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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2005


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

For the transition period from to

Commission File Number: 001-32681

PETROQUEST ENERGY, INC.

(Exact name of registrant as specified in its charter)


State of incorporation: Delaware				I.R.S. Employer Identification No. 72-1440714

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.

o Yes þ 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.

o Yes þ 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.

þ Yes o No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) 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. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act. (Check one):

o Large accelerated filer þ Accelerated filer o Non-accelerated filer

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

o Yes þ No

The aggregate market value of the voting common equity held by non-affiliates of the registrant was $293,582,993 as of June 30, 2005 (based on the last reported sale price of such stock on such date on The Nasdaq National Market System).

As of March 1, 2006, the registrant had outstanding 47,325,291 shares of Common Stock, par value $.001 per share.

Document incorporated by reference: Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held on May 16, 2006, which is incorporated by reference into Part III of this Form 10-K.

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 include, without limitation, statements regarding our estimate of the sufficiency of our existing capital resources and our ability to raise additional capital to fund cash requirements for future operations, and regarding the uncertainties involved in estimating quantities of proved oil and natural gas reserves, in prospect development and property acquisitions and in projecting future rates of production, timing of development expenditures and drilling of wells and the operating hazards attendant to the oil and gas business. 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.

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. Before you invest in our common stock, 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 39.

PART I

ITEM 1. BUSINESS

Overview

PetroQuest Energy, Inc. is an independent oil and gas company incorporated in the State of Delaware with operations in the Gulf Coast Basin, Oklahoma and Texas. We seek to grow our proved reserves, production, cash flow and earnings at low finding and development costs through a balanced mix of exploration, development and acquisition activities. We were successful in 2005 in achieving company records for proved reserves, production, cash flow from operating activities and net income. During 2005, we increased these operational and financial metrics by 29%, 13%, 4% and 31%, respectively, from 2004 levels.

From the commencement of our operations in 1985 through 2002, we focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow Gulf of Mexico shelf. Beginning in 2003, we began diversifying our reserves and production with longer life onshore properties in Texas and Oklahoma, and we enhanced our risk management policies by reducing our average working interest in projects, shifting capital to higher probability onshore wells and reducing the risks associated with individual wells by expanding our drilling program. In particular, in 2003 we acquired properties in the Southeast Carthage Field in East Texas with 29 Bcfe of proved reserves. In 2004, we entered the Arkoma Basin in Oklahoma by building an acreage position, drilling wells and acquiring 10.5 Bcfe of proved reserves. During 2005, we further increased our presence in Oklahoma through multiple acquisition

transactions and an expanded drilling program. To complement our increased operational activity, since December 2003 we have increased our staff by 43%, including adding personnel with expertise and knowledge specific to these regions dedicated to evaluating and exploiting these properties.

Business Strategy

Concentrate in Core Operating Areas and Build Scale. We plan to continue focusing our operations in the Gulf Coast Basin, Oklahoma and Texas, and to continue to build scale, particularly in the longer life onshore regions, through drilling and complementary acquisition activities. Operating in concentrated areas helps us to 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, coupled 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.

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 and exploitation activities and higher risk and higher impact exploration activities. In addition, we will continue to pursue strategic acquisitions aimed at geographically and operationally diversifying our asset base and increasing our inventory of drilling projects. Through our portfolio diversification efforts, at December 31, 2005, approximately 50% of our reserves were located in longer life onshore regions such as Oklahoma and Texas and 50% were located in the shorter life, but higher flow rate reservoirs in the Gulf Coast Basin. This compares to 45% of our proved reserves located in long life basins at December 31, 2004 and 35% at December 31, 2003. In terms of production diversification, during 2005, 30% of our production was derived from longer life basins versus 16% during 2004 and virtually none in 2003. We will continue to seek opportunities to achieve a balance between our longer life onshore reserves and our shorter life Gulf Coast reserves.

Manage Our Risk Exposure. We plan to continue several programs to mitigate our operating risks. Since 2003, we have aligned the working interest we are willing to hold based on the risk level and cost exposure of each project. 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, exploitation and development activities. For example, we typically reduce our working interest on higher risk exploration projects while retaining greater working interests in lower risk development projects. We also retain operating control of the majority of our properties to control costs and timing of expenditures. In addition, 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.

Target Underexploited Properties with Substantial Opportunity for Upside. We plan to continue using a rigorous prospect selection process that enables us to leverage our operating and technical experience in our core operating regions. We intend to target properties with an established production history that may benefit from the latest exploration, drilling, fracturing and operating techniques to more efficiently find, produce and develop oil and gas reserves. In addition, we plan to continue targeting properties with existing infrastructure that provide additional acreage for future development and exploitation opportunities.

Maintain Our Financial Flexibility. We intend to maintain a disciplined approach to financial management and a strong capital structure to execute our business plan. Historically, key components of our financial discipline have typically included funding expected exploration and development activities with cash flows from operations, establishing appropriate leverage ratios given the volatility of commodity prices, maintaining an active commodity hedging program and accessing the equity capital markets as appropriate. We may also consider opportunistically disposing of assets to provide capital for higher potential exploration and development properties that are more important to our long-term growth.

2005 Financial and Operational Summary

During 2005, we invested approximately $196 million in exploratory, development and acquisition activities as we drilled a company record 35 gross exploratory wells and 51 gross development wells realizing an overall success rate of 91% on our 2005 drilling program. This investment represented a 128% increase from our 2004 capital expenditures and resulted in a 161% increase in the number of gross wells drilled. Of our total 2005 capital expenditures, acquisition costs totaled approximately $82 million. To finance these acquisitions and to repay borrowings outstanding under our credit facilities, during 2005 we issued $150 million of 10 3/8% Senior Notes due 2012. Following the issuance of the senior notes we repaid and terminated our subordinated debt credit facility and in December 2005 we amended our bank credit facility increasing the borrowing base to $40 million, of which $30 million was available at December 31, 2005.

Production during 2005, even though reduced during the latter half of 2005 due to hurricanes, increased 13% to a company record 16.1 Bcfe. Our estimated proved reserves at December 31, 2005 totaled 3,642 MBbls of oil and 109,115 MMcfe of natural gas, with pre-tax present value discounted at 10% of the estimated future net revenues based on constant prices in effect at year-end (“discounted cash flow”) of $639.7 million. At December 31, 2005, we operated approximately 60% of our total estimated proved reserves and managed the drilling and completion activities on an additional 29% of our proved reserves.

Gulf Coast Basin

South Chauvin Field. During 2005, we invested $17.9 million in this field and drilled four exploratory wells, all of which were successful. Production from the field commenced during 2005 and averaged 11.6 MMcfe per day during December 2005. We expect to drill two additional wells in the field during 2006.

Gibson Field. In January 2006, we announced a discovery at our Pelican Point Prospect. While reserves from this discovery were booked in 2006, capital expenditures during 2005 related to this well, which was in progress at December 31, 2005, totaled $6 million. We expect this discovery to be delineated through additional drilling during 2006 with production from the initial well expected to commence in April 2006.

Oklahoma

During 2005, we acquired several primarily natural gas properties for approximately $36 million. We also drilled 58 gross wells on our Oklahoma properties during 2005 achieving a 90% success rate. In total, we invested $62 million in Oklahoma assets during 2005 or approximately 32% of our total 2005 capital expenditures. As a result, we were able to grow average daily production in 2005 from our Oklahoma properties to 4.6 MMcfe, a 566% increase from our 2004 average daily production. In addition to growing production, our 2005 investments also increased the estimated proved reserves attributable to our Oklahoma properties by 55% from December 31, 2004. We expect to drill 109 wells in Oklahoma in 2006 and we will continue to evaluate acquisition opportunities.

Texas

SE Carthage Field. During December 2003, we acquired working interests in approximately 41,000 acres in this field, which had approximately 80 producing wells. During 2005, we invested $30.4 million on the successful drilling of 15 wells. Net production from this field averaged 11.5 MMcfe per day during December 2005, a 117% increase from December 2004, and proved reserves increased 38% from December 31, 2004. During 2006, we expect to drill 20 wells in this field.

Markets and Customers

We sell our natural gas and oil production under fixed or floating market contracts. Customers purchase all of our natural gas and oil production at current market prices. The terms of the arrangement 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 gas from our wells depends upon numerous factors beyond our control, including:

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

	•		the proximity of the gas production to gas pipelines;

	•		the availability of capacity in such pipelines;

	•		the demand for oil and 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 gas production, and

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

No assurance can be given that we will be able to market all of the oil or gas we produce or that favorable prices can be obtained for the oil and gas we produce.

In view of the many uncertainties affecting the supply and demand for oil, gas and refined petroleum products, we are unable to predict future oil and gas prices and demand or the overall effect such prices and demand will have on the Company. For the year ended December 31, 2005, we had three customers who accounted for 20%, 16% and 12% of our oil and gas revenue, respectively. For the year ended December 31, 2004, we had two customers who accounted for 26% and 24% of our oil and gas revenue, respectively and for the year ended December 31, 2003, we had three customers who accounted for 27%, 24% and 12% of our oil and gas revenue, respectively. These percentages do not consider the effects of financial hedges. We do not believe that the loss of any of our oil or gas purchasers would have a material adverse effect on our operations due to the availability of other purchasers.

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.

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 tightening of natural gas supply and demand fundamentals has resulted in extremely volatile natural gas prices, which is expected to continue.

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. The FERC indicated in Order No. 561 that it will assess in 2000 how the rate-indexing method is operating. The FERC issued a Notice of Inquiry on July 27, 2000 seeking comment on whether to retain or to change the existing index. After consideration of the initial and reply comments, the FERC concluded on December 14, 2000 that the PPI-1 index has reasonably approximated the actual cost changes in the oil pipeline industry during the preceding five year period, and that it should be continued for the subsequent five year period.

Federal Leases. We maintain operations located on federal oil and gas leases, which are administered by the Minerals Management Service pursuant to the Outer Continental Shelf Lands Act. These leases are issued through competitive bidding and contain relatively standardized terms. These leases require compliance with detailed Minerals Management Service regulations and orders that are subject to interpretation and change by the Minerals Management Service.

For offshore operations, lessees must obtain Minerals Management Service approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency, lessees must obtain a permit from the Minerals Management Service prior to the commencement of drilling. The Minerals Management Service has promulgated regulations requiring offshore production facilities located on the Outer Continental Shelf to meet stringent engineering and construction specifications. The Minerals Management Service also has regulations restricting the flaring or venting of natural gas, and has proposed to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. Similarly, the Minerals Management Service has promulgated other regulations governing the plugging and abandonment of wells located offshore and the installation and removal of all production facilities.

To cover the various obligations of lessees on the Outer Continental Shelf, the Minerals Management Service generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of these bonds or assurances can be substantial, and there is no assurance that they can be obtained in all cases. Under some circumstances, the Minerals Management Service may require operations on federal leases to be suspended or terminated.

The Minerals Management Service also administers the collection of royalties under the terms of the Outer Continental Shelf Lands Act and the oil and gas leases issued under the Act. The amount of royalties due is based upon the terms of the oil and gas leases as well as of the regulations promulgated by the Minerals Management Service. These regulations are amended from time to time, and the amendments can affect the amount of royalties that we are obligated to pay to the Minerals Management Service. However, we do not believe that these regulations or any future amendments will affect us in a way that materially differs from the way it affects other oil and gas producers, gatherers and marketers.

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 Minerals Management Service 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. There are legislative proposals pending in the various state legislatures which, 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.

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 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 (“EPA”). Such regulation can increase the cost of planning, designing, installation and operation of such facilities. In most instances, the regulatory requirements relate to water and air pollution control measures. 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 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. We had no control over such entities’ 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, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The EPA has limited the disposal options for certain hazardous wastes. Furthermore, it is possible that certain wastes currently exempt from regulation as “hazardous wastes” generated by our oil and gas operations 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.

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 the hazardous substances at a

site. CERCLA also authorizes the EPA 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. Neither we nor our predecessors have been designated as a potentially responsible party by the EPA or a state under CERCLA or a similar state law with respect to any such site.

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 believe we currently have established adequate financial responsibility. While financial responsibility requirements under OPA may be amended to impose additional costs on us, the impact of any change in these requirements should not be any more burdensome to us than to others similarly situated.

Clean Water Act. 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.

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.

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 41,000 square feet of leased space, with an exploration office in Houston, Texas, in approximately 5,500 square feet 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 63 employees as of December 31, 2005. 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 “Investor Relations” 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. Also available on our website is our Code of Business Conduct and Ethics and our Corporate Governance Guidelines.

ITEM 1A. RISK FACTORS

Risks Related to Our Business, Industry and Strategy

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

As is generally the case in the Gulf Coast Basin where the majority of our current production is located, many of our producing properties are characterized by a high initial production rate, followed by a steep decline in production. 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, which would have a material adverse effect on our financial condition.

Oil and natural gas prices are volatile, and a substantial and extended decline in the prices of oil and natural gas would likely have a material adverse effect on our financial condition.

Our revenues, results of operations, profitability and future growth, and the carrying value of our oil and natural gas properties, depend to a large degree on prevailing oil and natural gas prices. 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 oil and natural gas are subject to large fluctuations in response to a variety of other factors beyond our control.

These factors include:

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

	•		market uncertainty;

	•		the level of consumer product demand;

	•		weather conditions in the United States, such as hurricanes;

	•		the condition of the United States and worldwide economies;

	•		the actions of the Organization of Petroleum Exporting Countries;

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

	•		political instability in the Middle East and elsewhere;

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

	•		the price and availability of alternate fuel sources.

At various times, excess domestic and imported supplies have depressed oil and natural gas prices. We cannot predict future oil and natural gas prices and such prices may decline. Declines 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 may also reduce the amount of oil and natural gas that we can produce economically and require us to record ceiling test write-downs when prices decline. 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 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.

A substantial portion of our operations is exposed to the additional risk of tropical weather disturbances.

