filings on Form 10-K or 8-K with the SEC under the 1934 Exchange Act. Furthermore, PetroQuest has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 of PetroQuest of the references to our name as well as to the references to our third party report for PetroQuest, which appears in the December 31, 2011 annual report on Form 10-K of PetroQuest. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by PetroQuest.

We have provided PetroQuest with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by PetroQuest and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ James F. Latham

James F. Latham, P.E.

TBPE License No. 49586

Senior Vice President

[SEAL]

JFL (FPR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Person

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. James F. Latham was the primary technical person responsible for overseeing the estimate of the reserves, future production and income.

Latham, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1980, is a Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Latham served in a number of engineering positions with Exxon Company USA (now ExxonMobil). For more information regarding Mr. Latham’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Latham earned a Bachelor of Science degree in Mechanical Engineering from Louisiana Tech University in 1974 and a Master of Science degree in Engineering from Louisiana Tech in 1975. Latham is a licensed Professional Engineer in the State of Texas (1981) and is also a member of the Society of Petroleum Evaluation Engineers and the Society of Petroleum Engineers.

The Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Latham fulfills. As part of his 2011 continuing education hours, Latham attended the 2011 RSC Reserves Conference, which addressed such diverse topics such SEC comment letters, applications of nanotechnology shale resource plays, the so-called “SEC 5-year rule,” and particularly SPEE Monograph 3, which deals with the probabilistic analysis of resource plays. Latham attended an additional 12 hours of formalized in-house training during 2011 covering such topics as the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, geoscience and petroleum economics evaluation methods, procedures and software and ethics for consultants. Latham has personally authored and conducts instruction regarding over 20 petroleum engineering software programs, eleven of which comprise Ryder Scott’s Reservoir Solutions Software for Microsoft^® Excel. Reservoir Solutions Software, published by Ryder Scott, is made available without cost to energy industry professionals, and currently has in excess of 10,000 users located in more than 80 countries worldwide.

Based on his educational background, professional training and more than 32 years of practical experience in the estimation and evaluation of petroleum reserves, Latham has attained the professional qualifications as a Reserves Estimator and as a Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITION

Page 2

(CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITION

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

RESERVES STATUS DEFINITION AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Organization and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Organization and Summary of Significant Accounting Policies [Abstract]

Organization and Summary of Significant Accounting Policies

Note 1—Organization and Summary of Significant Accounting Policies

PetroQuest Energy, Inc. (a Delaware Corporation) (“PetroQuest” or the “Company”) is an independent oil and gas company headquartered in Lafayette, Louisiana with exploration offices in Houston, Texas and Tulsa, Oklahoma. It is engaged in the exploration, development, acquisition and operation of oil and gas properties in Oklahoma, Arkansas, Wyoming and Texas as well as onshore and in the shallow waters offshore the Gulf Coast Basin.

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the Company and its subsidiaries, PetroQuest Energy, L.L.C., PetroQuest Oil & Gas, L.L.C, Pittrans, Inc. and TDC Energy LLC. All intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Reserve Estimates and Oil and Gas Properties

On December 29, 2008, the SEC adopted revised rules related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements 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 revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised 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. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize 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 rather than year-end prices. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules were effective for reserve estimates beginning December 31, 2009.

The Company utilizes the full cost method of accounting, which involves capitalizing all acquisition, exploration and development costs incurred for the purpose of finding oil and gas reserves including the costs of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. The Company also capitalizes the portion of general and administrative costs, which can be directly identified with acquisition, exploration or development of oil and gas properties. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties, the properties are sold, or management determines these costs to have been impaired. Interest is capitalized on unevaluated property costs. Transactions involving sales of reserves in place, unless significant, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Depreciation, depletion and amortization of oil and gas properties is computed using the unit-of-production method based on estimated proved reserves. All costs associated with evaluated oil and gas properties, including an estimate of future development costs associated therewith, are included in the depreciable base. The costs of investments in unevaluated properties are excluded from this calculation until the costs are evaluated and proved reserves established or impaired. Proved oil and gas reserves are estimated annually by independent petroleum engineers.

The capitalized costs of proved oil and gas properties cannot exceed the present value of the estimated net cash flow from proved reserves based on first of the month average twelve-month oil and gas prices, including the effect of hedges in place (the full cost ceiling). If the capitalized costs of proved oil and gas properties exceed the full cost ceiling, the Company is required to write-down the value of its oil and gas properties to the full cost ceiling amount. The Company follows the provisions of Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of ASC Topic 410-20 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test.

Cash and Cash Equivalents

The Company considers all highly liquid investments with a stated maturity of three months or less to be cash and cash equivalents. The majority of the Company’s cash and cash equivalents are in overnight securities made through its commercial bank accounts, which result in available funds the next business day.

Accounts Receivable and Other Accrued Liabilities

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. As of December 31, 2011 and 2010, the Company had $1.0 million and $0.6 million, respectively, recorded related to an allowance for doubtful accounts. Other accrued liabilities at December 31, 2011 and 2010 included $7.0 million and $6.3 million, respectively, related to accrued incentive compensation costs.

Gas Gathering Assets

During 2006, the Company acquired an interest in a gas gathering system used in the transportation of natural gas. The costs related to this system are depreciated on a straight line basis over the estimated remaining useful life, generally 14 years.

Other Assets

Other assets includes furniture and fixtures, which are depreciated over their useful lives ranging from 3-7 years, and deferred financing costs, which are amortized over the life of the related debt.

Drilling Pipe Inventory

Drilling pipe inventory, which is included in current assets, consists of tubular goods and pipe that the Company either utilizes in its ongoing exploration and development activities or has available for sale. The cost basis of drilling pipe inventory to be utilized is depreciated as a component of oil and gas properties once the inventory is used in drilling or other capitalized operations.

Income Taxes

The Company accounts for income taxes in accordance with ASC Topic 740. Provisions for income taxes include deferred taxes resulting primarily from temporary differences due to different reporting methods for oil and gas properties for financial reporting purposes and income tax purposes. For financial reporting purposes, all exploratory and development expenditures are capitalized and depreciated, depleted and amortized on the unit-of-production method. For income tax purposes, only the equipment and leasehold costs relative to successful wells are capitalized and recovered through depreciation or depletion. Generally, most other exploratory and development costs are charged to expense as incurred; however, the Company may use certain provisions of the Internal Revenue Code which allow capitalization of intangible drilling costs. Other financial and income tax reporting differences occur primarily as a result of statutory depletion.

