PETROQUEST ENERGY INC - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2002

or

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

For the transition period from to

Commission File Number: 019020

PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)

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: None

Securities registered pursuant to Section 12 (g) of the Act:
Common Stock, Par Value $.001 Per Share
Preferred Stock Purchase Rights
(Title of Class)

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

[X] Yes [ ] No

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

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

[X] Yes [ ] No

The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $155,451,520 as of June 28, 2002 (based on
the last reported sale price of such stock on The Nasdaq National Market
System).

As of March 10, 2003, the registrant had outstanding 42,852,394 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 7,
2003, which is incorporated 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 Discussions 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 in these 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.

PART I

ITEM 1. BUSINESS

OVERVIEW

PetroQuest Energy, Inc. ("PetroQuest" or the "Company") is incorporated
in the State of Delaware and is an independent oil and gas company engaged in
the generation, exploration, development, acquisition and operation of oil and
gas properties onshore and offshore in the Gulf Coast Region. PetroQuest and its
predecessors have been active in this area since 1986. The Company's business
strategy is to increase production, cash flow and reserves through generation,
exploration, development and acquisition of properties located in the Gulf Coast
Region.

On September 1, 1998, the Company, formerly known as Optima Petroleum
Corporation ("Optima"), completed a merger and reorganization (the "Merger")
pursuant to a Plan and Agreement of Merger dated February 11, 1998 by and among
Optima, Optima Energy (U.S.) Corporation ("Optima (U.S.)"), Goodson Exploration
Company ("Goodson"), NAB Financial, L.L.C. ("NAB") and Dexco Energy, Inc.
("Dexco"), pursuant to which Optima (U.S.) merged into PetroQuest Energy, Inc.,
a newly formed Louisiana corporation ("PetroQuest Louisiana"). Concurrently,
PetroQuest Louisiana, through a merger of PetroQuest Louisiana with Goodson, NAB
and Dexco, acquired 100% of the ownership interest of American Explorer L.L.C.
("American Explorer"), all which were owned by Goodson, NAB and Dexco prior to
the Merger. Concurrent with the Merger, PetroQuest continued from a Canadian
corporation to a Delaware corporation, converted each share of Optima no par
value common stock into one share of the Company's $.001 par value common stock,
changed its name to "PetroQuest Energy, Inc." and adopted a new certificate of
incorporation. The operating results of American Explorer have been consolidated
in the Company's consolidated statement of operations since September 1, 1998.

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In addition, management of PetroQuest was changed to the management of
American Explorer. The Canadian offices were closed and the Company's
headquarters were moved to Lafayette, Louisiana. PetroQuest maintains an
offshore exploration office in Houston, Texas.

On December 31, 2000, the Company underwent a corporate reorganization.
The Company's subsidiary, PetroQuest Energy, Inc., a Louisiana corporation, was
merged into PetroQuest Energy One, L.L.C., a Louisiana limited liability
company. In addition, PetroQuest Energy One, L.L.C. changed its name to
PetroQuest Energy, L.L.C., a single-member Louisiana limited liability company,
and PetroQuest Energy, Inc., a Delaware corporation, continues to be its sole
member.

DEFINED TERMS

The Company has provided definitions for some of the oil and natural
gas industry terms used in this Form 10-K in "Glossary of Oil and Natural Gas
Terms" on page 31.

OUR STRATEGY

Our business strategy is to build shareholder value by increasing per
share reserves, production, cash flow and earnings at low finding and
development costs through the exploration and development of properties located
in the Gulf Coast Basin, either onshore or in shallow waters offshore. We plan
to achieve this goal by continuing to:

o Focus on the Gulf Coast Basin. We have assembled a large acreage
position and 3-D seismic database in the Gulf Coast Basin because we
believe this area represents one of the most attractive exploration
and development regions in North America. We also believe our
management and technical team's expertise and experience developed
over the last 25 years will allow us to develop attractive
reinvestment opportunities that will permit continuing growth.

o Target under-exploited fields that have low current production levels.
Using a rigorous prospect selection process that enables us to
leverage our experience and knowledge of the Gulf Coast Basin, we
target properties with an established production history and existing
infrastructure. These fields have often produced from only shallower
sands and contain multiple productive horizons that were not targeted
during their initial phase of development. By targeting properties
with limited current production, our acquisition costs are typically
only a small portion of the total capital we will employ over the life
of the project.

o Emphasize and apply technical expertise. By applying the latest 3-D
and other geoscience technologies to under-exploited properties, we
believe we can identify opportunities to significantly increase
reserves and production from these properties.

o Operate properties and balance risk. By operating our properties, we
can better control the timing and execution of our exploration and
development plans. We also balance the risk and reward potential of
our prospects by determining our desired working interest and selling
the remainder to industry partners on terms where they often agree to
pay a disproportionate share of drilling costs relative to their
interests. Our management team has developed many successful
relationships with major, integrated and large independent producers.
We believe these relationships allow us to allocate our capital
spending in a way that maximizes return while reducing the inherent
risk of exploration activities.

o Maintain our financial flexibility. We seek to maintain unused
borrowing capacity under our bank credit facility in order to take
advantage of new opportunities. We also evaluate potential property
acquisitions and dispositions, and routinely discuss those
opportunities with third parties. While dispositions of producing
properties reduce current revenues, sales of properties can provide
additional capital for exploration and development of properties that
are more important to our long-term growth.