A substantial portion of our production and reserves is located in Federal waters offshore, onshore South Louisiana and Texas. For example, production from our Ship Shoal 72 field, which is located offshore Louisiana, represented approximately 29% of our total 2005 production. Operations in this area are subject to tropical weather disturbances. Some of these disturbances can be severe enough to cause substantial damage to facilities and possibly interrupt production. For example, Hurricanes Katrina and Rita impacted our South Louisiana and Texas operations in August and September of 2005, respectively, causing property damage to certain facilities, a substantial portion of which is expected to be covered by insurance. As a result, a portion of our oil and gas production was shut-in reducing our overall production volumes in the third and fourth quarters of 2005. In addition, production from our Main Pass 74 field, which represented approximately 11% of our 2004 production, was shut-in from September 2004 to January 2006 due to third party pipeline damage associated with Hurricane Ivan in September 2004. In accordance with customary industry practices, we maintain insurance against some, but not all, of these risks.

Losses could occur for uninsured risks or in amounts in excess of existing insurance coverage. We cannot assure you that we will be able to maintain adequate insurance in the future at rates we consider reasonable or that any particular types of coverage will be available. An event that is not fully covered by insurance could have a material adverse effect on our financial position and results of operations.

Shortage of rigs, equipment, supplies or personnel may restrict our operations.

The oil and gas industry is cyclical, and at the present time, there is a shortage of drilling rigs, equipment, supplies and personnel. The costs and delivery times of rigs, equipment and supplies has increased in recent months as oil and natural gas prices have continued to rise. In addition, demand for, and wage rates of, qualified drilling rig crews have risen with increases in the number of active rigs in service. Shortages of drilling rigs, equipment, supplies or personnel could delay or restrict our exploration and development operations, which in turn could impair our financial condition and results of operations.

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 natural gas and oil prices and to achieve more predictable cash flow. These financial arrangements take the form of costless collars or swap contracts and are placed with major trading counterparties whom we believe represent minimum credit risks. We cannot assure you that these trading 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 contract 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 natural gas and oil. For example, during 2005, oil and gas hedges reduced our total oil and gas sales by approximately $15.8 million. We cannot assure you that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in natural gas and oil prices.

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, 2005, the aggregate amount of our outstanding indebtedness was $158.3 million, which could have important consequences for you, including the following:

	•		it may be more difficult for us to satisfy our obligations with respect to our 10 3/8% senior notes due 2012, which we refer to as the our 10 3/8% notes, and any failure to comply with the obligations of any of our debt agreements, including financial and other restrictive covenants, could result in an event of default under the indenture governing our 10 3/8% notes and the agreements governing such other indebtedness;

	•		the covenants contained in our debt agreements limit our ability to borrow money in the future for acquisitions, capital expenditures or to meet our operating expenses or other general corporate obligations;

	•		we will need to use a substantial portion of our cash flows to pay principal and interest on our debt, approximately $15.6 million per year for interest on our 10 3/8% notes alone, which will reduce the amount of money we have for operations, capital expenditures, expansion, acquisitions or general corporate or other business activities;

	•		the amount of our interest expense may increase because certain of our borrowings are at variable rates of interest, which, if interest rates increase, could result in higher interest expense;

	•		we 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 declines in oil and natural gas prices; and

	•		our debt level could limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate.

We may incur from time to time debt under our bank credit facility. The borrowing base limitation under our bank credit facility is periodically redetermined and upon such redetermination, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make such repayments.

Our ability to meet our expenses and debt obligations will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors. We will not be able to control many of these factors, such as economic conditions and governmental regulation. We cannot be certain that our cash flow from operations will be sufficient to allow us to pay the principal and interest on our debt, including our 10 3/8% notes, and meet our other obligations. If we do not have enough money to service our debt, we may be required to refinance all or part of our existing debt, including our 10 3/8% notes, sell assets, borrow more money or raise equity. We may not be able to refinance our debt, sell assets, borrow more money or raise equity on terms acceptable to us, if at all.

We may incur substantially more debt, which may intensify the risks described above, including our ability to service our indebtedness.

Together with our subsidiaries, we may be able to incur substantially more debt in the future in connection with our acquisition, development, exploitation and exploration of oil and natural gas producing properties. Although the indenture governing our 10 3/8% notes contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness. As of December 31, 2005, we had $10 million outstanding under our bank credit facility and our borrowing base was $40 million. To the extent we add new indebtedness to our current indebtedness levels, the risks described above could substantially increase.

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 3/8% notes, and to fund planned capital expenditures will depend on our ability to generate sufficient cash flow from operations in the future. This, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, including the prices that we receive for oil and natural gas.

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 3/8% 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 effected 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 3/8% 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.

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 operation may be adversely affected.

We may be unable to overcome risks associated with our drilling activity.

Our drilling involves numerous risks, including the risk that we will drill a dry hole or otherwise not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to identify and acquire properties and to drill and complete wells. The costs of drilling and completing wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including unexpected drilling conditions, pressure or irregularities in formations, equipment failures or accidents, weather conditions and shortages or delays in the delivery of equipment and personnel. While we use advanced technology in our operations, this technology does not allow us to know conclusively prior to drilling a well that oil or natural gas is present or economically recoverable.

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

Our operations are dependent upon a relatively small group of key management and technical personnel, including Charles T. Goodson, our Chairman, Chief Executive Officer and President, Dalton F. Smith, III, our Senior Vice President-Business Development & Land, Stephen H. Green, our Senior Vice President-Exploration, and Arthur M. Mixon, our Senior Vice President-Operations. In addition, we employ numerous other highly technical personnel, including geologists and geophysicists 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 a detrimental effect on our operations.

There is presently a shortage of qualified geologists and geophysicists necessary to fill our requirements and the requirements of the oil and gas industry, and the market for such individuals is highly competitive. Our inability to hire or retain the services of such individuals could have a detrimental effect on our operations.

You should not place undue reliance on reserve information because reserve information represents estimates.

This document contains estimates of historical oil and natural gas reserves, and the historical estimated future net cash flows attributable to those reserves, prepared by Ryder Scott Company, L.P., our independent petroleum and geological engineers. Our estimate of proved reserves is based on the quantities of oil, gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

There are, however, numerous uncertainties inherent in estimating quantities of proved reserves and cash flows from such reserves, including factors beyond our control and the control of Ryder Scott. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to these reserves, is a function of:

	•		the available data;

	•		assumptions regarding future oil and natural gas prices;

	•		estimated expenditures for future development and exploitation activities; and

	•		engineering and geological interpretation and judgment.

Reserves and future cash flows may also be subject to material downward or upward revisions based upon production history, development and exploitation activities and oil and natural gas prices. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from those reserves may vary significantly from the assumptions and estimates in this prospectus. In calculating reserves on an Mcfe basis, oil and natural gas liquids were converted to natural gas equivalent at the ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquid.

Approximately 31% of our estimated proved reserves at December 31, 2005 are undeveloped and 32% are developed, non-producing. Estimates of undeveloped and non-producing reserves, by their nature, are less certain. 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.

You should not assume that the present value of future net revenues referred to in this prospectus is the current market value of our estimated oil and natural gas reserves. In accordance with Commission requirements, the estimated discounted future net cash flows from proved reserves are based on prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. Any changes in consumption by 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 the timing of actual future net cash flows from proved reserves and their present value. In addition, the 10% discount factor, which is required by the Commission to be used in calculating discounted future net cash flows for reporting purposes, is not necessarily the most accurate 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 a due diligence review (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.

We may not be able to obtain adequate financing to execute our operating strategy.

Our ability to execute our operating strategy is highly dependent on our having access to capital. We have historically addressed our long-term liquidity needs through the use of bank credit facilities, second lien term credit facilities, the issuance of equity and debt securities and the use of cash provided by operating activities. We will continue to examine the following alternative sources of long-term capital:

	•		borrowings from banks or other lenders;

	•		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 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 operating performance. We may be unable to execute our operating strategy if we cannot obtain capital from these sources.

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 3/8% notes contain a number of significant covenants that, among other things, restrict our ability to:

	•		dispose of assets;

	•		incur or guarantee additional indebtedness and issue certain types of preferred stock;

	•		pay dividends on our capital stock;

	•		create liens on our assets;

	•		enter into sale and leaseback transactions;

	•		enter into specified investments or acquisitions;

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

	•		merge or consolidate, or transfer all or substantially all of our assets and the assets of our subsidiaries;

	•		engage in specified transactions with subsidiaries and affiliates; or

•

other corporate activities.

Also, our bank credit facility and the indenture governing our 10 3/8% 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 3/8% 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 3/8% notes. A default, if not cured or waived, could result in acceleration of all indebtedness outstanding under our bank credit facility and our 10 3/8% notes. The accelerated debt would become immediately due and payable. If that should occur, we may not be able to pay all such debt or to borrow sufficient funds to refinance it. Even if new financing were then available, it may not be on terms that are acceptable to us.

We may not be able to fund our planned capital expenditures.

We spend and will continue to spend a substantial amount of capital for the development, exploration, acquisition and production of oil and natural gas reserves. If low oil and natural gas prices, operating difficulties or other factors, many of which are beyond our control, cause our revenues or cash flows from operations to decrease, we may be limited in our ability to spend the capital necessary to continue our drilling program. We may be forced to raise additional debt or equity proceeds to fund such expenditures. We cannot assure you that additional debt or equity financing or cash generated by operations will be available to meet these requirements.

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;

	•		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.

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

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

There have been substantial insurance claims made by the oil and gas industry as a result of hurricane damages incurred during 2005 in the Gulf Coast Basin. Accordingly, we expect that our insurance costs in 2006 will increase significantly. 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.

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.

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.

Lower oil and natural gas prices may cause us to record ceiling test write-downs.

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 “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, 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 ceiling limit, 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 stockholders’ equity. The risk that we will be required to write down the carrying value of oil and natural 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.

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 be highly volatile. 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.

Provisions in certificate of incorporation, bylaws and shareholder rights plan 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, bylaws and shareholder rights plan 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:

	•		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.

In November 2001, our board of directors adopted a shareholder rights plan, pursuant to which uncertificated preferred stock purchase rights were distributed to our stockholders at a rate of one right for each share of common stock held of record as of November 19, 2001. The rights plan is designed to enhance the board’s ability to prevent an acquirer from depriving stockholders of the long-term value of their investment and to protect stockholders against attempts to acquire us by means of unfair or abusive takeover tactics. However, the existence of the rights plan may impede a takeover not supported by our board, including a takeover that may be desired by a majority of our stockholders or involving a premium over the prevailing stock price.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

For a description of the Company’s recent acquisition, exploration and development activities, see Item 1. Business– 2005 Financial and Operational Summary.

Oil and Gas Reserves

The following table sets forth certain information about our estimated proved reserves as of December 31, 2005.


	Proved		Proved		Total
	Developed		Undeveloped		Proved
Oil (MBbls)		2,891		751		3,642

Natural Gas and NGL (MMcfe)		73,250		35,865		109,115

Estimated pre-tax future net cash flows	$	626,736,378	$	234,952,710	$	861,689,088

Discounted pre-tax future net cash flows	$	478,216,958	$	161,516,664	$	639,733,622

Ryder Scott Company, L.P., our independent petroleum and geological engineers, prepared the estimates of proved reserves and future net cash flows (and present value thereof) attributable to such proved reserves at December 31, 2005. Reserves were estimated using oil and gas prices and production and development costs in effect at December 31, 2005 without escalation, and were prepared in accordance with Securities and Exchange Commission regulations regarding disclosure of oil and gas reserve information. The product prices used in developing the above estimates averaged $59.66 per Bbl of oil and $8.61 per Mcfe of gas. Proved developed reserves above include 2,279 MBbls of oil and 28,263 MMcfe of gas that are classified as proved developed, non-producing reserves. These proved developed, non-producing reserves include approximately 400 MBbls of oil and 9,000 MMcfe of gas that were previously producing, but were shut-in at December 31, 2005 as a result of hurricane damage to facilities. Proved reserves attributable to Main Pass 74, which returned to production in January 2006, represented the majority of the shut-in proved reserves at December 31, 2005. The above cash flow amounts include a reduction for estimated plugging and abandonment costs that has been reflected as a liability on our balance sheet at December 31, 2005, in accordance with Statement of Financial Accounting Standards No. 143.

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

Production, Pricing and Production Cost Data

The following table sets forth our production, pricing and production cost data during the periods indicated:


	Year Ended December 31,
	2005		2004		2003
Production:
Oil (Bbls)		665,400		818,405		744,575
Gas (Mcfe)		12,058,377		9,305,075		5,192,760
Total Production (Mcfe)		16,050,777		14,215,505		9,660,210

Average sales prices:
Oil (per Bbl)	$	45.76	$	35.31	$	28.47
Gas (per Mcfe)		7.47		5.99		5.14
Per Mcfe		7.51		5.95		4.96

Average Production Cost per Mcfe (1)	$	1.54	$	1.04	$	1.07


(1)		Production costs include lease operating costs and production taxes

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:


	2005				2004				2003
	Gross		Net		Gross		Net		Gross		Net
Exploration:
Productive		32		14.82		17		8.87		4		1.55
Non-productive		3		1.53		1		0.18		2		1.20

Total		35		16.35		18		9.05		6		2.75


Development:
Productive		46		30.90		15		9.90		4		1.96
Non-productive		5		4.29		—		—		—		—

Total		51		35.19		15		9.90		4		1.96

We owned working interests in 15 gross (9 net) producing oil wells and 581 gross (221 net) producing gas wells at December 31, 2005. Ten of the 596 gross productive wells at December 31, 2005 had dual completions. At December 31, 2005, we had 17 gross wells in progress.

Leasehold Acreage

The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2005:


	Developed				Undeveloped
	Gross		Net		Gross		Net
Mississippi (onshore)		721		458		88		56
Louisiana (onshore)		4,318		1,279		9,966		2,754
Louisiana (offshore)		2,039		1,682		9,281		1,545
Oklahoma		45,397		30,981		7,759		5,079
Texas (onshore)		17,157		8,507		35,942		18,692
Federal Waters		116,063		69,443		78,021		53,171

Total		185,695		112,350		141,057		81,297

Leases covering 13% of our gross undeveloped acreage will expire in 2006, 14% in 2007 and 9% in 2008.

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;

	•		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.

ITEM 3. LEGAL PROCEEDINGS

PetroQuest is involved in litigation relating to claims arising out of its operations in the normal course of business, including workmen’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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to a vote of security holders during the fourth quarter of 2005.