Revenue Recognition

The Company records natural gas and oil revenue under the sales method of accounting. Under the sales method, the Company recognizes revenues based on the amount of natural gas or oil sold to purchasers, which may differ from the amounts to which the Company is entitled based on its interest in the properties. Gas balancing obligations as of December 31, 2011 and 2010 were not significant.

Certain Concentrations

The Company’s production is sold on month to month contracts at prevailing prices. The Company attempts to diversify its sales among multiple purchasers and obtain credit protection such as letters of credit and parental guarantees when necessary.

The following table identifies customers from whom the Company derived 10% or more of its net oil and gas revenues during the years presented. Based on the availability of other customers, the Company does not believe the loss of any of these customers would have a significant effect on its business or financial condition.

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Laclede Energy		20	%		17	%		12	%
Shell Trading Co.		18	%		19	%		17	%
Texon LP		15	%		17	%		17	%
Gary Williams		11	%		10	%		(a	)
Atmos Energy		(a	)		(a	)		13	%

(a) Less than 10 percent

Fair Value of Financial Instruments

The fair value of cash and cash equivalents, accounts receivable and accounts payable approximates book value at December 31, 2011 and 2010 due to the short-term nature of these accounts. Hedging instruments are reflected as an asset on the balance sheet at an estimated fair value of approximately $6.4 million at December 31, 2011 and as a liability at an estimated fair value of approximately $1.1 million at December 31, 2010, as required under ASC Topic 815. The estimated fair value of the 10% senior notes due 2017 (the “Notes”) at December 31, 2011 was $151.5 million, as compared to the book value of $150 million. At December 31, 2010, the fair value of the Notes was $154.5 million, as compared to the book value of $150 million. The estimated fair value of the Notes was provided by independent brokers using the actual year-end market quotes for the Notes.

Derivative Instruments

Under ASC Topic 815, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for cash flow hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in stockholders’ equity through other comprehensive income (loss), net of related taxes, to the extent the hedge is effective. All of the Company’s derivative instruments qualified for cash flow hedge accounting during the periods presented. As a result, the changes in fair value of these instruments were recorded to other comprehensive income (loss). The cash settlements of cash flow hedges are recorded as adjustments to oil and gas sales. Oil and gas revenues include additions related to the net settlement of hedges totaling $2,417,000, $17,538,000 and $79,892,000 during 2011, 2010 and 2009, respectively.

The Company’s hedges are specifically referenced to NYMEX prices. The effectiveness of hedges is evaluated at the time the contracts are entered into, as well as periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices received from the designated production. Through this analysis, the Company is able to determine if a high correlation exists between the prices received for its designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2011, the Company’s hedging contracts were considered effective cash flow hedges. See Note 8 for further discussion of the Company’s derivative instruments.

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Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements of Comprehensive Income (Loss) [Abstract]
Tax benefit (expense) of derivative instruments	$ (2,388)	$ 1,028	$ 13,983

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 22,263	$ 63,237
Revenue receivable	15,860	13,386
Joint interest billing receivable	47,445	12,193
Other receivable	0	13,795
Hedge asset	6,418	0
Prepaid drilling costs	2,900	789
Drilling pipe inventory	4,070	11,711
Other current assets	2,965	1,827
Total current assets	101,921	116,938
Oil and gas properties:
Oil and gas properties, full cost method	1,600,546	1,433,642
Unevaluated oil and gas properties	70,408	54,851
Accumulated depreciation, depletion and amortization	(1,265,603)	(1,175,553)
Oil and gas properties, net	405,351	312,940
Gas gathering assets	4,177	4,177
Accumulated depreciation and amortization of gas gathering assets	(1,794)	(1,496)
Total property and equipment	407,734	315,621
Other assets, net of accumulated depreciation and amortization of $8,066 and $6,435, respectively	6,511	6,958
Total assets	516,166	439,517
Current liabilities:
Accounts payable to vendors	50,750	26,097
Advances from co-owners	33,867	7,963
Oil and gas revenue payable	13,764	7,220
Accrued interest and preferred stock dividend	6,167	6,575
Hedge liability	0	1,089
Asset retirement obligation	3,110	1,517
Other accrued liabilities	8,250	7,380
Total current liabilities	115,908	57,841
10% Senior Notes	150,000	150,000
Asset retirement obligation	27,317	23,075
Deferred income taxes	551	0
Other liabilities	0	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 62,148 and 61,565 shares, respectively	62	62
Paid-in capital	270,606	266,907
Accumulated other comprehensive income (loss)	4,031	(1,089)
Accumulated deficit	(52,310)	(57,719)
Total stockholders' equity	222,390	208,162
Total liabilities and stockholders' equity	$ 516,166	$ 439,517

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Consolidated Statements of Stockholders' Equity (USD $) In Thousands	Total	Common Stock	Preferred Stock	Paid-In Capital	Other Comprehensive Income (Loss)	Accumulated Deficit
Balance at Dec. 31, 2008	$ 237,487	$ 49	$ 1	$ 216,253	$ 25,560	$ (4,376)
Options exercised	65			65
Retirement of shares upon vesting of restricted stock	(431)			(431)
Issuance of common stock	37,778	12		37,766
Share-based compensation expense	6,328			6,328
Derivative fair value adjustment, net of tax	(23,792)				(23,792)
Preferred stock dividend	(5,140)					(5,140)
Net income (loss)	(90,190)					(90,190)
Balance at Dec. 31, 2009	162,105	61	1	259,981	1,768	(99,706)
Options exercised	297	1		296
Retirement of shares upon vesting of restricted stock	(507)			(507)
Share-based compensation expense	7,137			7,137
Derivative fair value adjustment, net of tax	(2,857)				(2,857)
Preferred stock dividend	(5,139)					(5,139)
Net income (loss)	47,126					47,126
Balance at Dec. 31, 2010	208,162	62	1	266,907	(1,089)	(57,719)
Options exercised	234			234
Retirement of shares upon vesting of restricted stock	(1,368)			(1,368)
Share-based compensation expense	4,833			4,833
Derivative fair value adjustment, net of tax	5,120				5,120
Preferred stock dividend	(5,139)					(5,139)
Net income (loss)	10,548					10,548
Balance at Dec. 31, 2011	$ 222,390	$ 62	$ 1	$ 270,606	$ 4,031	$ (52,310)

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies [Abstract]

Commitments and Contingencies

Note 14—Commitments and Contingencies

The Company is a party to ongoing litigation in the normal course of business. While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management believes that the effect on its financial condition, results of operations and cash flows, if any, will not be material. At December 31, 2010 the Company had accrued $2.25 million in connection with estimated liabilities related to certain legal matters. All of these matters were settled during 2011, which resulted in an additional charge of $1.43 million included in other expense for the year ended December 31, 2011.