EXPLORATION AND DEVELOPMENT

The Company is engaged in the exploration, development, acquisition and
operation of oil and gas properties onshore and offshore in the Gulf Coast
Region. As of December 31, 2002, the Company's estimated proved reserves totaled
5,258 MBbl of oil and 37,137 MMcf 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 $166,048,000. Approximately
62% of the

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Company's reserves are proved developed reserves. The Company operates 11 fields
representing approximately 95% of the total discounted cash flow attributable to
estimated proved reserves.

SIGNIFICANT PROPERTIES

SHIP SHOAL 72, FEDERAL OUTER CONTINENTAL SHELF WATERS. PetroQuest
acquired an 85% working interest in 14,000 acres in the fourth quarter of 2000
and the remaining 15% working interest in this field during 2001. During 2002,
the Company drilled and completed five wells, and the field produced
approximately 7 Bcfe net to the Company from 11 producing wells. Additional
developmental opportunities and exploration potential in a deeper horizon have
been identified and are currently being evaluated for future drilling. Current
plans call for seven additional developmental wells and three exploratory wells.
We may seek to obtain an industry partner in the future development of this
property. Reprocessed 3-D data is currently being reviewed for additional
opportunities.

TURTLE BAYOU FIELD, TERREBONNE PARISH, LA. As of December 31, 2002,
there are four producing wells in the field in which we hold a working interest.
Collectively, the four producing wells averaged approximately 3,060 Mcf of
natural gas and 80 barrels of oil per day, net to the Company, for the year
ended December 31, 2002. Our working interest varies between 14% and 43% with a
weighted average working interest of approximately 34%. PetroQuest acquired a
3-D regional seismic survey shot in 1998, which incorporates the Turtle Bayou
Field. As a result of studying this data, six additional prospects with multiple
objectives have been identified. The first five wells have been drilled and the
Company has completed four of these wells as of December 31, 2002.

VERMILION BLOCK 376, FEDERAL OUTER CONTINENTAL SHELF WATERS ("FALCON
PROSPECT"). The Company and its partners drilled a well on this property in the
fourth quarter of 1999 and logged 285 feet of gross hydrocarbon column (136 feet
net). An additional well was drilled in the second quarter of 2000 logging 112
feet of gross hydrocarbon pay (74 feet net). PetroQuest is the operator of the
project and owns a 43% working interest. During 2000, an approximately 2,500 ton
production platform was fabricated and placed in service. During 2002 the field
produced at an average rate of approximately 590 Bbls per day of oil and 840 Mcf
per day of natural gas, net to the Company.

BERRY LAKE FIELD, IBERVILLE PARISH, LA. The Company and its partners
drilled a well on this property in the third quarter of 2002 and logged
approximately 71 feet of net productive sands. The well came on line during the
fourth quarter and produced at an average rate for December of approximately 350
Bbls per day of oil and 560 Mcf per day of natural gas, net to the Company.

EUGENE ISLAND 147, FEDERAL OUTER CONTINENTAL SHELF WATERS. PetroQuest
initially had a 25% working interest in this lease and acquired the remaining
75% working interest from a major oil and gas company. A 63.5% working interest
was subsequently sold to other oil and gas companies and we currently hold a
36.5% working interest. During 2000, we drilled two successful wells on this
offshore block, and 2002 production averaged approximately 2,060 Mcfe per day
net to PetroQuest. Additional exploration opportunities have been identified and
are currently being evaluated for future drilling.

MARKETS

PetroQuest's ability to market oil and gas from the Company's wells
depends upon numerous factors beyond the Company's control, including:

o the extent of domestic production and imports of oil and gas,

o the proximity of the gas production to gas pipelines,

o the availability of capacity in such pipelines,

o the demand for oil and gas by utilities and other end users,

o the availability of alternative fuel sources,

o the effects of inclement weather,

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o state and federal regulation of oil and gas production, and

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

No assurance can be given that PetroQuest will be able to market all of
the oil or gas produced by the Company or that favorable prices can be obtained
for the oil and gas PetroQuest produces.

In view of the many uncertainties affecting the supply and demand for
oil, gas and refined petroleum products, the Company is 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, 2002, the Company had three
customers who accounted for 25%, 22% and 19% of total revenues, respectively.
For the year ended December 31, 2001, the Company had four customers who
accounted for 19%, 19%, 15% and 13% of total revenues, respectively. For the
year ended December 31, 2000, the Company had three customers who accounted for
58%, 15% and 11% of total revenues, respectively. PetroQuest does not believe
that the loss of any of the Company's oil or gas purchasers would have a
material adverse effect on the Company's 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 sales of
gas by the Company 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.