PART II

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

Market Price of and Dividends on Common Stock

On November 30, 2005, our common stock began trading on the New York Stock Exchange under the symbol “PQ.” Prior to that, our stock was traded on The Nasdaq Stock Market under the symbol “PQUE.” The following table lists high and low sales prices per share for the periods indicated:


	NYSE/Nasdaq Stock Market
	High		Low
2004
1st Quarter	$	4.02	$	2.40
2nd Quarter		4.38		3.00
3rd Quarter		5.85		4.09
4th Quarter		5.74		3.55

2005
1st Quarter	$	7.75	$	4.53
2nd Quarter		7.08		5.12
3rd Quarter		11.17		6.50
4th Quarter		11.17		7.96

As of March 1, 2006, there were 463 common stockholders of record.

We have not paid dividends on our common stock and intend to retain our cash flow from operations for the future operation and development of our business. Our bank credit facility and the indenture governing the 10 3/8% senior notes contain customary restrictions with respect to the declaration or payment of any dividends or distributions.

We made no repurchases of our common stock during the year ended December 31, 2005.

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, 2005 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.


	Year Ended December 31,
	2005		2004		2003 (a)		2002		2001 (b)
	(in thousands except per share data)
Revenues	$	123,348	$	84,868	$	48,688	$	48,238	$	55,342
Net Income		21,417		16,348		3,640		2,307		11,645
Net Income per share:
Basic		0.46		0.37		0.08		0.06		0.37
Diluted		0.44		0.35		0.08		0.06		0.34
Oil and Gas Properties, net		365,183		211,683		160,229		120,746		101,029
Total Assets		431,470		231,617		176,384		132,063		114,639
Long-term Debt		158,340		38,500		22,200		2,400		33,000
Stockholders’ Equity		144,537		121,277		107,727		97,770		54,215


(a)		During 2003, the Company adopted SFAS No. 143. The cumulative effect of adoption resulted in a gain of $849,000, or $0.02 per share.

(b)		The Company’s financial statements for 2001 were audited by Arthur Andersen LLP, which has ceased operations.

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, which from the commencement of operations in 1985 through 2002, was focused exclusively in the Gulf Coast Basin with onshore properties principally in southern Louisiana and offshore properties in the shallow Gulf of Mexico shelf. Beginning in 2003, we began diversifying our reserves and production with longer life onshore properties in Texas and Oklahoma, and we enhanced our risk management policies by reducing our average working interest in projects, shifting capital to higher probability onshore wells and reducing the risks associated with individual wells by expanding our drilling program.

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

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

investments yielded a 91% success rate on a company record 86 wells drilled and the consummation of several strategic acquisitions.

To provide capital for our 2005 acquisitions and to repay borrowings under our credit facilities for future liquidity, during 2005 we issued $150 million in principal amount of 10 3/8% Senior Notes due 2012 (“the Notes”). Following the issuance of the Notes we repaid and terminated our subordinated debt credit facility and in December 2005 we amended our bank credit facility increasing the borrowing base to $40 million.

Critical Accounting Policies and Estimates

Full Cost Method of Accounting

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

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

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

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

Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs. Declines in prices or reserves could result in a future write-down of oil and gas properties.

Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices decline, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants.

Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Reserve Estimates

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

Derivative Instruments

The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded to Other Comprehensive Income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement.

Our hedges are specifically referenced to the NYMEX index prices we receive for our designated production. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX index prices and the posted prices we receive from the designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At December 31, 2005, our derivative instruments were considered effective cash flow hedges.

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

New Accounting Standards

In December 2004, the Financial Accounting Standards Board issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. In April 2005, the SEC issued an amendment to rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R). This amendment changed the effective date to the first fiscal year beginning on or after June 15, 2005. Accordingly, we adopted the standard during the first quarter of 2006.

SFAS 123(R) permits adoption using one of two methods. A “modified prospective” method in which compensation cost is recognized beginning with the effective date using the requirements of SFAS 123(R) for all share-based payments granted after the effective date and the requirements of SFAS 123 for all unvested awards at the effective date related to awards granted prior to the effective date. An alternate method, the “modified retrospective” method includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures (see Note 1 in the Notes to the Consolidated Financial Statements) either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

We adopted the standard using the modified prospective method. We plan to continue to compute the fair value of our stock options using the Black-Scholes option-pricing model assuming a stock option forfeiture rate, based on historical activity, of 8.4%, an expected term of six years, using the short-cut method provided for in Staff Accounting Bulletin (“SAB”) No. 107 and expected volatility computed using our historical stock price fluctuations on a weekly basis for a period of time equal to the expected term of the option. Periodically we will adjust compensation expense based on the difference between actual and estimated forfeitures. We currently account for our stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Accordingly, the adoption of SFAS 123(R) will have a significant impact on our results of operations, but will have no impact on our overall financial position.

The specific impact of the adoption cannot be predicted because it will depend on the level of share-based payments granted in the future and the differences between actual and estimated stock option forfeitures. All of our stock options vest equally over a three year period. Therefore, at December 31, 2005, we had one year of compensation expense related to 2004 option grants and two years of compensation expense related to 2005 option grants that will be recognized in our income statement in 2006 and 2007, using the accelerated expense attribution method. Based on options outstanding at December 31, 2005 and using an 8.4% expected forfeiture rate, we would expect to recognize approximately $200,000 of share based compensation expense in 2006 and approximately $30,000 in 2007 in connection with the adoption of SFAS 123(R).

SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reflected as a financing cash flow, rather than as an operating cash flow as currently required. We did not recognize any excess tax deductions during 2005, 2004 or 2003 in connection with the exercise of stock options.

In September 2004, the Securities and Exchange Commission adopted SAB No. 106, regarding the application of SFAS No. 143 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. We began applying SAB No. 106 in the first quarter of 2005.

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, 2005, 2004 and 2003. Our historical results are not necessarily indicative of results to be expected in future periods.


	Year Ended December 31,
	2005		2004		2003
Production:
Oil (Bbls)		665,400		818,405		744,575
Gas (Mcfe)		12,058,377		9,305,075		5,192,760
Total Production (Mcfe)		16,050,777		14,215,505		9,660,210

Sales:
Total oil sales	$	30,446,897	$	28,896,550	$	21,196,246
Total gas sales		90,105,054		55,698,797		26,713,611

Total oil and gas sales	$	120,551,951	$	84,595,347	$	47,909,857

Average sales prices:
Oil (per Bbl)	$	45.76	$	35.31	$	28.47
Gas (per Mcfe)		7.47		5.99		5.14
Per Mcfe		7.51		5.95		4.96

The above sales and average sales prices include reductions to revenue related to the settlement of gas hedges of $10,242,000, $1,064,000 and $2,540,000 and oil hedges of $5,572,000, $4,197,000 and, $1,923,000 for the years ended December 31, 2005, 2004 and 2003, respectively.

Comparison of Results of Operations for the Years Ended December 31, 2005 and 2004

Net income for the year ended December 31, 2005 increased 31% to $21,417,000, as compared to $16,348,000 for the year ended December 31, 2004. The results were attributable to the following components:

Production

Oil production in 2005 totaled 665,400 barrels, a 19% decline from 2004, while natural gas production increased 30% to 12.1 Bcf from 2004 gas production of 9.3 Bcf. On a gas equivalent basis, production for 2005 totaled 16.1 Bcfe, a 13% increase from the 2004 period. During 2005, 75% of our total production was natural gas as compared to 65% during 2004. This shift towards natural gas is the result of our expanded operations in Texas and Oklahoma where the production is primarily natural gas.

The growth in production during 2005 was primarily the result of our increased capital expenditures, which included several acquisitions of producing properties and a 161% increase in the number of gross wells drilled, as compared to 2004. Offsetting our production gains were the shut-in of a portion of our Gulf Coast Basin fields during the third and fourth quarters of 2005 as a result of Hurricanes Katrina and Rita and the shut-in of our Main Pass 74 field throughout 2005 due to third-party pipeline damage from Hurricane Ivan in 2004. Production from Main Pass 74 was restored in January 2006.

Based on our drilling success during 2005 and the restoration of production of Main Pass 74, we expect that our production will continue to grow during 2006. In addition, our 2006 production would benefit from any acquisition of producing properties that we would be successful in consummating during 2006. Finally, we expect to drill approximately 160 gross wells during 2006, an 86% increase from 2005. Assuming we are able to maintain our historically high drilling success rate (91% success rate over the last three years), our 2006 expanded drilling program should provide additional production growth.

Prices

Average oil prices per barrel during 2005 were $45.76 versus $35.31 during 2004. Average gas prices per Mcf were $7.47 during 2005 as compared to $5.99 during 2004. Stated on a gas equivalent basis, unit prices received during 2005 were 26% higher than the prices received during 2004.

Revenue

Oil and gas sales during 2005 increased 43% to $120,552,000 from $84,595,000 during 2004 as a result of higher commodity prices and increased production volumes. Assuming commodity prices remain at current levels, we expect that our revenues would continue to increase as we expect to grow our production through drilling and strategic acquisitions of producing properties.

During 2005, interest and other income totaled $2,796,000 as compared to $273,000 during 2004. The increase in 2005 is primarily due to income generated by our gas gathering assets acquired during 2005 and interest income earned on cash proceeds from the Notes.

Expenses

Lease operating expenses during 2005 increased to $20,972,000 as compared to $13,161,000 during 2004. On an Mcfe basis, lease operating expenses totaled $1.31 per Mcfe in 2005, a 41% increase from the $0.93 per Mcfe of operating costs in 2004. At December 31, 2005, we owned working interests in 596 gross wells, as compared to 197 gross wells at December 31, 2004. Operating costs during 2005 were higher due to this significant increase in the number of producing wells in which we participate, as well as the increases in costs for oil field related services prevalent throughout the industry, such as labor, transportation, insurance and materials.

We expect the trend of higher operating costs to continue during 2006, particularly with respect to insurance. There have been substantial insurance claims made by the oil and gas industry as a result of hurricane damages incurred during 2005 in the Gulf Coast Basin. Accordingly, we expect a significant increase in our 2006 insurance costs relative to our offshore operations, and are currently in discussions with our insurance underwriters regarding our options on deductibles, limits and specific coverages for 2006. See “Risk Factors-Losses and liabilities from uninsured or underinsured drilling and operating activities could have a material adverse effect on our financial condition and operations.”

At December 31, 2005, we recorded a $1.8 million receivable representing our estimate of costs incurred to repair hurricane related damages through year-end 2005 that we believed qualified for insurance reimbursement. We estimate that our insurance claim related to hurricane damages attributable to our interests will ultimately total between $4 million and $5 million, assuming actual costs of remaining repairs approximate estimates.

Production taxes increased to $3,764,000 during 2005 from $1,549,000 during 2004. Production taxes in Texas and Oklahoma are predominately value based and therefore fluctuate in relation to commodity prices. As a result, the increase in 2005 production taxes is primarily due to higher commodity prices coupled with increased production from our Oklahoma and onshore Texas properties. Additionally, effective July 1, 2005, there was an increase to the Louisiana gas severance tax rate that contributed to the increase in production taxes.

General and administrative expenses during 2005 totaled $7,347,000 as compared to $6,212,000 during 2004, net of amounts capitalized of $4,807,000 and $4,036,000, respectively. The increase in general and administrative expenses is primarily due to the 31% increase in our staffing level during 2005 in order to accommodate our increased operational activities.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for 2005 increased 22% to $42,513,000 as compared to $34,971,000 in 2004. On an Mcfe basis, the DD&A rate on oil and gas properties totaled $2.65 per Mcfe during 2005 as compared to $2.46 per Mcfe for 2004. The increase in our DD&A expense per Mcfe is primarily due to increased costs to drill for, develop and acquire oil and gas reserves. As a result of the increased demand for oil and gas properties, equipment and services caused by high commodity prices, relative to historical averages, we expect this trend to continue.

Interest expense, net of amounts capitalized on unevaluated assets, totaled $12,371,000 during 2005 versus $2,817,000 during 2004. The increase in interest expense is the result of the higher debt level and interest rate associated with the Notes, as well as a charge during 2005 of $2,575,000 related to previously deferred financing costs, primarily associated

with our subordinated debt credit facility, which were written off. We capitalized $2,912,000 and $883,000 of interest during 2005 and 2004, respectively.

Income tax expense of $12,477,000 was recognized during 2005 as compared to $8,511,000 being recorded during 2004. The increase is primarily due to the higher operating profit during 2005. We provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, and state income taxes.

Comparison of Results of Operations for the Years Ended December 31, 2004 and 2003

Net income totaled $16,348,000 and $3,640,000 for the years ended December 31, 2004 and 2003, respectively. The results are attributable to the following components:

Production

Oil production in 2004 totaled 818,405 barrels, a 10% increase from the year ended December 31, 2003. Natural gas production in 2004 increased 79% to 9.3 Bcf from 2003 gas production of 5.2 Bcf. On a gas equivalent basis, production for 2004 totaled 14.2 Bcfe, a 47% increase from the 2003 period. The increase in production as compared to 2003 was the result of our current year drilling success, which included only one dry hole out of 33 wells drilled, and our acquisition of primarily gas producing properties in the Southeast Carthage Field in December 2003, which contributed 1.9 Bcfe, or 13%, to our net 2004 production.

Prices

Average oil prices per barrel during 2004 were $35.31 versus $28.47 during 2003. Average gas prices per Mcf were $5.99 during 2004 as compared to $5.14 during 2003. Stated on a gas equivalent basis, unit prices received during 2004 were 20% higher than the prices received during 2003.

Revenue

Oil and gas sales during 2004 increased 77% to $84,595,000 from $47,910,000 during 2003 as a result of higher production volumes and commodity prices.

During 2004, interest and other income decreased to $273,000 from $778,000 during 2003. Interest and other income recognized during 2003 included the settlement of a lawsuit.

Expenses

As a result of the increase in the number of wells we participate in, lease operating expenses for 2004 increased to $13,161,000 from $9,449,000 during 2003. However, on an Mcfe basis, lease operating expenses decreased 5% from $0.98 per Mcfe in 2003 to $0.93 per Mcfe in 2004.

Production taxes increased to $1,549,000 during 2004 from $884,000 during 2003. The increase is due to higher onshore production as a result of acquisitions in Texas and Oklahoma, as well as an increase in the Louisiana severance tax rate effective July 1, 2004.