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. The gain was reduced by approximately $0.8 million of costs incurred by the Company directly related to the settlement. 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 non-cash gain representing the estimated fair market value of those interests on the effective date of the settlement, which represents a non-cash investing activity for purposes of the Statement of Cash Flows.

A portion of the production that the Company operates in Oklahoma is committed to a firm transportation agreement. Under the terms of the agreement, the Company must deliver 9.1 Bcf of natural gas per year through October 31, 2013.

Lease Commitments

The Company has operating leases for office space and equipment, which expire on various dates through 2017.

Future minimum lease commitments as of December 31, 2011 under these operating leases are as follows (in thousands):

		September 30,
2012	$	1,100
2013		396
2014		245
2015		228
2016		178
Thereafter		143
	$	2,290

Total rent expense under operating leases was approximately $1,342,000, $1,090,000 and $1,082,000 in 2011, 2010 and 2009, respectively.

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Summarized Quarterly Financial Information - Unaudited

12 Months Ended

Dec. 31, 2011

Summarized Quarterly Financial Information - Unaudited [Abstract]

Summarized Quarterly Financial Information - Unaudited

Note 16—Summarized Quarterly Financial Information—Unaudited

Summarized quarterly financial information is as follows (amounts in thousands except per share data):

		September 30,		September 30,			September 30,		September 30,
	Quarter Ended
	March 31		June 30			September 30		December 31
2011:
Revenues	$	41,610	$	41,978		$	39,029	$	38,083
Income (loss) from operations (1)		3,178		(2,088	)		4,749		2,899
Net income (loss) available to common stockholders (1)		1,897		(3,045	)		3,727		2,830
Earnings per share:
Basic	$	0.03	$	(0.05	)	$	0.06	$	0.04
Diluted	$	0.03	$	(0.05	)	$	0.06	$	0.04
2010:
Revenues	$	47,614	$	41,918		$	46,274	$	43,457
Income from operations		27,106		9,046			6,525		6,079
Net income available to common stockholders		29,717		5,248			4,939		2,083
Earnings per share:
Basic	$	0.47	$	0.08		$	0.08	$	0.03
Diluted	$	0.46	$	0.08		$	0.08	$	0.03

(1) Income (loss) from operations and net income (loss) available to common stockholders reported during the three months ended March 31 and June 30, 2011 include non-cash ceiling test write-downs of $5.9 million and $13.0 million, respectively.

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Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Consolidated Statements of Comprehensive Income (Loss) [Abstract]
Net income (loss)	$ 10,548	$ 47,126	$ (90,190)
Change in fair value of derivative instruments, accounted for as hedges, net of tax benefit (expense) of ($2,388), $1,028 and $13,983, respectively	5,120	(2,857)	(23,792)
Comprehensive income (loss)	$ 15,668	$ 44,269	$ (113,982)

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Consolidated Balance Sheets [Abstract]
Accumulated depreciation and amortization	$ 8,066	$ 6,435
Preferred stock, par value	$ 0.001	$ 0.001
Preferred stock, shares authorized	5,000	5,000
Preferred stock, shares issued	1,495	1,495
Preferred stock, shares outstanding	1,495	1,495
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	150,000	150,000
Common stock, shares issued	62,148	62,148
Common stock, shares outstanding	61,565	61,565

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt [Abstract]

Long-Term Debt

Note 9—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 10  ³/8% Senior Notes due 2012. The Company incurred a loss totaling $6.0 million relating to the redemption of the 10 ³/8 % Senior Notes. Approximately $1.8 million of the loss related to non-cash amortization of deferred financing costs and discount associated with the 10  ³/8% Senior 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 March 1 and September 1. At December 31, 2011, $5.0 million had been accrued in connection with the March 1, 2012 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., Wells Fargo Bank, N.A., Capital One, N.A., Iberiabank and Whitney Bank. The Credit Agreement provides the Company with a $300 million revolving credit facility that permits borrowings based on the commitments of the lenders and 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 3, 2016. As of December 31, 2011 the Company had no borrowings outstanding under (and no letters of credit issued pursuant to) the Credit Agreement.

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 $125 million (subject to the aggregate commitments of the lenders then in effect). The aggregate commitments of the lenders is currently $100 million and can be increased to up to $300 million by either adding new lenders or increasing the commitments of existing lenders, subject to certain conditions. The next borrowing base redetermination is scheduled to occur by March 31, 2012. 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 80% 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 0.5% to 1.5% depending on total commitments) or the adjusted LIBO rate (“Eurodollar”) plus a margin (based on a sliding scale of 1.5% to 2.5% depending on total commitments). 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 based on a sliding scale of 0.375% to 0.5% depending on total commitments.

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. However, the Credit Agreement permits the Company to repurchase up to $10 million of the Company’s common stock during the term of the Credit Agreement, so long as after giving effect to such repurchase the Borrower’s Liquidity (as defined therein) is greater than 20% of the total commitments of the lenders at such time. As of December 31, 2011, the Company was in compliance with all of the covenants contained in the Credit Agreement.