General and administrative expenses during 2004 totaled $6,212,000 as compared to $4,444,000 during 2003, net of amounts capitalized of $4,036,000 and $3,611,000, respectively. The increases in general and administrative expenses are primarily due to higher accrued bonuses in 2004 resulting from the Company’s improved performance in 2004 relative to 2003.

Depreciation, depletion and amortization (“DD&A”) expense on oil and gas properties for 2004 increased 31% to $34,971,000 as compared to $26,654,000 in 2003. On an Mcfe basis, however, the DD&A rate on oil and gas properties totaled $2.46 per Mcfe during 2004 as compared to $2.76 per Mcfe for 2003. The decrease in 2004 per unit DD&A was due primarily to acquisitions made during late 2003 and throughout 2004 at a lower per unit cost than our historical depletion rate and our 2004 drilling success.

Interest expense, net of amounts capitalized on unevaluated prospects, totaled $2,817,000 during 2004 versus $579,000 during 2003. The increase in interest costs is the result of borrowings made in December 2003 to fund the

acquisition of properties in the Carthage Field and borrowings made in October 2004 to fund the acquisition of properties in Oklahoma. We capitalized $883,000 and $451,000 of interest during 2004 and 2003, respectively.

Derivative expense totaled $2,000 and $1,071,000 during 2004 and 2003, respectively. The expense recorded in 2003 was the result of an ineffective gas derivative instrument and an interest rate swap that did not qualify for hedge accounting treatment. These instruments expired during December 2003 and November 2004, respectively.

Income tax expense of $8,511,000 was recognized during 2004 as compared to $1,690,000 being recorded during 2003. The increase is due to the increase in operating profit during the current year. We provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion.

Liquidity and Capital Resources

We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, private and public offerings of common stock and debt securities and sales of properties.

Source of Capital: Operations

Net cash flow from operations increased from $70,310,000 during 2004 to $73,190,000 in 2005.

At December 31, 2005, we had a working capital deficit of $31,752,000 versus a deficit of $24,429,000 at December 31, 2004. The increase in our current assets at December 31, 2005 was primarily due to an increase in our revenue and joint interest billing receivables. The increase in the revenue receivable was due to higher production and prices at year-end 2005 while our joint interest billing receivable increased as a result of the substantial increase in drilling and operational activity during 2005. The increase in current liabilities was primarily due to an increase in the current portion of the estimated fair value of our derivative instruments, a result of higher estimated future commodity prices, and an increase in our accounts payable to vendors, which is a function of increased operational activity. Overall, our accounts receivable and accounts payable at December 31, 2005 increased as a result of higher capital expenditures, production and commodity prices realized during 2005. We believe that our working capital balance should be viewed in conjunction with availability of borrowings under our bank credit facility when measuring liquidity.

Source of Capital: Debt

On May 11, 2005, we issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, we issued an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 at 99% of their face value.

After payment of expenses and the initial purchasers’ discounts, we received $144.4 million in net proceeds from the issuance of the Notes. The net proceeds were used to repay all outstanding borrowings under our credit facilities, to fund acquisitions and for general corporate purposes. The Notes are redeemable at our option beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, we may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on May 15 and November 15. At December 31, 2005, $1.9 million had been accrued in connection with the May 15, 2006 interest payment. At December 31, 2005, we were in compliance with all of the covenants under the Notes.

We entered into a $75 million bank credit facility on May 14, 2003. During the second quarter of 2005, we repaid all outstanding borrowings under this credit facility with a portion of the net proceeds received from the issuance of the Notes. On November 18, 2005, we and our wholly owned subsidiary, PetroQuest Energy, L.L.C., entered into the Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as lender, agent and issuer of letters of credit, Macquarie Bank Limited, as lender, and Calyon New York Branch, as lender and syndication agent. The Credit Agreement, which was amended in December 2005, provides for a $100 million revolving credit facility that permits us to borrow amounts from time to time based on the available borrowing base as determined in the credit facility. The credit facility also allows us to use up to $15 million of the borrowing base for letters of credit. The credit facility matures on November 19, 2009.

The credit facility is secured by, among other things, a lien on at least 90% of the PDP present value and at least 80% of the aggregate proved reserves of our oil and gas properties. PDP present value means the present value discounted at nine percent of the future net revenues attributable to producing reserves. The borrowing base under the credit facility is based upon the valuation as of January 1 and July 1 of each year of our mortgaged oil and gas properties and any other credit factors deemed relevant by the lenders. The borrowing base is currently $40 million with no reductions scheduled to occur prior to the first borrowing base re-determination, which is scheduled to occur by April 1, 2006. We or the lenders may request additional borrowing base re-determinations.

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

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

As of December 31, 2005, we had $10 million of borrowings outstanding under the credit facility and we were in compliance with all of the covenants therein.

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

Natural gas and oil prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the bank credit facility, thus reducing the amount of financial resources available to meet our capital requirements. Reduced cash flow may also make it difficult to incur debt, other than under our bank credit facility, because of the restrictive covenants in the indenture governing the Notes. Although we do not anticipate debt covenant violations, our ability to comply with our debt agreements is dependent upon the success of our exploration and development program and upon factors beyond our control, such as natural gas and oil prices.

Source of Capital: Issuance of Securities

During April 2005, we issued 646,226 shares of our common stock in connection with the acquisition of TDC Energy, Inc, an independent oil and gas company with properties in the Gulf Coast Basin.

Use of Capital: Exploration and Development

We have an exploration and development program budget for 2006 that will require significant capital. Our capital budget for 2006 is expected to range from $145 million to $160 million. Based on our outlook of commodity prices and estimated production, we believe that cash flow from operations and available borrowing capacity under our bank credit facility will be sufficient to fund planned 2006 exploration and development activities. In the future, our exploration and development activities could require additional financings, which may include sales of additional equity or debt securities, additional borrowings from banks or other lenders, sales of properties, or joint venture arrangements with industry partners. We cannot assure you that such additional financings will be available on acceptable terms, if at all. If we are unable to obtain additional financing, we could be forced to delay or even abandon some of our exploration and development opportunities or be forced to sell some of our assets on an untimely or unfavorable basis.

Contractual Obligations

The following table summarizes our contractual obligations as of December 31, 2005 (in thousands):


													After
	Total		2006		2007		2008		2009		2010		2010
Bank debt (1)	$	12,870	$	700	$	725	$	750	$	10,695	$	—	$	—
10 3/8% Senior Notes (1)		249,214		15,563		15,563		15,563		15,563		15,563		171,399
Purchase obligations (2)		30,265		8,240		9,125		9,125		3,775		—		—
Operating leases (3)		3,232		821		778		764		771		98		—
Capital projects (4)		21,607		2,350		2,769		2,690		356		2,172		11,270


(1)		Includes principal and estimated interest.

(2)		Consists of a three-year commitment for the rental of a drilling rig and a commitment to acquire seismic data during 2006.

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

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 2006, a 10% decline in the estimated average prices we receive for our crude oil and natural gas production would have an approximate $20 million impact on our 2006 revenues.

We periodically seek to reduce our exposure to commodity price volatility by hedging a portion of production through commodity derivative instruments. In the settlement of a typical hedge transaction, we will have the right to receive from the counterparts to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the counterparts this difference multiplied by the quantity hedged. During 2005, we paid the counterparties to our derivative instruments approximately $15.8 million in connection with hedge settlements.

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

As of December 31, 2005, we had entered into the following oil and gas hedge contracts accounted for as cash flow hedges:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

2006

Swap

5,500 Mmbtu

4.33

First Quarter 2006

Costless Collar

16,500 Mmbtu

8.80 - 14.30

Second Quarter 2006

Costless Collar

14,500 Mmbtu

7.95 - 12.41

Third Quarter 2006

Costless Collar

11,000 Mmbtu

8.55 - 13.14

Fourth Quarter 2006

Costless Collar

9,000 Mmbtu

8.22 - 13.29

Crude Oil:

First Quarter 2006

Costless Collar

600 Bbls

37.67 - 57.37

April — December 2006

Costless Collar

200 Bbls

23.00 - 26.40

At December 31, 2005, we recognized a liability of approximately $16 million related to the estimated fair value of these derivative instruments.

During January 2006, we entered into the following oil hedge contracts accounted for as cash flow hedges:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Crude Oil:

Second Quarter 2006

Costless Collar

750 Bbls

65.00 - 74.30

Third Quarter 2006

Costless Collar

500 Bbls

65.00 - 75.35

Fourth Quarter 2006

Costless Collar

300 Bbls

65.00 - 75.65

Debt outstanding under the credit facility is subject to a floating interest rate and represents only 6% of our total debt as of December 31, 2005. As a result, the potential effect of rising interest rates during 2006 on borrowings outstanding at December 31, 2005 is not expected to be material.

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.

Changes in Internal Controls

There have been no changes in the Company’s internal controls over financial reporting during the quarter ended December 31, 2005 that have materially affected, or that are reasonably likely to materially affect, the Company’s internal controls 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, 2005. 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 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, 2005 based upon criteria in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on our assessment, management believes that our internal control over financial reporting was effective as of December 31, 2005 based on these criteria.

Our management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2005 has been audited by Ernst & Young LLP, our independent registered public accounting firm, as stated in their report below.

March 6, 2006

/s/ Charles T. Goodson
Charles T. Goodson
Chairman and
Chief Executive Officer

/s/ Michael O. Aldridge
Michael O. Aldridge
Senior Vice President-
Chief Financial Officer

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors and Shareholders
PetroQuest Energy, Inc.

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that PetroQuest Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2005, 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. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, management’s assessment that PetroQuest Energy, Inc. maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, PetroQuest Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, 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, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005 of PetroQuest Energy, Inc. and our report dated March 6, 2006 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 6, 2006

ITEM 9B. OTHER INFORMATION

NONE

PART III

ITEMS 10, 11, 12, 13 & 14

For information concerning Item 10. Directors and Executive Officers of the Registrant, 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 Item 14. Principal Accounting Fees and Services, see the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual Meeting of Stockholders to be held May 16, 2006, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS AND 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-21 of this Form 10-K:

Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Income for the three years ended December 31, 2005
Consolidated Statements of Stockholders’ Equity for the three years ended December 31, 2005
Consolidated Statements of Cash Flows for the three years ended December 31, 2005
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).

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

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

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

	2.5		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, LLC (incorporated by reference to Exhibit 2.3 to Form 8-K filed April 22, 2005).

	2.6		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, LLC (incorporated by reference to Exhibit 2.4 to Form 8-K filed April 22, 2005).

	3.1		Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated September 16, 1998).

	3.2		Bylaws of the Company (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated September 16, 1998).

	3.3		Certificate of Domestication of Optima Petroleum Corporation (incorporated herein by reference to Exhibit 4.4 to Form 8-K dated September 16, 1998).

	3.4		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).

	4.1		Warrant to Purchase Common Shares of PetroQuest Energy, Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 29, 2003).

	4.2		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).

	4.3		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).

	4.4		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 by reference to Exhibit 4.1 to Form 8-K filed May 11, 2005).

	4.5		Registration Rights Agreement dated April 12, 2005, between PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 4.1 to Form 8-K filed April 13, 2005).

	4.6		Registration Rights Agreement dated May 6, 2005, among PetroQuest Energy, Inc., PetroQuest Energy, LLC, the Subsidiary Guarantors identified therein and the Initial Purchasers (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 11, 2005).

	4.7		Registration Rights Agreement dated June 17, 2005, among PetroQuest Energy, Inc., PetroQuest Energy, LLC, the Subsidiary Guarantors identified therein and the Initial Purchasers (incorporated by reference to Exhibit 4.2 to Form 8-K filed June 17, 2005).

	†10.1		PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective December 1, 2000 (incorporated herein by reference to Appendix A to Proxy Statement on Schedule 14A filed April 20, 2001).

	10.2		Amended and Restated Credit Agreement, dated as of May 14, 2003, by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Bank One, NA, Banc One Capital Markets, Inc., and certain other Lenders (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed August 13, 2003).

	10.3		Guaranty dated May 14, 2003, between PetroQuest Energy, Inc. and Bank One, NA, as Agent for the Lenders (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed August 13, 2003).

	10.4		First Amendment to Amended and Restated Credit Agreement dated as of November 6, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc.; Bank One, N.A., and Union Bank of California, N.A. (incorporated herein by reference to Exhibit 10.4 to Form 10-Q filed November 13, 2003).

	10.5		Second Amendment to Amended and Restated Credit Agreement dated as of December 23, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., and Bank One, N.A. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed December 29, 2003).

	10.6		Third Amendment to Amended and Restated Credit Agreement dated as of July 27, 2004, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., and Bank One, N.A. (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed July 30, 2004).

	10.7		Fourth Amendment to Amended and Restated Credit Agreement dated as of October 14, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc. and Bank One, N.A. (incorporated by reference to Exhibit 10.1 on Form 8-K filed October 19, 2004).

	10.8		Fifth Amendment to Amended and Restated Credit Agreement entered into as of November 3, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc. (a wholly owned subsidiary of PetroQuest Energy, LLC) and Bank One, N.A. (incorporated by reference to Exhibit 10.1 on Form 8-K filed November 15, 2004).

	10.9		Sixth Amendment to Amended and Restated Credit Agreement dated April 12, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Acquisition Sub LLC, and JP Morgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 13, 2005).

	10.10		Seventh Amendment to Amended and Restated Credit Agreement dated May 9, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JP Morgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 11, 2005).

	10.11		Eighth Amendment to Amended and Restated Credit Agreement dated June 17, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JP Morgan Chase Bank, N.A., Guaranty Bank, FSB and Calyon New York Branch (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 17, 2005).

	10.12		Second Amended and Restated Credit Agreement dated as of November 18, 2005, among PetroQuest Energy, LLC, PetroQuest Energy, Inc., JP Morgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 23, 2005).

	10.13		Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 22, 2005, among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans, Inc., TDC Energy LLC, JP Morgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed December 22, 2005).

	10.14		Senior Second Lien Secured Credit Agreement dated November 6, 2003, between PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto; and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed November 13, 2003).

	10.15		Unconditional Guaranty Agreement dated November 6, 2003, by PetroQuest Energy, Inc. to Macquarie Americas Corp., as administrative agent for the benefit of the Lenders under the Credit Agreement (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed November 13, 2003).

	10.16		First Amendment To Second Lien Secured Credit Agreement dated December 23, 2003, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto, and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 29, 2003).

	10.17		Second Amendment to Second Lien Secured Credit Agreement dated July 27, 2004, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto, and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed July 30, 2004).

	10.18		Third Amendment to Second Lien Secured Credit Agreement dated as of October 14, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 10.2 on Form 8-K filed October 19, 2004).

	10.19		Fourth Amendment to Second Lien Secured Credit Agreement dated as of December 29, 2004 by and between PetroQuest Energy, LLC and Macquarie Bank Limited (incorporated by reference to Exhibit 10.1 on Form 8-K filed December 30, 2004).

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

	†10.21		Employment Agreement dated September 1, 1998, between PetroQuest Energy, Inc. and Charles T. Goodson (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated September 16, 1998).

	†10.22		First Amendment to Employment agreement dated September 1, 1998 between PetroQuest Energy, Inc. and Charles T. Goodson dated July 30, 1999 (incorporated herein by reference to Exhibit 10.1 to For 8-K dated August 9, 1999).

	†10.23		Employment Agreement dated September 1, 1998, between PetroQuest Energy, Inc. and Ralph J. Daigle (incorporated herein by reference to Exhibit 10.4 to Form 8-K dated September 16, 1998).

	†10.24		First Amendment to Employment Agreement dated September 1, 1998 between PetroQuest Energy, Inc. and Ralph J. Daigle dated July 30, 1999 (incorporated herein by reference to Exhibit 10.3 to Form 8-K dated August 9, 1999).

	†10.25		Severance Agreement and Release, effective April 8, 2005, between PetroQuest Energy, Inc. and Ralph J. Daigle (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed April 22, 2005).

	†10.26		Employment Agreement dated May 8, 2000 between PetroQuest Energy, Inc. and Michael O. Aldridge (incorporated by reference to Exhibit 10.1 to the Form 10-Q filed August 14, 2000).

	†10.27		Employment Agreement dated December 15, 2000 between PetroQuest Energy, Inc. and Arthur M. Mixon, III. (incorporated herein by reference to Exhibit 10.12 to Form 10-K filed March 30, 2001).

	†10.28		Employment Agreement dated April 20, 2001 between PetroQuest Energy, Inc. and Daniel G. Fournerat (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed May 15, 2001).

	†10.29		Employment Agreement dated April 20, 2001 between PetroQuest Energy, Inc. and Dalton F. Smith III (incorporated herein by reference to Exhibit 10.21 to Form 10-K filed March 13, 2002).

	†10.30		Employment agreement dated July 28, 2003, between PetroQuest Energy, Inc. and Stephen H. Green (incorporated herein by reference to Exhibit 10.3 to Form 10-Q filed November 13, 2003).

	†10.31		Form of Termination Agreement Between PetroQuest Energy, Inc. and each of its executive officers, including Charles T. Goodson, Michael O. Aldridge, Arthur M. Mixon, III, Daniel G. Fournerat, Dalton F. Smith III and Stephen H. Green (incorporated herein by reference to Exhibit 10.20 to Form 10-K filed March 13, 2002).

	†10.32		Form of Indemnification Agreement between PetroQuest Energy, Inc. and each of its directors and executive officers, including Charles T. Goodson, Ralph J. Daigle, Daniel G. Fournerat, E. Wayne Nordberg, William W. Rucks, IV, Michael O. Aldridge, Arthur M. Mixon, III, Dalton F. Smith III, Michael L. Finch, W.J. Gordon, III, Stephen H. Green and Charles F. Mitchell, II (incorporated herein by reference to Exhibit 10.21 to Form 10-K filed March 13, 2002).

	*14.1		Code of Business Conduct and Ethics.

	*21.1		Subsidiaries of the Company.

	*23.1		Consent of Independent Auditors.

	*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.


*		Filed herewith.

†		Management contract or compensatory plan or arrangement

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

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. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

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

Developmental well. A well drilled into a proved natural gas or oil 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 and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend 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 either 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.

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.

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

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 developed non-producing reserves. Proved developed reserves expected to be recovered from zones behind casing in existing wells.

Proved developed producing reserves (“PDP”). Proved developed reserves that are expected to be recovered from completion intervals currently open in existing wells and capable of production to market.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves 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.

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

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.

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.

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 7, 2006.


	PETROQUEST ENERGY, INC.
	By:	/s/ Charles T. Goodson
		CHARLES T. GOODSON
		Chairman of the Board 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 7, 2006.


By:	/s/ Charles T. Goodson CHARLES T. GOODSON	Chairman of the Board, Chief Executive Officer and Director (Principal Executive Officer)

By:	/s/ Michael O. Aldridge MICHAEL O. ALDRIDGE	Senior Vice President, Chief Financial Officer, Treasurer and Director (Principal Financial and Accounting Officer)

By:	/s/ W.J. Gordon, III W.J. GORDON, III	Director

By:	/s/ Michael L. Finch MICHAEL L. FINCH	Director

By:	/s/ Charles F. Mitchell, II, M.D. Charles F. Mitchell, II, M.D.	Director

By:	/s/ E. Wayne Nordberg E. WAYNE NORDBERG	Director

By:	/s/ William W. Rucks, IV WILLIAM W. RUCKS, IV	Director

Report of Independent Registered Public Accounting Firm

The Board of Directors and Shareholders of
PetroQuest Energy, Inc.

We have audited the accompanying consolidated balance sheets of PetroQuest Energy, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2005. 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, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of PetroQuest Energy, Inc.’s internal control over financial reporting as of December 31, 2005, 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 6, 2006 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

New Orleans, Louisiana
March 6, 2006

F-2

PETROQUEST ENERGY, INC.

Consolidated Balance Sheets

(Amounts in Thousands)


	December 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	6,703		$	1,529
Revenue receivable		22,492			9,392
Joint interest billing receivable		17,567			3,655
Other current assets		3,441			1,017

Total current assets		50,203			15,593


Property and equipment:
Oil and gas properties:
Oil and gas properties, full cost method		523,212			363,756
Unevaluated oil and gas properties		52,745			16,380
Accumulated depreciation, depletion and amortization		(210,774	)		(168,453	)

Oil and gas properties, net		365,183			211,683
Gas gathering assets		10,861			—
Accumulated depreciation and amortization of gas gathering assets		(1,055	)		—

Total property and equipment		374,989			211,683


Other assets, net of accumulated depreciation and amortization of $10,353 and $5,967, respectively		6,278			4,341


Total assets	$	431,470		$	231,617


LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable to vendors	$	41,462		$	24,176
Advances from co-owners		5,874			2,265
Oil and gas revenue payable		8,090			2,930
Hedging liability		15,987			4,536
Other accrued liabilities		10,542			6,115

Total current liabilities		81,955			40,022

Bank debt		10,000			38,500
10 3/8% Senior Notes		148,340			—
Asset retirement obligation		19,257			15,238
Deferred income taxes		27,139			14,606
Other liabilities		242			1,974

Commitments and contingencies

Stockholders’ equity:
Common stock, $.001 par value; authorized 75,000 shares; issued and outstanding 47,325 and 44,685 shares, respectively		47			45
Paid-in capital		117,441			112,387
Accumulated other comprehensive loss		(7,444	)		(4,231	)
Retained earnings		34,493			13,076

Total stockholders’ equity		144,537			121,277


Total liabilities and stockholders’ equity	$	431,470		$	231,617

See accompanying Notes to Consolidated Financial Statements.

F-3

PETROQUEST ENERGY, INC.

Consolidated Statements of Income

(Amounts in Thousands, Except Per Share Data)


	Year Ended December 31,
	2005		2004		2003
Revenues:
Oil and gas sales	$	120,552	$	84,595	$	47,910
Interest and other income		2,796		273		778

		123,348		84,868		48,688


Expenses:
Lease operating expenses		20,972		13,161		9,449
Production taxes		3,764		1,549		884
Depreciation, depletion and amortization		43,747		35,435		27,098
General and administrative		7,347		6,212		4,444
Accretion of asset retirement obligation		1,253		833		682
Interest expense		12,371		2,817		579
Derivative expense		—		2		1,071

		89,454		60,009		44,207


Income from operations		33,894		24,859		4,481

Income tax expense		12,477		8,511		1,690


Income before cumulative effect of change in accounting principle	$	21,417	$	16,348	$	2,791

Cumulative effect of change in accounting principle		—		—		849


Net income	$	21,417	$	16,348	$	3,640


Earnings per common share:
Basic
Income before cumulative effect of change in accounting principle	$	0.46	$	0.37	$	0.06
Cumulative effect of change in accounting principle		—		—		0.02

Net income	$	0.46	$	0.37	$	0.08

Diluted
Income before cumulative effect of change in accounting principle	$	0.44	$	0.35	$	0.06
Cumulative effect of change in accounting principle		—		—		0.02

Net income	$	0.44	$	0.35	$	0.08


Weighted average number of common shares:
Basic		46,714		44,616		43,661
Diluted		48,242		46,438		44,181

See accompanying Notes to Consolidated Financial Statements.

F-4

PETROQUEST ENERGY, INC.

Consolidated Statements of Stockholders’ Equity

(Amounts in Thousands)


						Unearned			Other						Total
	Common		Paid-In			Deferred			Comprehensive			Retained			Stockholders’
	Stock		Capital			Compensation			Loss			Earnings (Deficit)			Equity
December 31, 2002	$	43	$	106,173		$	(337	)	$	(1,197	)	$	(6,912	)	$	97,770

Options and warrants exercised		2		2,110			—			—			—			2,112

Sale of common stock		—		(6	)		—			—			—			(6	)

Amortization of deferred compensation		—		—			268			—			—			268

Tax effect of deferred compensation		—		16			—			—			—			16

Warrant fair value adjustment		—		3,745			—			—			—			3,745

Derivative fair value adjustment, net of tax		—		—			—			182			—			182

Net income		—		—			—			—			3,640			3,640


December 31, 2003	$	45	$	112,038		$	(69	)	$	(1,015	)	$	(3,272	)	$	107,727


Options and warrants exercised		—		170			—			—			—			170

Sale of common stock		—		203			—			—			—			203

Amortization of deferred compensation		—		—			69			—			—			69

Tax effect of deferred compensation		—		(24	)		—			—			—			(24	)

Derivative fair value adjustment, net of tax		—		—			—			(3,216	)		—			(3,216	)

Net income		—		—			—			—			16,348			16,348


December 31, 2004	$	45	$	112,387		$	—		$	(4,231	)	$	13,076		$	121,277


Options and warrants exercised		2		1,003			—			—			—			1,005

Issuance of common stock		—		4,051			—			—			—			4,051

Derivative fair value adjustment, net of tax		—		—			—			(3,213	)		—			(3,213	)

Net income		—		—			—			—			21,417			21,417


December 31, 2005	$	47	$	117,441		$	—		$	(7,444	)	$	34,493		$	144,537

See accompanying Notes to Consolidated Financial Statements.

F-5

PETROQUEST ENERGY, INC.

Consolidated Statements of Cash Flows

(Amounts in Thousands)


	Year Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income	$	21,417		$	16,348		$	3,640
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred tax expense		12,477			8,511			1,690
Amortization of debt issuance costs		1,390			1,678			531
Compensation expense		213			272			381
Depreciation, depletion and amortization		43,747			35,435			27,098
Derivative mark to market		—			(218	)		(258	)
Write-off of debt issuance costs		2,575			—			—
Amortization of bond discount		111			—			—
Cumulative effect of change in accounting principle		—			—			(849	)
Accretion of asset retirement obligation		1,253			833			682
Changes in working capital accounts:
Revenue receivable		(13,100	)		(2,871	)		(20	)
Joint interest billing receivable		(13,912	)		(1,080	)		(409	)
Accounts payable and accrued liabilities		14,255			12,521			1,416
Other assets		(448	)		(619	)		(273	)
Advances from co-owners		3,609			(487	)		1,811
Other		(397	)		(13	)		(1,250	)


Net cash provided by operating activities		73,190			70,310			34,190


Cash flows from investing activities:
Investment in oil and gas properties		(171,980	)		(80,142	)		(54,126	)
Investment in gas gathering assets		(10,861	)		—			—


Net cash used in investing activities		(182,841	)		(80,142	)		(54,126	)


Cash flows from financing activities:
Proceeds from exercise of options and warrants		972			170			2,111
Proceeds from bank borrowings		44,500			39,000			39,600
Repayment of bank borrowings		(73,000	)		(28,000	)		(21,100	)
Proceeds from issuance of 10 3/8% senior notes		148,229			—			—
Deferred financing costs		(5,876	)		(588	)		(1,027	)
Issuance of common stock, net of expenses		—			—			(6	)


Net cash provided by financing activities		114,825			10,582			19,578


Net increase (decrease) in cash and cash equivalents		5,174			750			(358	)
Cash and cash equivalents at beginning of period		1,529			779			1,137

Cash and cash equivalents at end of period	$	6,703		$	1,529		$	779


Supplentmental disclosure of cash flow information
Cash paid during the period for:
Interest	$	9,628		$	1,752		$	435

Income taxes	$	75		$	—		$	—

See accompanying Notes to Consolidated Financial Statements.

F-6

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 an exploration office in Houston, Texas. It is engaged in the exploration, development, acquisition and operation of oil and gas properties onshore and offshore in the Gulf Coast Basin, as well as in Texas and Oklahoma.

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. Certain reclassifications of amounts previously reported have been made to conform to current year presentation.

Oil and Gas Properties

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.

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, restoration, dismantlement and abandonment costs associated therewith, are included in the depreciable base. The costs of investments in unproved 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 its proved reserves (the full cost ceiling). In September 2004, the Securities and Exchange Commission adopted Staff Accounting Bulletin (“SAB”) No. 106, regarding the application of SFAS No. 143 by companies following the full cost accounting method. SAB No. 106 indicates that estimated future dismantlement and abandonment costs that are recorded on the balance sheet are to be included in the costs subject to the full cost ceiling limitation. The estimated future cash outflows associated with settling the recorded asset retirement obligations should be excluded from the computation of the present value of estimated future net revenues used in applying the ceiling test. The Company began applying SAB No. 106 in the first quarter of 2005. Transactions involving sales of reserves in place, unless significant, are recorded as adjustments to accumulated depreciation, depletion and amortization.