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Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2011	Feb. 23, 2012	Jun. 30, 2011
Document and Entity Information [Abstract]
Entity Registrant Name	PETROQUEST ENERGY INC
Entity Central Index Key	0000872248
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Public Float			$ 302,000,000
Entity Common Stock, Shares Outstanding		64,096,164

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Related Party Transactions

12 Months Ended

Dec. 31, 2011

Related Party Transactions [Abstract]

Related Party Transactions

Note 10—Related Party Transactions

Three of the Company’s senior officers, Charles T. Goodson, Stephen H. Green, and Mark K. Stover, or their affiliates, are working interest owners and overriding royalty interest owners and E. Wayne Nordberg and William W. Rucks, IV, two of the Company’s directors, are working interest owners in certain properties operated by the Company or in which the Company also holds a working interest. As working interest owners, they are required to pay their proportionate share of all costs and are entitled to receive their proportionate share of revenues in the normal course of business. As overriding royalty interest owners they are entitled to receive their proportionate share of revenues in the normal course of business.

During 2011, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover or their affiliates, in the amounts of $293,000, $546,000 and $328,000 and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $9. During 2010, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover or their affiliates, in the amounts of $103,000, $520,000 and $261,000 and with respect to Mr. Nordberg, costs billed exceeded revenues disbursed in the amount of $100. No such disbursements were made to Mr. Rucks during 2011 and 2010. During 2009, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs, were disbursed to Messrs. Goodson, Green, Stover and Nordberg, or their affiliates, in the amounts of $218,000, $559,000, $64,000 and $7,000 and with respect to Mr. Rucks, costs in the amount of $43,000 were billed with no revenue disbursed. With respect to Mr. Goodson, gross revenues attributable to interests, properties or participation rights held by him prior to joining the Company as an officer and director on September 1, 1998 represent substantially all of the gross revenue received by him in 2011.

In its capacity as operator, the Company incurs drilling and operating costs that are billed to its partners based on their respective working interests. At December 31, 2011, the Company’s joint interest billing receivable included approximately $11,000 from the related parties discussed above or their affiliates, attributable to their share of costs. This represents less than 1% of the Company’s total joint interest billing receivable at December 31, 2011.

Periodically, the Company charters private aircraft for business purposes. During 2011, 2010 and 2009, the Company paid approximately $128,200, $169,400 and $13,500, respectively, to a third party operator in connection with the Company’s use of flight hours owned by Charles T. Goodson through a fractional ownership arrangement with the third party operator. These amounts represent the cost of the hours purchased by Mr. Goodson. The Company’s use of flight hours purchased by Mr. Goodson was pre-approved by the Company’s Audit Committee and there is no agreement or obligation by or on behalf of the Company to utilize this aircraft arrangement.

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Consolidated Statements of Operations (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues:
Oil and gas sales	$ 160,486	$ 179,038	$ 218,644
Gas gathering revenue	214	225	40
Total revenues	160,700	179,263	218,684
Expenses:
Lease operating expenses	38,571	39,012	38,541
Production taxes	3,100	4,917	4,656
Depreciation, depletion and amortization	58,243	59,326	84,772
Ceiling test writedown	18,907		156,134
General and administrative	20,436	21,341	18,869
Accretion of asset retirement obligation	2,049	1,306	2,452
Interest expense	9,648	9,952	12,615
Total expenses	150,954	135,854	318,039
Gain on legal settlement		12,400
Loss on early extinguishment of debt		(5,973)
Gain on sale of assets			485
Other expense	(1,008)	(1,080)	(5,955)
Income (loss) from operations	8,738	48,756	(104,825)
Income tax expense (benefit)	(1,810)	1,630	(14,635)
Net income (loss)	10,548	47,126	(90,190)
Preferred stock dividend	5,139	5,139	5,140
Net income (loss) available to common stockholders	$ 5,409	$ 41,987	$ (95,330)
Basic
Net income (loss) per share	$ 0.08	$ 0.67	$ (1.72)
Diluted
Net income (loss) per share	$ 0.08	$ 0.66	$ (1.72)
Weighted average number of common shares:
Basic	61,937	61,415	55,363
Diluted	62,325	61,789	55,363

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Woodford Joint Development Agreement

12 Months Ended

Dec. 31, 2011

Joint Development Agreement [Abstract]

Woodford Joint Development Agreement

Note 4—Woodford Joint Development Agreement

In May 2010, PetroQuest Energy, L.L.C. entered into a joint development agreement (“JDA”) with WSGP Gas Producing LLC (WSGP), a subsidiary of NextEra Energy Resources, LLC, whereby WSGP acquired approximately 29 Bcfe of the Company’s Woodford proved undeveloped reserves (PUDs) as well as the right to earn 50% of the Company’s undeveloped Woodford acreage position through a two phase drilling program. The Company received $57.4 million in cash at closing net of $2.6 million in fees incurred in relation to the transaction, and recorded a $14 million receivable for a contractual payment that was to be received in 2011. The Company received the $14 million contractual payment on November 30, 2011. The Company recorded the total consideration of approximately $71 million during 2010 as an adjustment to capitalized costs with no gain or loss recognized. Certain defined production performance metrics were achieved during the fourth quarter of 2011 and the Company received an additional $14 million during December 2011, which was also recorded as a reduction of capitalized costs. Additionally, since May 2010, WSGP has funded a share of the Company’s drilling costs under a long-term drilling program.

During February 2012, the Company amended its Woodford Shale JDA to accelerate the entry into Phase 2 of the drilling program effective March 1, 2012 and modify the drilling carry ratio. Under the amended JDA, the Phase 2 drilling carry has been expanded to provide for development in both the Mississippian Lime and the Woodford Shale plays whereby the Company will pay 25% of the cost to drill and complete wells and receive a 50% ownership interest. The Phase 2 drilling carry totals approximately $93 million and will be subject to extensions in one-year intervals.

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Common Stock Offering

12 Months Ended

Dec. 31, 2011

Common Stock Offering [Abstract]

Common Stock Offering

Note 3—Common Stock Offering

On June 30, 2009, the Company received $38 million in net proceeds through the public offering of 11.5 million shares of its common stock, which included the issuance of 1.5 million shares pursuant to the underwriters’ over-allotment option.

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Oil and Gas Reserve Information - Unaudited

12 Months Ended

Dec. 31, 2011

Investment in Oil and Gas Properties/Oil and Gas Reserve Information - Unaudited [Abstract]

Oil and Gas Reserve Information - Unaudited

Note 15—Oil and Gas Reserve Information—Unaudited

The Company’s net proved oil and gas reserves at December 31, 2011 have been estimated by independent petroleum engineers in accordance with guidelines established by the Securities and Exchange Commission.