Upon the acquisition or discovery of oil and gas properties, management estimates the future net costs to be incurred to dismantle, abandon and restore the property using geological, engineering and regulatory data available. Such cost estimates are periodically updated for changes in conditions and requirements. Such estimated amounts are considered part of the full cost pool for purposes of amortization upon acquisition or discovery. Such costs are capitalized as oil and gas properties as the actual restoration, dismantlement and abandonment activities take place.

F-7

Gas Gathering Assets

In connection with certain acquisitions of properties in Oklahoma, during 2005 we acquired interests in several gas gathering systems used in the transportation of natural gas. The costs of these systems are depreciated on a straight line basis over the estimated remaining useful lives, generally 14 years.

Other Assets

Other assets consist primarily of furniture and fixtures (net of accumulated depreciation), which are depreciated over their useful lives ranging from 3-7 years, and deferred financing costs, which are amortized on a straight line basis over the life of the related debt.

Cash and Cash Equivalents

The Company considers all highly liquid investments in overnight securities made through its commercial bank accounts, which result in available funds the next business day, to be cash and cash equivalents.

Income Taxes

The Company accounts for income taxes in accordance with Statement of Financial Accounting Standards (SFAS) No. 109. 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 where management deems appropriate. Other financial and income tax reporting differences occur as a result of statutory depletion.

Earnings per Common Share Amounts

Basic earnings per common share is computed by dividing net income by the weighted average number of shares of common stock outstanding during the year. Diluted earnings per common share is determined on a weighted average basis using common shares issued and outstanding adjusted for the effect of stock options and warrants considered common stock equivalents computed using the treasury stock method. A reconciliation between basic and diluted shares outstanding (in thousands) is as follows:


	Year Ended December 31,
	2005		2004		2003
Basic shares outstanding		46,714		44,616		43,661
Effect of stock options		1,327		858		179
Effect of warrants		201		964		341

Diluted shares outstanding		48,242		46,438		44,181

Options to purchase 45,000 shares of common stock at $6.64 to $7.65 per share were outstanding during 2005 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options to purchase 433,792 shares of common stock at $3.75 to $7.65 per share were outstanding during 2004 but were not included in the computation of diluted earnings per share because the options’ exercise prices were greater than the average market price of the common shares. Options and warrants to purchase 3,385,334 shares of common stock at $2.29 to $7.65 per share were outstanding during 2003 but were not included in the computation of diluted earnings per share because the options’ and warrants’ exercise prices were greater than the average market price of the common shares.

F-8

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, 2005, 2004 and 2003 were not significant.

Certain Concentrations

Our production is sold on month to month contracts at prevailing prices. We attempt to diversify our sales and obtain credit protections such as letters of credit and parental guarantees from certain of our purchasers. The following table identifies customers from whom we derived 10% or more of our 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 financially disruptive effect on its business or financial condition.


	Year Ended December 31,
	2005			2004			2003
Cokinos		12	%		(a	)		12	%
Louis Dreyfus Corporation		20	%		26	%		27	%
Texon LP		16	%		24	%		24	%


(a)		Less than 10 percent

Fair Value of Financial Instruments

The fair value of cash and cash equivalents, accounts receivable and accounts payable approximate book value at December 31, 2005 and 2004 due to the short-term nature of these accounts. The fair value of the bank debt also approximates book value due to the variable rate of interest charged. Hedging instruments are reflected as liabilities on the balance sheet at estimated fair values of approximately $16 million and $6.5 million at December 31, 2005 and 2004, respectively, as required under SFAS 133. These estimated fair values are based on quotes obtained from counterparties, discussed below. The estimated fair value of the 10 3/8% senior notes (the “Notes”) at December 31, 2005 was $156.7 million, while the book value of the Notes, net of discount, was $148.3 million. The estimated fair value of the Notes was provided by independent brokers using the actual year-end market quote for the Notes.

Derivative Instruments

Under SFAS No. 133, as amended, the nature of a derivative instrument must be evaluated to determine if it qualifies for hedge accounting treatment. Instruments qualifying for hedge accounting treatment are recorded as an asset or liability measured at fair value and subsequent changes in fair value are recognized in equity through other comprehensive income, net of related taxes, to the extent the hedge is effective. The cash settlements of cash flow hedges are recorded into revenue. Instruments not qualifying for hedge accounting treatment are recorded in the balance sheet and changes in fair value are recognized in earnings as derivative expense (income).

The Company’s hedges are specifically referenced to the NYMEX index prices received for its designated production. 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 index 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, 2005, the Company’s hedging contracts were considered effective cash flow hedges.

Estimating the fair value of hedging derivatives requires complex calculations incorporating estimates of future prices, discount rates and price movements. As a result, the Company obtains the fair value of its commodity derivatives from the counterparties to those contracts. Because the counterparties are market makers, they are able to provide a literal market value, or what they would be willing to settle such contracts for as of the given date.

Oil and gas revenues include reductions related to the settlement of hedges totaling $15,814,000, $5,261,000 and $4,462,000 during 2005, 2004 and 2003, respectively. The Company recognized $2,000 and $1,071,000 in derivative expense

F-9

during the years ended December 31, 2004 and 2003, respectively. This expense was the result of an ineffective gas derivative instrument and an interest rate swap that did not qualify for hedge accounting treatment. These instruments expired during December 2003 and November 2004, respectively.

As of December 31, 2005, the Company had entered into the following oil and gas hedge contracts accounted for as cash flow hedges:

Instrument

Weighted

Production Period

Type

Daily Volumes

Average Price

Natural Gas:

2006

Swap

5,500 Mmbtu

4.33

First Quarter 2006

Costless Collar

16,500 Mmbtu

8.80 - 14.30

Second Quarter 2006

Costless Collar

14,500 Mmbtu

7.95 - 12.41

Third Quarter 2006

Costless Collar

11,000 Mmbtu

8.55 - 13.14

Fourth Quarter 2006

Costless Collar

9,000 Mmbtu

8.22 - 13.29

Crude Oil:

First Quarter 2006

Costless Collar

600 Bbls

37.67 - 57.37

April — December 2006

Costless Collar

200 Bbls

23.00 - 26.40

At December 31, 2005, the Company recognized a liability of $16 million related to the estimated fair value of these derivative instruments. The Company expects to reclassify $10.4 million of deferred losses, net of taxes, on derivatives from accumulated comprehensive loss to oil and gas sales during the next 12 months. These losses are expected to be reclassified as the oil and gas volumes underlying the derivative contracts are produced and sold.

New Accounting Standards

In December 2004, the Financial Accounting Standards Board issued SFAS 123 (revised 2004), “Share Based Payment,” which is a revision of SFAS 123, “Accounting for Stock-Based Compensation.” SFAS 123(R) supersedes APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and amends SFAS 95, “Statement of Cash Flows.” Generally, the approach in SFAS 123(R) is similar to the approach in SFAS 123. However, SFAS 123(R) requires all share-based payments to employees, including grants of employee stock options, to be recognized in the income statement based on their estimated fair values. Pro forma disclosure is no longer an alternative. In April 2005, the SEC issued an amendment to rule 4-01(a) of Regulation S-X regarding the compliance date for SFAS 123(R). This amendment changed the effective date to the first fiscal year beginning on or after June 15, 2005. Accordingly, we will adopt the standard during the first quarter of 2006.

SFAS 123(R) permits adoption using one of two methods. A “modified prospective” method in which compensation cost is recognized beginning with the effective date using the requirements of SFAS 123(R) for all share-based payments granted after the effective date and the requirements of SFAS 123 for all unvested awards at the effective date related to awards granted prior to the effective date. An alternate method, the “modified retrospective” method includes the requirements of the modified prospective method described above, but also permits entities to restate based on the amounts previously recognized under SFAS 123 for purposes of pro forma disclosures (see amounts below) either (a) all prior periods presented or (b) prior interim periods of the year of adoption.

The Company expects to adopt the standard using the modified prospective method. In addition, the Company plans to continue to compute the fair value of its stock options using the Black-Scholes option-pricing model assuming a stock option forfeiture rate, based on historical activity, of 8.4%, an expected term of six years, using the short-cut method provided for in SAB No. 107 and expected volatility computed using its historical stock price fluctuations on a weekly basis for a period of time equal to the expected term of the option. Periodically the Company will adjust compensation expense based on the difference between actual and estimated forfeitures. The Company currently accounts for its stock-based compensation plans under the principles prescribed by APB Opinion No. 25. Accordingly, no stock option compensation cost is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Accordingly, the adoption of SFAS 123(R) will have a significant impact on the Company’s results of operations, but will have no impact on its overall financial position.

F-10

option grants and two years of compensation expense related to 2005 option grants will be recognized in the income statement in 2006 and 2007, using the accelerated expense attribution method. Based on options outstanding at December 31, 2005 and using an 8.4% expected forfeiture rate, the Company expects to recognize approximately $200,000 of share based compensation expense in 2006 and approximately $30,000 in 2007 in connection with the adoption of SFAS 123(R).

SFAS 123(R) also requires the benefits of tax deductions in excess of recognized compensation cost to be reflected as a financing cash flow, rather than as an operating cash flow as currently required. The Company did not recognize any excess tax deductions during 2005, 2004 or 2003 in connection with the exercise of stock options.

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


	Year Ended December 31,
	2005			2004			2003
Net income	$	21,417		$	16,348		$	3,640
Stock-based compensation:
Add: expense included in reported results, net of tax		22			177			248
Deduct: fair value based method, net of tax		(688	)		(1,191	)		(541	)

Pro forma net income	$	20,751		$	15,334		$	3,347


Earnings per common share
Basic — as reported	$	0.46		$	0.37		$	0.08
Basic — pro forma	$	0.44		$	0.34		$	0.08
Diluted — as reported	$	0.44		$	0.35		$	0.08
Diluted — pro forma	$	0.43		$	0.33		$	0.08

See Note 10 for additional disclosures of stock-based compensation under SFAS No. 148.

Note 2 — Asset Retirement Obligations

The Company adopted SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003. Retirement obligations associated with long-lived assets included within the scope of SFAS 143 are those for which there is a legal obligation to settle under existing or enacted law, statute, written or oral contract or by legal construction under the doctrine of promissory estoppel. The Company has legal obligations to plug, abandon and dismantle existing wells and facilities that it has acquired and constructed.

The net difference between the Company’s previously depleted abandonment costs and the amounts estimated under SFAS 143, after taxes, totaled a gain of $849,000, which was recognized during 2003 as a cumulative effect of a change in accounting principle. The gain was due to the effect on the historical depletion as a result of the retirement obligation being recorded at fair value.

F-11

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


	Year Ended
	December 31, 2005
Asset retirement obligation at beginning of year	$	16,393

Liabilities incurred (1)		7,105

Liabilities settled		—

Accretion expense		1,253

Revisions in estimated cash flows		(3,144	)


Asset retirement obligation at end of period		21,607
Less: current portion of obligation		(2,350	)


Long-term asset retirement obligation	$	19,257


(1)		Approximately $6.5 million relates to the assumption of estimated abandonment costs in connection with the Company’s acquisition of TDC Energy, Inc (see Note 6).

Note 3 — Equity

Other Comprehensive Income

The following table presents the Company’s comprehensive income for years ended December 31, 2005, 2004 and 2003 (in thousands):


	Year Ended December 31,
	2005			2004			2003
Net income	$	21,417		$	16,348		$	3,640
Change in fair value of derivative instrument, accounted for as hedges, net of taxes		(3,213	)		(3,216	)		182

Comprehensive income	$	18,204		$	13,132		$	3,822

At December 31, 2005, 2004 and 2003, the effect of derivative financial instruments is net of deferred income tax benefits of $1,730,000, $1,732,000 and $546,000, respectively.

The Company accounts for derivatives in accordance with SFAS 133, as amended. When the conditions specified in SFAS 133 are met, the Company may designate these derivatives as hedges. The changes in fair value of derivative instruments that qualify for hedge accounting treatment are recorded to other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the expected event does not occur, or the hedge does not qualify for hedge accounting treatment, changes in the fair value of the derivative are recorded on the income statement.

All of the Company’s derivative instruments qualified for hedge accounting during 2005. As a result, the changes in fair value of these instruments were recorded to other comprehensive income. During 2004 and 2003, the Company recognized $2,000 and $1,071,000 in derivative expense, respectively, on its income statement related to an ineffective gas derivative instrument and an interest rate swap that did not qualify for hedge accounting treatment. These instruments expired during December 2003 and November 2004, respectively.

F-12

Unearned Deferred Compensation

In April 2001, the original owners of American Explorer L.L.C. entered into an agreement with an officer of the Company whereby they granted to the officer an option to acquire, at a fixed price, certain of the original shares the original owners were issued. As the fixed price of the April grant was below the market price as of the date of grant, the Company is recognizing non-cash compensation expense over the three-year vesting period of the option. In addition, the original owners granted to the officer an interest in a portion of the Common Stock issuable pursuant to the Contingent Stock Issue Rights (“CSIRs”), if any, that might be issued. This agreement is similar to agreements previously entered into with two other officers of the Company. Non-cash compensation expense is being recognized for the Common Stock issuable pursuant to the CSIRs granted to the three officers over the three-year vesting period based on the fair value of the Common Stock issuable pursuant to the CSIRs in May 2001, when the Common Stock issuable pursuant to the CSIRs was issued to the original owners. The Company has recorded the effects of the transactions as deferred compensation which became fully amortized during 2004. The Company recognized $69,000 and $381,000, respectively, of non-cash compensation expense during the years ended December 31, 2004 and 2003.

Note 4 — Debt

On May 11, 2005, the Company issued $125 million in principal amount of 10 3/8% Senior Notes due 2012 at 98.783% of their face value. On June 17, 2005, an additional $25 million in principal amount of 10 3/8% Senior Notes due 2012 were issued at 99% of their face value. The Notes are guaranteed by the significant subsidiaries of the Company and PetroQuest Energy, L.L.C. The aggregate assets and revenues of subsidiaries not guaranteeing the Notes constituted less than 3% of the Company’s consolidated assets and revenues at and for the year ended December 31, 2005.

After payment of expenses and the initial purchasers’ discounts, the Company received $144.4 million in net proceeds from the issuance of the Notes. The net proceeds were used to repay all outstanding borrowings under the credit facilities, to fund acquisitions and for general corporate purposes. The Notes are redeemable at the Company’s option beginning on May 15, 2009 at 105.188% of their principal amount and thereafter declining annually to 100% on and after May 15, 2011. In addition, before May 15, 2008, the Company may redeem up to 35% of the aggregate principal amount of the Notes issued with net proceeds from an equity offering at 110.375%. The Notes provide for certain covenants, which include, without limitation, restrictions on liens, incurrence of indebtedness, asset sales, dividend payments and other restricted payments. Interest is payable semi-annually on May 15 and November 15. At December 31, 2005, $1.9 million had been accrued in connection with the May 15, 2006 interest payment. At December 31, 2005, the Company was in compliance with all of the covenants under the Notes.

The Company entered into a $75 million bank credit facility on May 14, 2003. During the second quarter of 2005, all outstanding borrowings under this credit facility were repaid with a portion of the net proceeds received from the issuance of the Notes. On November 18, 2005, the Company and its wholly owned subsidiary, PetroQuest Energy, L.L.C., entered into the Second Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A., as lender, agent and issuer of letters of credit, Macquarie Bank Limited, as lender, and Calyon New York Branch, as lender and syndication agent. The Credit Agreement, which was amended in December 2005, provides for a $100 million revolving credit facility that permits borrowings from time to time based on the available borrowing base as determined in the credit facility. The credit facility also allows for the use of up to $15 million of the borrowing base for letters of credit. The credit facility matures on November 19, 2009.

The credit facility is secured by, among other things, a lien on at least 90% of the PDP present value and at least 80% of the aggregate proved reserves of the Company’s oil and gas properties. PDP present value means the present value discounted at nine percent of the future net revenues attributable to producing reserves. The borrowing base under the credit facility is based upon the valuation as of January 1 and July 1 of each year of the mortgaged oil and gas properties and any other credit factors deemed relevant by the lenders. The borrowing base is currently $40 million, with no reductions scheduled to occur prior to the first borrowing base redermination, which is scheduled to occur prior to April 1, 2006. The Company or the lenders may request additional borrowing base re-determinations.

F-13

British Bankers’ Association LIBOR rate for deposits in U.S. dollars. Outstanding letters of credit will be charged a letter of credit fee equal to the applicable margin for advances at the Eurodollar rate.

As of December 31, 2005, there were $10 million of borrowings outstanding under the credit facility and the Company was in compliance with all of the covenants therein.

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

Note 5 — Related Party Transactions

Two of the Company’s officers, Charles T. Goodson and Stephen H. Green, or their affiliates, are working interest owners and overriding royalty interest owners and E. Wayne Nordberg, one of the Company’s directors, is a working interest owner 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 the year ended December 31, 2005, in their capacities as working interest owners or overriding royalty interest owners, revenues, net of costs were disbursed to Messrs. Goodson and Green, or their affiliates, in the amounts of $313,729 and $254,367, respectively, and with respect to the working interests of Mr. Nordberg, revenues exceeded costs by $20,010. Net amounts received by Messrs. Goodson and Green, or their affiliates, totaled $380,644 and $480,446, respectively, during the year ended December 31, 2004 and $841,350 and $107,367, respectively, during 2003. With respect to the working interests of Mr. Nordberg, during 2004 revenues exceeded costs by $75,509. During the year ended December 31, 2003, costs exceeded revenues with respect to Mr. Nordberg’s working interests by $89,225. 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 approximately 89% of the gross revenue received by him in 2005.

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, 2005, the Company’s joint interest billing receivable included $10,500 from related parties attributable to their share of costs. This represents less than 1% of the Company’s total joint interest billing receivable at December 31, 2005.

Note 6 — Acquisitions

On April 12, 2005, the Company acquired all of the outstanding membership interests of TDC Energy Inc. (“TDC”) an oil and gas exploration company with 12 producing fields and 19 wells in the Gulf of Mexico shelf. Consideration for the acquisition, which was accounted for using purchase accounting, included cash, the issuance of 646,226 shares of common stock valued at approximately $4.1 million, the assumption of certain liabilities and the repayment of approximately $11.5 million in net debt associated with TDC’s operations.

During 2005, the Company closed several acquisitions of gas properties located in Oklahoma for an aggregate purchase price of approximately $36 million. These acquisitions were financed with a portion of the net proceeds received from the issuance of the Notes. At December 31, 2005, approximately $14.7 million of the aggregate purchase price was classified as unevaluated.

F-14

The pro forma effects of the above transactions, as though they occurred as of January 1, 2005, is not material to the operations of the Company.

Note 7 — Investment in Oil and Gas Properties

The following tables disclose certain financial data relative to the Company’s evaluated 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)


	For the Year-Ended December 31,
	2005		2004		2003
Acquisition costs:
Proved	$	58,121	$	23,041	$	22,679
Unproved		24,152		5,963		1,769
Exploration costs:
Proved		39,311		28,298		5,170
Unproved		15,098		—		—
Development costs		51,420		24,204		21,685
Cumulative effect of change in accounting principle		—		—		8,150
Capitalized general and administrative and interest costs		7,719		4,919		4,062


Total costs incurred	$	195,821	$	86,425	$	63,515


	For the Year-Ended December 31,
	2005			2004			2003
Accumulated depreciation, depletion and amortization (DD&A)
Balance, beginning of year	$	(168,453	)	$	(133,482	)	$	(109,450	)
Provision for DD&A		(42,513	)		(34,971	)		(26,654	)
Effect of change in accounting principle		—			—			2,622
Sale of proved properties and other		192			—			—


Balance, end of year	$	(210,774	)	$	(168,453	)	$	(133,482	)


DD&A per Mcfe	$	2.65		$	2.46		$	2.76

Non-cash additions (reductions) to oil and gas properties related to asset retirement obligations, excluding amounts assumed during 2005 in connection with the TDC acquisition, totaled ($2.5) million, $3.1 million and $10.5 million during 2005, 2004 and 2003, respectively. Proved acquisition costs during 2005 included $16.6 million of purchase price adjustments associated with the TDC acquisition, including the assumption of $6.5 million of estimated asset retirement obligations.

At December 31, 2005 and 2004, unevaluated oil and gas properties totaled $52,745,000 and $16,380,000, respectively, and were not subject to depletion. Unevaluated costs at December 31, 2005 included $15,098,000 of costs related to five exploratory wells in progress at year-end and $14,744,000 of acquisition costs related to Oklahoma properties purchased during 2005. All of the unevaluated costs at December 31, 2004 and 2003 related to acquisition costs and related capitalized interest. The Company capitalized $2,912,000 and $883,000 of interest during 2005 and 2004, respectively. Of the total unevaluated oil and gas property costs at December 31, 2005, $42,161,000, or 80%, was incurred in 2005, $3,488,000 was incurred in 2004 and $7,096,000 was incurred in prior years. Management expects that the majority of the unevaluated costs at December 31, 2005 will be evaluated within the next three years.

F-15

Note 8 — Income Taxes

The Company follows the provisions of SFAS No. 109, “Accounting For Income Taxes,” which provides for recognition of a deferred tax asset for deductible temporary timing differences, operating loss carryforwards, statutory depletion carryforwards and tax credit carryforwards net of a “valuation allowance.”

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


	December 31,
	2005			2004
Net operating loss carryforwards	$	22,710		$	12,565
Percentage depletion carryforward		1,994			1,839
Alternative minimum tax credit		105			115
Temporary differences:
Oil and gas properties — full cost		(52,101	)		(29,278	)
Compensation expense		153			153


	$	(27,139	)	$	(14,606	)

For tax reporting purposes, the Company had operating loss carryforwards of $61,048,000 and $33,776,000 at December 31, 2005 and 2004, respectively. If not utilized, such carryforwards would begin expiring in 2006 and would completely expire by the year 2025. The Company had available for tax reporting purposes $5,698,000 in statutory depletion deductions that may be carried forward indefinitely.

Income tax expense for each of the years ended December 31, 2005, 2004 and 2003 (amounts in thousands) was different than the amount computed using the Federal statutory rate (35%) for the following reasons:


	For the Year-Ended December 31,
	2005			2004			2003
Amount computed using the statutory rate	$	11,863		$	8,701		$	1,568
Increase (reduction) in taxes resulting from:
State & local taxes		746			547			99
Percentage depletion carryforward		(155	)		(498	)		(50	)
Other		23			(239	)		73


Income tax expense	$	12,477		$	8,511		$	1,690

Note 9 — 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.

During 2005, the Company entered into a contract to secure a drilling rig for a three-year term. The contract is expected to commence in June 2006 and the estimated future payments under this contract are expected to total $27.4 million.

F-16

Lease Commitments

The Company has operating leases for office space, which expire on various dates through 2010.

Future minimum lease commitments as of December 31, 2005 under these operating leases are as follows (in thousands):


2006	$	821
2007		778
2008		764
2009		771
2010		98
Thereafter		—

	$	3,232

Beginning in July 2003, the Company subleased office space to third parties. For the years ended December 31, 2005, 2004 and 2003, the Company received $79,000, $74,000 and $27,000, respectively, relative to subleased office space. Total rent expense under operating leases, net of amounts received under sublease arrangements, was approximately $768,000, $654,000 and $639,000 in 2005, 2004 and 2003, respectively. A minimum lease rental to be received from the sublease of office space is $33,000 during 2006.

Note 10 — Employee Benefit Plans

The Company currently has one stock option plan. Stock options generally become exercisable 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.

A summary of the Company’s stock options as of December 31, 2005, 2004 and 2003 and changes during the years ended on those dates is presented below:


	Year Ended December 31,
	2005					2004					2003
	Number of			Wgtd. Avg.		Number of			Wgtd. Avg.		Number of			Wgtd. Avg.
	Options			Price		Options			Price		Options			Price
Outstanding at beginning of year		2,664,634		$	2.70		2,069,634		$	3.03		2,197,353		$	3.14
Granted		155,000			6.33		1,239,500			3.32		150,000			1.94
Expired/cancelled/forfeited		(20,834	)		3.37		(556,167	)		5.41		(235,253	)		3.76
Exercised		(487,236	)		1.97		(88,333	)		1.93		(42,466	)		1.23

Outstanding at end of year		2,311,564			3.08		2,664,634			2.70		2,069,634			3.03

Options exercisable at year-end		1,709,373			2.73		1,892,963			2.46		1,690,371			2.77
Options available for future grant		486,899					621,066					1,359,069
Weighted average fair value of options granted during the year	$	6.33				$	1.93				$	1.18

The fair value of each option granted during the periods presented is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions: (a) dividend yield of 0%, (b) expected volatility ranges of 60.86%-64.53%, 64.30%-67.40% and 69.90%-73.90% in 2005, 2004 and 2003, respectively, (c) risk-free interest rate ranges of 3.81%-4.55%, 3.21%-3.98% and 2.93%-3.39% in 2005, 2004 and 2003, respectively, and (d) expected life of 5 years for all grants.

F-17

The following table summarizes information regarding stock options outstanding at December 31, 2005:


Range of		Options		Wgtd. Avg.	Wgtd. Avg.		Options		Wgtd. Avg.
Exercise		Outstanding		Remaining	Exercise		Exercisable		Exercise
Price		12/31/05		Contractual Life	Price		12/31/05		Price
$	0.85 - $1.65		407,300	4.5 years	$	1.32		387,302	$	1.30
$	1.81 - $3.13		575,000	5.4 years	$	2.69		548,336	$	2.71
$	3.17 - $4.24		1,104,264	7.6 years	$	3.28		720,402	$	3.23
$	4.93 - $8.51		225,000	9.2 years	$	6.30		53,333	$	6.65

			2,311,564	6.6 years	$	3.08		1,709,373	$	2.73

Note 11 — Oil and Gas Reserve Information — Unaudited

The Company’s net proved oil and gas reserves at December 31, 2005 have been estimated by independent petroleum consultants in accordance with guidelines established by the Securities and Exchange Commission. Accordingly, the following reserve estimates are based upon existing economic and operating conditions at the respective dates.

The estimates of proved oil and gas reserves constitute quantities that the Company is reasonably certain of recovering in future years. 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.

During 2005, the Company increased its proved reserves by 29%. This increase was primarily due to several acquisitions and the Company’s drilling success during the year, offset in part by a record year of production and approximately 8.5 Bcfe of net downward revisions. The downward revisions were the result of less than expected production performance at a portion of the Company’s Oklahoma acreage and higher prices at December 31, 2005, which had the effect of accelerating the timing of future payouts at the Carthage Field, thus reducing reserve quantities attributable to the Company’s interests. In terms of reserve additions, during 2005 the Company added approximately 23 Bcfe of proved reserves through acquisitions, the most significant of which were three acquisitions of properties in Oklahoma and the acquisition of Gulf Coast Basin reserves attributable to the purchase of TDC Energy, Inc. Significant reserve additions through discoveries during 2005 included the drilling program at the Carthage Field in East Texas where the Company drilled 15 wells, all of which were successful, resulting in reserve additions of approximately 17 Bcfe. Additionally, during 2005 the Company invested $17.9 million on the successful drilling of four exploratory wells at the South Chauvin field onshore Louisiana and booked approximately 8 Bcfe. Overall, the Company had a 91% drilling success rate during 2005 on a company record 86 gross wells drilled.