The 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. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in providing the future rates of production and timing of development expenditures. The following reserve data represents estimates only and should not be construed as being exact. In addition, the present values should not be construed as the current market value of the Company’s oil and gas properties or the cost that would be incurred to obtain equivalent reserves.

On December 29, 2008, the SEC issued a revision to Staff Accounting Bulletin 113 (“SAB 113”) which established guidelines related to modernizing accounting and disclosure requirements for oil and natural gas companies. The revised disclosure requirements 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 revised rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The revised 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. A significant change to the rules involves the pricing at which reserves are measured. The revised rules utilize a historical 12-month average price based on 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 rather than year-end prices. In addition, the 12-month average is used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The revised rules are effective for reserve estimates beginning December 31, 2009.

During 2011, the Company’s estimated proved reserves increased by 38%. This increase was primarily due to a successful drilling program in Oklahoma in the Woodford Shale. Additionally, reserves increased due to positive performance revisions from the Company’s Oklahoma assets. In total, the Company added approximately 70 Bcfe of proved reserves in Oklahoma, 8 Bcfe from the La Cantera discovery and 9 Bcfe in the Carthage Field from horizontal drilling in the Cotton Valley during 2011. Overall, the Company had a 99% drilling success rate during 2011 on 118 gross wells drilled.

The following table sets forth an analysis of the Company’s estimated quantities of net proved and proved developed oil (including condensate) and gas reserves, all located onshore and offshore the continental United States:

		September 30,			September 30,			September 30,			September 30,
	Oil			NGL			Natural Gas			Total
	in			in			in			Reserves
	MBbls			MMcfe			MMcf			in MMcfe
Proved reserves as of December 31, 2008		2,201			13,405			158,781			185,392
Revisions of previous estimates		321			(664	)		(9,953	)		(8,691	)
Extensions, discoveries and other additions		9			300			39,003			39,357
Sale of reserves in place		—			—			(2,913	)		(2,913	)
Production		(600	)		(2,533	)		(28,065	)		(34,198	)
Proved reserves as of December 31, 2009		1,931			10,508			156,853			178,947
Revisions of previous estimates		187			187			20,958			22,267
Extensions, discoveries and other additions		168			150			47,681			48,839
Purchase of producing properties		—			—			2,336			2,336
Sale of reserves in place		—			—			(28,761	)		(28,761	)
Production		(663	)		(2,472	)		(24,501	)		(30,951	)
Proved reserves as of December 31, 2010		1,623			8,373			174,566			192,677
Revisions of previous estimates		(294	)		308			8,418			6,962
Extensions, discoveries and other additions		595			8,627			82,113			94,310
Purchase of producing properties		43			91			1,292			1,641
Sale of reserves in place		—			—			—			—
Production		(572	)		(2,288	)		(24,463	)		(30,183	)
Proved reserves as of December 31, 2011		1,395			15,111			241,926			265,407
Proved developed reserves
As of December 31, 2009		1,775			7,134			93,294			111,078
As of December 31, 2010		1,474			6,078			110,599			125,521
As of December 31, 2011		1,160			11,071			143,441			161,472
Proved undeveloped reserves
As of December 31, 2009		156			3,372			63,559			67,867
As of December 31, 2010		149			2,295			63,967			67,156
As of December 31, 2011		235			4,040			98,485			103,935

The following tables (amounts in thousands) present the standardized measure of future net cash flows related to proved oil and gas reserves together with changes therein, as defined by the FASB. Future production and development costs are based on current costs with no escalations. Estimated future cash flows have been discounted to their present values based on a 10% annual discount rate.

Standardized Measure

		September 30,			September 30,			September 30,
	December 31,
	2011			2010			2009
Future cash flows	$	1,080,392		$	810,131		$	614,293
Future production costs		(264,219	)		(223,175	)		(193,427	)
Future development costs		(180,846	)		(144,451	)		(148,595	)
Future income taxes		(86,612	)		(41,156	)		(3,166	)
Future net cash flows		548,715			401,349			269,105
10% annual discount		(244,834	)		(164,974	)		(94,817	)
Standardized measure of discounted future net cash flows	$	303,881		$	236,375		$	174,288

Changes in Standardized Measure

		September 30,			September 30,			September 30,
	Year Ended December 31,
	2011			2010			2009
Standarized measure at beginning of year	$	236,375		$	174,288		$	314,787
Sales and transfers of oil and gas produced, net of production costs		(116,398	)		(117,572	)		(95,555	)
Changes in price, net of future production costs		(10,219	)		93,702			(100,150	)
Extensions and discoveries, net of future production and development costs		178,901			42,028			2,790
Changes in estimated future development costs, net of development costs incurred during this period		915			5,803			38,407
Revisions of quantity estimates		11,236			46,373			(15,045	)
Accretion of discount		25,565			17,700			32,719
Net change in income taxes		(18,215	)		(16,568	)		9,698
Purchase of reserves in place		4,805			1,478			—
Sale of reserves in place		—			(798	)		(2,138	)
Changes in production rates (timing) and other		(9,084	)		(10,059	)		(11,225	)
Standardized measure at end of year	$	303,881		$	236,375		$	174,288

The weighted average prices of oil, ngls and gas used for the above tables at December 31, 2011, 2010 and 2009 were $101.42, $79.72 and $60.57 per barrel of oil, respectively, $8.62, $7.00 and $4.89 per Mcfe of natural gas liquids, respectively, and $3.34, $3.56 and $2.84 per Mcf of natural gas, respectively.

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Ceiling Test

12 Months Ended

Dec. 31, 2011

Ceiling Test [Abstract]

Ceiling Test

Note 11—Ceiling Test

The Company uses the full cost method to account for its oil and natural gas operations. Accordingly, the costs to acquire, explore for and develop oil and natural 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. The Company recorded $18.9 million and $156.1 million of ceiling test write-downs during 2011 and 2009, respectively. No such write-down occurred during 2010.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligations [Abstract]

Asset Retirement Obligations

Note 7—Asset Retirement Obligations

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 summarizes the changes to the Company’s asset retirement obligation liability (in thousands):

		September 30,			September 30,
	Years Ended December 31,
	2011			2010
Asset retirement obligation, beginning of period	$	24,592		$	23,916
Liabilities incurred		220			275
Liabilities settled		(905	)		(7,362	)
Accretion expense		2,049			1,306
Revisions in estimates		4,471			6,457
Asset retirement obligation, end of period		30,427			24,592
Less: current portion of asset retirement obligation		(3,110	)		(1,517	)
Long-term asset retirement obligation	$	27,317		$	23,075

Liabilities settled during 2010 included two offshore fields that were completely decommissioned and the liability for an additional offshore platform in the amount of $1.1 million that was transferred to a third party related to a farmout, which represents a non-cash investing activity for purposes of the Statement of Cash Flows. Revisions in estimates during 2011 and 2010 primarily represent increased cost estimates to decommission the Company’s offshore fields including platforms and pipelines and to plug and abandon the related wells.

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Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share

Note 5—Earnings Per Share

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

		September 30,			September 30,		September 30,
	Income			Shares		Per
For the Year Ended December 31, 2011	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	5,409			61,937
Attributable to participating securities		(154	)		—
BASIC EPS	$	5,255			61,937	$	0.08
Net income available to common stockholders	$	5,409			61,937
Effect of dilutive securities:
Stock options		—			388
Attributable to participating securities		(153	)		—
DILUTED EPS	$	5,256			62,325	$	0.08

		September 30,			September 30,		September 30,
	Income			Shares		Per
For the Year Ended December 31, 2010	(Numerator)			(Denominator)		Share Amount
Net income available to common stockholders	$	41,987			61,415
Attributable to participating securities		(1,029	)		—
BASIC EPS	$	40,958			61,415	$	0.67
Net income available to common stockholders	$	41,987			61,415
Effect of dilutive securities:
Stock options		—			374
Attributable to participating securities		(1,023	)		—
DILUTED EPS	$	40,964			61,789	$	0.66

		September 30,			September 30,		September 30,
	Loss			Shares		Per
For the Year Ended December 31, 2009	(Numerator)			(Denominator)		Share Amount
Net loss available to common stockholders	$	(95,330	)		55,363	$	(1.72	)
Effect of dilutive securities:
Stock options		—			—
Restricted stock		—			—
Series B preferred stock		—			—
DILUTED EPS	$	(95,330	)		55,363	$	(1.72	)

Common shares issuable upon the assumed conversion of the Series B preferred stock totaling 5,148,000 shares during 2011, 2010 and 2009 were not included in the computation of diluted earnings per share because the inclusion would have been anti-dilutive. No restricted stock or stock options were included in the computation of diluted earnings per share for the year ended December 31, 2009 because the inclusion would have been anti-dilutive as a result of the net loss reported for the year. Options to purchase 0.1 million and 1.7 million shares of common stock were outstanding during the year ended December 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.

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Share Based Compensation

12 Months Ended

Dec. 31, 2011

Share Based Compensation [Abstract]

Share Based Compensation

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 years ended December 31, 2011, 2010 and 2009 is as follows (in thousands):

		September 30,		September 30,		September 30,
	Years Ended
	December 31,
	2011		2010		2009
Stock options:
Incentive Stock Options	$	493	$	793	$	835
Non-Qualified Stock Options		703		2,081		2,024
Restricted stock		3,637		4,263		3,469
Share-based compensation	$	4,833	$	7,137	$	6,328

During the years ended December 31, 2011, 2010 and 2009, the Company recorded income tax benefits of approximately $1.6 million, $2.4 million and $2 million, respectively, related to share-based compensation expense recognized during those periods. Share-based compensation expense for the year ended December 31, 2010 included a charge of approximately $0.5 million related to the voluntary early cancellation of certain stock options and accelerated recognition of associated compensation expense. Any excess tax benefits from the vesting of restricted stock and the exercise of stock options will not be recognized in paid-in capital until the Company is in a current tax paying position. Presently, all of the Company’s income taxes are deferred and the Company has net operating losses available to carryover to future periods. Accordingly, no excess tax benefits have been recognized for any periods presented.

At December 31, 2011, the Company had $10.3 million of unrecognized compensation cost related to granted restricted stock and stock options. This amount will be recognized as an expense over a weighted average period of approximately two years.

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 and expected term based on historical activity 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.

The following table outlines the assumptions used in computing the fair value of stock options granted during 2011, 2010 and 2009:

		September 30,		September 30,		September 30,
	Years Ended December 31,
	2011		2010		2009
Dividend yield		0%		0%		0%
Expected volatility		78.5% - 79.7%		78.2% - 80.3%		75.5% - 78.4%
Risk-free rate		1.1% - 2.2%		1.5% - 3.0%		2.3% - 2.5%
Expected term		6 years		6 years		6 years
Forfeiture rate		5.0%		5.0%		5.0%
Stock options granted (1)		395,280		69,500		638,486
Wgtd. avg. grant date fair value per share	$	5.09	$	4.21	$	4.77
Fair value of grants (1)	$	2,011,000	$	293,000	$	3,045,000

(1) Prior to applying estimated forfeiture rate

The following table details stock option activity during the year ended December 31, 2011:

		September 30,			September 30,		September 30,		September 30,
	Number of Options			Wgtd. Avg. Exercise  Price		Wgtd. Avg. Remaining  Life		Aggregate Intrinsic  Value (000’s)
Outstanding at beginning of year		1,625,551		$	5.09
Granted		395,280			7.49
Expired/cancelled/forfeited		(39,756	)		8.77
Exercised		(58,667	)		3.45
Outstanding at end of year		1,922,408			5.56		5.69 years	$	2,699
Options exercisable at end of year		1,283,674		$	4.73		4.09 years	$	2,653
Options expected to vest		606,797			7.23		8.89 years	$	44

The intrinsic value of options exercised was immaterial for all periods presented.