F-18

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:


	Oil			Natural Gas
	in			and NGL in
	MBbls			MMcfe
Proved reserves as of December 31, 2002		5,258			37,137
Revisions of previous estimates		(369	)		(7,935	)
Extensions, discoveries and other additions		83			6,830
Purchase of producing properties		217			28,410
Sale of producing properties		(200	)		(1,456	)
Production		(744	)		(5,193	)


Proved reserves as of December 31, 2003		4,245			57,793
Revisions of previous estimates		(396	)		3,461
Extensions, discoveries and other additions		559			14,575
Purchase of producing properties		124			12,545
Production		(818	)		(9,305	)


Proved reserves as of December 31, 2004		3,714			79,069
Revisions of previous estimates		(29	)		(8,315	)
Extensions, discoveries and other additions		362			29,966
Purchase of producing properties		294			21,211
Sale of producing properties		(34	)		(758	)
Production		(665	)		(12,058	)


Proved reserves as of December 31, 2005		3,642			109,115


Proved developed reserves

As of December 31, 2003		3,446			34,655


As of December 31, 2004		2,984			50,809


As of December 31, 2005		2,891			73,250

F-19

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


	December 31,
	2005			2004			2003
Future cash flows	$	1,157,283		$	622,941		$	460,073
Future production costs		(195,648	)		(111,165	)		(100,213	)
Future development costs		(99,946	)		(68,289	)		(66,511	)
Future income taxes		(213,222	)		(94,454	)		(53,514	)


Future net cash flows		648,467			349,033			239,835

10% annual discount		(165,055	)		(91,279	)		(64,609	)


Standardized measure of discounted future net cash flows	$	483,412		$	257,754		$	175,226

Changes in Standardized Measure


	Year Ended December 31,
	2005			2004			2003
Standarized measure at beginning of year	$	257,754		$	175,226		$	139,416
Sales and transfers of oil and gas produced, net of production costs		(95,816	)		(69,885	)		(37,577	)
Changes in price, net of future production costs		164,071			46,382			23,007
Extensions and discoveries, net of future production and development costs		168,802			73,535			38,883
Changes in estimated future development costs, net of development costs incurred during this period		6,398			10,122			10,577
Revisions of quantity estimates		(47,025	)		4,076			(35,796	)
Accretion of discount		32,627			21,435			16,605
Net change in income taxes		(87,808	)		(29,375	)		(12,507	)
Purchase of reserves in place		94,834			27,623			40,605
Sale of reserves in place		(1,352	)		—			(3,802	)
Changes in production rates (timing) and other		(9,073	)		(1,385	)		(4,185	)


Standardized measure at end of year	$	483,412		$	257,754		$	175,226

The weighted average prices of oil and gas used with the above tables at December 31, 2005, 2004 and 2003 were $59.66, $43.85 and $32.24 per barrel, respectively, and $8.61, $5.82 and $5.59 per Mcfe, respectively. The Company’s cash flow amounts include a reduction for estimated plugging and abandonment costs that has also been reflected as a liability on the balance sheet at December 31, 2005 and 2004, in accordance with SFAS No. 143.

F-20

Exhibit Index

	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).

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

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

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

	2.5		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, LLC (incorporated by reference to Exhibit 2.3 to Form 8-K filed April 22, 2005).

	2.6		Purchase and Sale Agreement, dated as of April 7, 2005, between Golden Gas Service Company and PetroQuest Energy, LLC (incorporated by reference to Exhibit 2.4 to Form 8-K filed April 22, 2005).

	3.1		Certificate of Incorporation of the Company (incorporated herein by reference to Exhibit 4.1 to Form 8-K dated September 16, 1998).

	3.2		Bylaws of the Company (incorporated herein by reference to Exhibit 4.2 to Form 8-K dated September 16, 1998).

	3.3		Certificate of Domestication of Optima Petroleum Corporation (incorporated herein by reference to Exhibit 4.4 to Form 8-K dated September 16, 1998).

	3.4		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).

	4.1		Warrant to Purchase Common Shares of PetroQuest Energy, Inc. (incorporated by reference to Exhibit 4.1 to Form 8-K filed December 29, 2003).

	4.2		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).

	4.3		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).

	4.4		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 by reference to Exhibit 4.1 to Form 8-K filed May 11, 2005).

	4.5		Registration Rights Agreement dated April 12, 2005, between PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 4.1 to Form 8-K filed April 13, 2005).

	4.6		Registration Rights Agreement dated May 6, 2005, among PetroQuest Energy, Inc., PetroQuest Energy, LLC, the Subsidiary Guarantors identified therein and the Initial Purchasers (incorporated by reference to Exhibit 4.2 to Form 8-K filed May 11, 2005).

	4.7		Registration Rights Agreement dated June 17, 2005, among PetroQuest Energy, Inc., PetroQuest Energy, LLC, the Subsidiary Guarantors identified therein and the Initial Purchasers (incorporated by reference to Exhibit 4.2 to Form 8-K filed June 17, 2005).

	†10.1		PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated effective December 1, 2000 (incorporated herein by reference to Appendix A to Proxy Statement on Schedule 14A filed April 20, 2001).

	10.2		Amended and Restated Credit Agreement, dated as of May 14, 2003, by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Bank One, NA, Banc One Capital Markets, Inc., and certain other Lenders (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed August 13, 2003).

	10.3		Guaranty dated May 14, 2003, between PetroQuest Energy, Inc. and Bank One, NA, as Agent for the Lenders (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed August 13, 2003).

	10.4		First Amendment to Amended and Restated Credit Agreement dated as of November 6, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc.; Bank One, N.A., and Union Bank of California, N.A. (incorporated herein by reference to Exhibit 10.4 to Form 10-Q filed November 13, 2003).

	10.5		Second Amendment to Amended and Restated Credit Agreement dated as of December 23, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., and Bank One, N.A. (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed December 29, 2003).

	10.6		Third Amendment to Amended and Restated Credit Agreement dated as of July 27, 2004, by and among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., and Bank One, N.A. (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed July 30, 2004).

	10.7		Fourth Amendment to Amended and Restated Credit Agreement dated as of October 14, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc. and Bank One, N.A. (incorporated by reference to Exhibit 10.1 on Form 8-K filed October 19, 2004).

	10.8		Fifth Amendment to Amended and Restated Credit Agreement entered into as of November 3, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc. (a wholly owned subsidiary of PetroQuest Energy, LLC) and Bank One, N.A. (incorporated by reference to Exhibit 10.1 on Form 8-K filed November 15, 2004).

	10.9		Sixth Amendment to Amended and Restated Credit Agreement dated April 12, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Acquisition Sub LLC, and JP Morgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to Form 8-K filed April 13, 2005).

	10.10		Seventh Amendment to Amended and Restated Credit Agreement dated May 9, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JP Morgan Chase Bank, N.A. (incorporated by reference to Exhibit 10.1 to Form 8-K filed May 11, 2005).

	10.11		Eighth Amendment to Amended and Restated Credit Agreement dated June 17, 2005, by and among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans Inc., TDC Energy LLC, and JP Morgan Chase Bank, N.A., Guaranty Bank, FSB and Calyon New York Branch (incorporated by reference to Exhibit 10.1 to Form 8-K filed June 17, 2005).

	10.12		Second Amended and Restated Credit Agreement dated as of November 18, 2005, among PetroQuest Energy, LLC, PetroQuest Energy, Inc., JP Morgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed November 23, 2005).

	10.13		Amendment No. 1 to Second Amended and Restated Credit Agreement dated as of December 22, 2005, among PetroQuest Energy, LLC, PetroQuest Energy, Inc., Pittrans, Inc., TDC Energy LLC, JP Morgan Chase Bank, N.A. as lender, agent and issuer of letters of credit, Macquarie Bank Limited as lender, and Calyon New York Branch as lender and syndication agent (incorporated by reference to Exhibit 10.1 to Form 8-K filed December 22, 2005).

	10.14		Senior Second Lien Secured Credit Agreement dated November 6, 2003, between PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto; and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed November 13, 2003).

	10.15		Unconditional Guaranty Agreement dated November 6, 2003, by PetroQuest Energy, Inc. to Macquarie Americas Corp., as administrative agent for the benefit of the Lenders under the Credit Agreement (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed November 13, 2003).

	10.16		First Amendment To Second Lien Secured Credit Agreement dated December 23, 2003, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto, and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed December 29, 2003).

	10.17		Second Amendment to Second Lien Secured Credit Agreement dated July 27, 2004, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the Lenders from time to time party thereto, and Macquarie Americas Corp., as administrative agent for the Lenders (incorporated herein by reference to Exhibit 10.2 to Form 10-Q filed July 30, 2004).

	10.18		Third Amendment to Second Lien Secured Credit Agreement dated as of October 14, 2004 by and between PetroQuest Energy, LLC, PetroQuest Energy, Inc. and Macquarie Bank Limited (incorporated by reference to Exhibit 10.2 on Form 8-K filed October 19, 2004).

	10.19		Fourth Amendment to Second Lien Secured Credit Agreement dated as of December 29, 2004 by and between PetroQuest Energy, LLC and Macquarie Bank Limited (incorporated by reference to Exhibit 10.1 on Form 8-K filed December 30, 2004).

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

	†10.21		Employment Agreement dated September 1, 1998, between PetroQuest Energy, Inc. and Charles T. Goodson (incorporated herein by reference to Exhibit 10.2 to Form 8-K dated September 16, 1998).

	†10.22		First Amendment to Employment agreement dated September 1, 1998 between PetroQuest Energy, Inc. and Charles T. Goodson dated July 30, 1999 (incorporated herein by reference to Exhibit 10.1 to For 8-K dated August 9, 1999).

	†10.23		Employment Agreement dated September 1, 1998, between PetroQuest Energy, Inc. and Ralph J. Daigle (incorporated herein by reference to Exhibit 10.4 to Form 8-K dated September 16, 1998).

	†10.24		First Amendment to Employment Agreement dated September 1, 1998 between PetroQuest Energy, Inc. and Ralph J. Daigle dated July 30, 1999 (incorporated herein by reference to Exhibit 10.3 to Form 8-K dated August 9, 1999).

	†10.25		Severance Agreement and Release, effective April 8, 2005, between PetroQuest Energy, Inc. and Ralph J. Daigle (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed April 22, 2005).

	†10.26		Employment Agreement dated May 8, 2000 between PetroQuest Energy, Inc. and Michael O. Aldridge (incorporated by reference to Exhibit 10.1 to the Form 10-Q filed August 14, 2000).

	†10.27		Employment Agreement dated December 15, 2000 between PetroQuest Energy, Inc. and Arthur M. Mixon, III. (incorporated herein by reference to Exhibit 10.12 to Form 10-K filed March 30, 2001).

	†10.28		Employment Agreement dated April 20, 2001 between PetroQuest Energy, Inc. and Daniel G. Fournerat (incorporated herein by reference to Exhibit 10.1 to Form 10-Q filed May 15, 2001).

	†10.29		Employment Agreement dated April 20, 2001 between PetroQuest Energy, Inc. and Dalton F. Smith III (incorporated herein by reference to Exhibit 10.21 to Form 10-K filed March 13, 2002).

	†10.30		Employment agreement dated July 28, 2003, between PetroQuest Energy, Inc. and Stephen H. Green (incorporated herein by reference to Exhibit 10.3 to Form 10-Q filed November 13, 2003).

	†10.31		Form of Termination Agreement Between PetroQuest Energy, Inc. and each of its executive officers, including Charles T. Goodson, Michael O. Aldridge, Arthur M. Mixon, III, Daniel G. Fournerat, Dalton F. Smith III and Stephen H. Green (incorporated herein by reference to Exhibit 10.20 to Form 10-K filed March 13, 2002).

	†10.32		Form of Indemnification Agreement between PetroQuest Energy, Inc. and each of its directors and executive officers, including Charles T. Goodson, Ralph J. Daigle, Daniel G. Fournerat, E. Wayne Nordberg, William W. Rucks, IV, Michael O. Aldridge, Arthur M. Mixon, III, Dalton F. Smith III, Michael L. Finch, W.J. Gordon, III, Stephen H. Green and Charles F. Mitchell, II (incorporated herein by reference to Exhibit 10.21 to Form 10-K filed March 13, 2002).

	*14.1		Code of Business Conduct and Ethics.

	*21.1		Subsidiaries of the Company.

	*23.1		Consent of Independent Auditors.

	*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.


		Page No.
	PART I

Item 1.	Business		2

Item 1A.	Risk Factors		9

Item 1B.	Unresolved Staff Comments		18

Item 2.	Properties		18

Item 3.	Legal Proceedings		21

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

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		21

Item 6.	Selected Financial Data		22

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22

Item 7A.	Quantitative and Qualitative Disclosure About Market Risk		31

Item 8.	Financial Statements and Supplementary Data		32

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		32

Item 9A.	Controls and Procedures		32

Item 9B.	Other Information		34

	PART III

Item 10.	Directors and Executive Officers of the Registrant		34

Item 11.	Executive Compensation		34

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		34

Item 13.	Certain Relationships and Related Transactions		34

Item 14.	Principal Accounting Fees and Services		34

	PART IV

Item 15.	Exhibits, Financial Statement Schedules		35

	Index to Financial Statements.		F-1
Code of Business Conduct and Ethics
Subsidiaries of the Company
Consent of Independent Auditors
Consent of Ryder Scott Company, L.P.
Certification of CEO pursuant to Rule 13a-14a/15d-14a
Certification of CFO pursuant to Rule 13a-14a/15d-14a
Certification pursuant to Section 906
Certification pursuant to Section 906


Report of Independent Registered Public Accounting Firm			F-2

Consolidated Balance Sheets of PetroQuest Energy, Inc. as of December 31, 2005 and 2004			F-3

Consolidated Statements of Income of PetroQuest Energy, Inc. for the years ended December 31, 2005, 2004 and 2003			F-4

Consolidated Statements of Stockholders’ Equity of PetroQuest Energy, Inc. for the years ended December 31, 2005, 2004 and 2003			F-5

Consolidated Statements of Cash Flows of PetroQuest Energy, Inc. for the years ended December 31, 2005, 2004 and 2003			F-6

Notes to Consolidated Financial Statements			F-7


	Quarter Ended
	March-31		June-30		September-30		December-31
2005:
Revenues	$	21,743	$	30,279	$	31,381	$	39,945
Expenses		17,556		26,414		26,336		31,625

Net income	$	4,187	$	3,865	$	5,045	$	8,320

Earnings per share:
Basic	$	0.09	$	0.08	$	0.11	$	0.18
Diluted	$	0.09	$	0.08	$	0.10	$	0.17

2004:
Revenues	$	18,202	$	21,497	$	22,572	$	22,597
Expenses		15,030		17,260		18,632		17,598

Net income	$	3,172	$	4,237	$	3,940	$	4,999

Earnings per share:
Basic	$	0.07	$	0.10	$	0.09	$	0.11
Diluted	$	0.07	$	0.09	$	0.08	$	0.11


(1)		The above quarterly earnings per share may not total to the full year per share amount, as the weighted average number of shares outstanding for each quarter fluctuated as a result of the assumed exercise of stock options.