The following table summarizes information regarding stock options outstanding at December 31, 2011:

		September 30,		September 30,		September 30,		September 30,		September 30,
Range of	Options		Wgtd. Avg.		Wgtd. Avg.		Options		Wgtd. Avg.
Exercise	Outstanding		Remaining		Exercise		Exercisable		Exercise
Price	12/31/11		Contractual Life		Price		12/31/11		Price
$0.0—$3.17		508,167		2.0 years	$	2.95		508,167	$	2.95
$3.17—$5.91		339,065		3.3 years	$	4.24		312,398	$	4.14
$5.91—$7.08		681,896		7.4 years	$	6.99		453,109	$	7.01
$7.08—$9.99		393,280		9.5 years	$	7.59		10,000	$	9.99
		1,922,408		5.7 years	$	5.56		1,283,674	$	4.73

Restricted Stock

The Company computes the fair value of its service based restricted stock using the closing price of the Company’s stock at the date of grant, and compensation expense is recognized assuming a 5% estimated forfeiture rate. Restricted stock granted to employees prior to 2011 generally vests over a five-year period with one-fourth vesting on each of the first, second, third and fifth anniversaries of the date of the grant. No portion of the restricted stock vests on the fourth anniversary of the date of the grant. Restricted stock granted to directors generally vests evenly over a three year period. Beginning January 1, 2011, restricted stock granted to employees generally vests evenly over a three year period. 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.

The following table details restricted stock activity during 2011:

		September 30,			September 30,
	Number of Shares			Wgtd. Avg. Fair Value  per Share
Outstanding at beginning of year		1,638,809		$	6.57
Granted		1,134,917			7.54
Expired/cancelled/forfeited		(88,416	)		5.04
Lapse of restrictions		(696,708	)		8.01
Outstanding at December 31, 2011		1,988,602		$	6.69

At December 31, 2011, the weighted average remaining life of restricted stock outstanding was three years and the intrinsic value of restricted stock outstanding, using the closing stock price on December 31, 2011, was $13.1 million.

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Derivatives

12 Months Ended

Dec. 31, 2011

Derivatives [Abstract]

Derivatives

Note 8—Derivatives

As of December 31, 2011, the Company had entered into the following natural gas contract accounted for as a cash flow hedge:

	Instrument			Weighted
Production Period	Type	Daily Volumes		Average Price
Natural Gas:
2012	Costless Collar		10,000 Mmbtu		$5.00—5.29

At December 31, 2011, the Company had an asset of $6.4 million related to the estimated fair value of this derivative instrument. Based on estimated future commodity prices as of December 31, 2011, the Company would realize a $4 million gain, net of taxes, as an increase to gas sales during the next 12 months. This gain is expected to be reclassified based on the schedule of oil and gas volumes stipulated in the derivative contract.

Oil and gas sales include additions (reductions) related to the settlement of gas hedges of $2,609,000, $17,538,000 and $74,333,000 and oil hedges of ($192,000), zero and $5,559,000 for the years ended December 31, 2011, 2010 and 2009, respectively.

During January 2012, the Company entered into the following additional oil and gas hedge contracts accounted for as cash flow hedges:

		September 30,		September 30,		September 30,
	Instrument				Weighted
Production Period	Type		Daily Volumes		Average Price
Natural Gas:
March—October 2012		Swap		20,000 Mmbtu	$	2.60
Crude Oil:
February—December 2012		Swap		250 Bbl	$	100.77

All of the Company’s derivative instruments at December 31, 2011 and 2010 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 as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 (in thousands):

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

	September 30,		September 30,
	Commodity Derivatives
	Balance Sheet
Period	Location	Fair Value
December 31, 2011	Hedging asset	$	6,418
December 31, 2010	Hedging liability	$	(1,089	)

Effect of Derivative Instruments on the Consolidated Statement of Operations for the twelve months ended December 31, 2011, 2010 and 2009:

		September 30,		September 30,		September 30,
	Commodity Derivatives
	Amount of Gain (Loss)			Location of	Amount of Gain
	Recognized in Other			Gain Reclassified	Reclassified into
Period	Comprehensive Income (Loss)			into Income	Income
December 31, 2011	$	5,120		Oil and gas sales	$	2,417
December 31, 2010	$	(2,857	)	Oil and gas sales	$	17,538
December 31, 2009	$	(23,792	)	Oil and gas sales	$	79,892

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 instrument at December 31, 2011 is in the form of a costless collar based on NYMEX pricing. The fair value of this derivative 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 valuation of the Company’s derivatives subject to fair value measurement on a recurring basis as of December 31, 2011 and 2010 (in thousands):

		September 30,		September 30,			September 30,
	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—2011		—	$	6,418			—
Commodity Derivatives—2010		—	$	(1,089	)		—

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Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Income Taxes

Note 13—Income Taxes

The Company follows the provisions of ASC Topic 740, which provides for recognition of deferred tax assets and liabilities for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards, net of a valuation allowance for any asset for which it is more likely than not will not be realized in the Company’s tax return. As a result of the ceiling test write-downs during 2009 and 2008, 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 with respect to a portion of its deferred tax assets. The valuation allowance was $3.2 million and $23.3 million as of December 31, 2010 and 2009, respectively. During 2011, the Company reversed the remaining valuation allowance as future reversals of existing deferred tax liabilities were sufficient to realize the entire deferred tax asset.

An analysis of the Company’s deferred taxes follows (amounts in thousands):

		September 30,			September 30,
	December 31,
	2011			2010
Net operating loss carryforwards	$	2,409		$	4,737
Percentage depletion carryforward		6,103			3,596
Alternative minimum tax credit		784			776
Contributions carryforward and other		130			90
Temporary differences:
Oil and gas properties—full cost		(10,541	)		(10,141	)
Hedges		(2,388	)		405
Share-based compensation		2,952			3,732
Valuation allowance		—			(3,195	)
Deferred tax liability	$	(551	)	$	—

At December 31, 2011, the Company had approximately $17,973,000 of operating loss carryforwards, of which $11,497,000 relates to excess tax benefits with respect to share-based compensation that have not been recognized in the financial statements. If not utilized, approximately $8,732,000 of such carryforwards would expire in 2025 and the remainder would expire by the year 2031. The Company has available for tax reporting purposes $17,437,000 in statutory depletion deductions that may be carried forward indefinitely.

Income tax expense (benefit) for each of the years ended December 31, 2011, 2010 and 2009 was different than the amount computed using the Federal statutory rate (35%) for the following reasons (amounts in thousands):

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Amount computed using the statutory rate	$	3,058		$	17,065		$	(36,689	)
Increase (reduction) in taxes resulting from:
State & local taxes		192			1,073			(2,306	)
Percentage depletion carryforward		(2,507	)		(252	)		(725	)
Allowance for alternative minimum tax		8			575			—
Non-deductible stock option expense (1)		183			295			311
Share-based compensation (2)		346			3,041			1,334
Other		(300	)		321			161
Change in valuation allowance		(2,790	)		(20,488	)		23,279
Income tax expense (benefit)	$	(1,810	)	$	1,630		$	(14,635	)

(1) Relates to compensation expense recognized on the vesting of Incentive Stock Options

(2) Relates to the write-off of deferred tax assets associated with share based compensation that will not be recognized for tax purposes.

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income (loss)	$ 10,548	$ 47,126	$ (90,190)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Deferred tax expense (benefit)	(1,810)	1,630	(14,635)
Depreciation, depletion and amortization	58,243	59,326	84,772
Ceiling test writedown	18,907		156,134
Non-cash gain on legal settlement		(4,164)
Loss on early extinguishment of debt		5,973
Gain on sale of assets			(485)
Accretion of asset retirement obligation	2,049	1,306	2,452
Pipe inventory impairment			913
Share-based compensation expense	4,833	7,137	6,328
Amortization costs and other	625	1,334	1,512
Payments to settle asset retirement obligations	(905)	(6,274)	(1,803)
Changes in working capital accounts:
Revenue receivable	(2,474)	3,071	3,617
Joint interest billing receivable	(35,252)	(401)	11,937
Prepaid drilling and pipe costs	5,530	9,180	14,828
Accounts payable and accrued liabilities	34,599	3,368	(51,375)
Advances from co-owners	25,904	4,301	(1,687)
Other	(2,907)	(1,269)	(496)
Net cash provided by operating activities	117,890	131,644	121,822
Cash flows from investing activities:
Investment in oil and gas properties	(194,536)	(103,926)	(63,420)
Investment in gas gathering assets			(204)
Proceeds from sale of unevaluated properties	28,461	22,473
Proceeds from sale of oil and gas properties and other	14,000	35,000	7,451
Net cash used in investing activities	(152,075)	(46,453)	(56,173)
Cash flows from financing activities:
Net payments for share based compensation	(1,133)	(210)	(366)
Deferred financing costs	(517)	(12)	(114)
Proceeds from common stock offering			38,036
Costs of common stock offering			(258)
Payment of preferred stock dividend	(5,139)	(5,137)	(5,139)
Repayment of bank borrowings	(22,000)	(29,000)	(101,000)
Proceeds from bank borrowings	22,000
Redemption of 10 3/8% Senior Notes		(150,000)
Costs to redeem 10 3/8% Senior Notes		(4,187)
Proceeds from issuance of 10% Senior Notes		150,000
Costs to issue 10% Senior Notes		(4,180)
Net cash used in financing activities	(6,789)	(42,726)	(68,841)
Net increase (decrease) in cash and cash equivalents	(40,974)	42,465	(3,192)
Cash and cash equivalents at beginning of period	63,237	20,772	23,964
Cash and cash equivalents at end of period	22,263	63,237	20,772
Cash paid during the period for:
Interest	16,017	11,195	20,335
Income taxes	$ 51	$ 192	$ 227

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Convertible Preferred Stock

12 Months Ended

Dec. 31, 2011

Convertible Preferred Stock [Abstract]

Convertible Preferred Stock

Note 2—Convertible Preferred Stock

During 2007, the Company completed the public offering of 1,495,000 shares of its 6.875% Series B cumulative convertible perpetual preferred stock (the “Series B Preferred Stock”).

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

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

Mandatory conversion. After October 20, 2010, 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.

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Investment in Oil and Gas Properties

12 Months Ended

Dec. 31, 2011

Investment in Oil and Gas Properties/Oil and Gas Reserve Information - Unaudited [Abstract]

Investment in Oil and Gas Properties

Note 12—Investment in Oil and Gas Properties

The following tables disclose certain financial data relative to the Company’s oil and gas producing activities, which are located onshore and offshore the continental United States:

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

(amounts in thousands)

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Acquisition costs:
Proved	$	2,720		$	10,421		$	427
Unproved		43,207			11,310			1,592
Divestitures—unproved (1)		(14,461	)		(36,139	)		—
Exploration costs:
Proved		92,466			34,310			16,495
Unproved		5,919			10,384			3,249
Development costs		34,400			34,286			19,333
Capitalized general and administrative and interest costs		18,210			19,665			18,009
Total costs incurred	$	182,461		$	84,237		$	59,105

		September 30,			September 30,			September 30,
	For the Year-Ended December 31,
	2011			2010			2009
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(1,175,553	)	$	(1,082,381	)	$	(832,290	)
Provision for DD&A		(57,143	)		(58,172	)		(83,613	)
Ceiling test writedown		(18,907	)		—			(156,134	)
Sale of proved properties and other (1)		(14,000	)		(35,000	)		(10,344	)
Balance, end of year	$	(1,265,603	)	$	(1,175,553	)	$	(1,082,381	)
DD&A per Mcfe	$	1.89		$	1.88		$	2.44

(1) During 2010, the Company recorded $71 million in consideration from its Woodford joint development agreement. During 2011, the Company received an additional $14 million payment associated with the achievement of certain production metrics stipulated under the joint development agreement (See Note 4). In addition, during 2011, the Company sold a portion of its unproved Mississippian Lime acreage for $14.5 million.

At December 31, 2011 and 2010, unevaluated oil and gas properties totaled $70,408,000 and $54,851,000, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2011 included $5,919,000 of costs related to 44 exploratory wells in progress at year-end. These costs will be transferred to evaluated oil and gas properties during 2012 upon the completion of drilling. At December 31, 2010, unevaluated costs included $10,384,000 related to 28 exploratory wells in progress. All of these costs were transferred to evaluated oil and gas properties during 2011. The Company capitalized $7,034,000, $7,771,000 and $8,679,000 of interest during 2011, 2010 and 2009, respectively. Of the total unevaluated oil and gas property costs of $70,408,000 at December 31, 2011, $38,918,000 or 55%, was incurred in 2011, $11,316,000, or 16%, was incurred in 2010 and $20,174,000 or 29% was incurred in prior years. The Company expects that the majority of the unevaluated costs at December 31, 2011 will be evaluated within the next three years, including $24,186,000 that the Company expects to be evaluated during 2012.