Beginning in April 1992, the FERC issued Order No. 636 and a series of
related orders, which required interstate pipelines to provide open-access
transportation on a not unduly discriminatory basis for all natural gas
shippers. The FERC has stated that it intends for Order No. 636 and its future
restructuring activities to foster increased competition within all phases of
the natural gas industry. Although Order No. 636 does not directly regulate our
production and marketing activities, it does affect how buyers and sellers gain
access to the necessary transportation facilities and how we and our competitors
sell natural gas in the marketplace.

The courts have largely affirmed the significant features of Order No.
636 and the numerous related orders pertaining to individual pipelines. However,
some appeals remain pending and the FERC continues to review and modify its
regulations regarding the transportation of natural gas. For example, the FERC
issued Order No. 637 which;

o lifts the cost-based cap on pipeline transportation rates in
the capacity release market until September 30, 2002, for
short-term releases of pipeline capacity of less than one
year,

o permits pipelines to file for authority to charge different
maximum cost-based rates for peak and off-peak periods,

o encourages, but does not mandate, auctions for pipeline
capacity,

o requires pipelines to implement imbalance management services,

o restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders, and

o implements a number of new pipeline reporting requirements.

Order No. 637 also requires the FERC staff to analyze whether the FERC
should implement additional fundamental policy changes. These include whether to
pursue performance-based or other non-cost based ratemaking techniques and
whether the FERC should mandate greater standardization in terms and conditions
of service across the interstate pipeline grid.

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In April 1999 the FERC issued Order No. 603, which implemented new
regulations governing the procedure for obtaining authorization to construct new
pipeline facilities. In September 1999, the FERC issued a related policy
statement establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates for service on new pipeline facilities based
solely on the costs associated with such new pipeline facilities.

We cannot predict what further action the FERC will take on these
matters, nor can we accurately predict whether the FERC's actions will achieve
the goal of increasing competition in markets in which our natural gas is sold.
However, we do not believe that any action taken will affect the Company in a
way that materially differs from the way it affects other natural gas producers,
gatherers and marketers.

The Outer Continental Shelf Lands Act, which the FERC implements as to
transportation and pipeline issues, requires that all pipelines operating on or
across the Outer Continental Shelf provide open-access, non-discriminatory
service. Historically, the FERC has opted not to impose regulatory requirements
under its Outer Continental Shelf Lands Act authority on gatherers and other
entities outside the reach of its NGA jurisdiction. However, the FERC in 2000
issued Order No. 639 and 639-A, requiring that virtually all non-proprietary
pipeline transporters of natural gas on the Outer Continental Shelf report
information on their affiliations, rates and conditions of service. The
reporting requirements established by the FERC in Order No. 639 and 639-A may
apply, in certain circumstances, to operators of production platforms and other
facilities on the Outer Continental Shelf, with respect to gas movements across
such facilities. Certain offshore service providers have requested FERC to treat
certain information as confidential and not subject to public review. On
September 13, 2001, FERC issued an order denying confidential treatment;
however, on January 11, 2002, the United States District Court for the District
of Columbia granted the motion for summary judgment of the offshore service
providers seeking confidential treatment of certain information they are
required to report. FERC has indicated that it will appeal. Among the FERC's
stated purposes in issuing such rules was the desire to increase transparency in
the market, to provide producers and shippers on the Outer Continental Shelf
with greater assurance of (a) open-access services on pipelines located on the
Outer Continental Shelf and (b) non-discriminatory rates and conditions of
service on such pipelines.

The FERC retains authority under the Outer Continental Shelf Lands Act
to exercise jurisdiction over gatherers and other entities outside the reach of
its NGA jurisdiction if necessary to ensure non-discriminatory access to service
on the Outer Continental Shelf. We do not believe that any FERC action taken
under its Outer Continental Shelf Lands Act jurisdiction will affect us in a way
that materially differs from the way it affects other natural gas producers,
gatherers and marketers.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.

SALES AND TRANSPORTATION OF CRUDE OIL. Sales of crude oil, condensate
and natural gas liquids by the Company 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 all
the initial and reply comments, the FERC concluded on December 14, 2000 that the

5

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. The Company maintains 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 the Company in a way
that materially differs from the way it affects other oil and gas producers,
gathers and marketers.

FEDERAL, STATE OR AMERICAN INDIAN LEASES. In the event the Company
conducts 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.
The Company owns interests in numerous federal onshore oil and gas leases. It is
possible that holders of equity interests in the Company 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:

o requirements for obtaining drilling permits,

o the method of developing new fields,

o the spacing and operation of wells,

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o the prevention of waste of oil and gas resources, and

o 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.

The Company 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 which the Company
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 the Company's operations.

ENVIRONMENTAL REGULATIONS

GENERAL. The Company's activities are subject to existing federal,
state and local laws and regulations governing environmental quality and
pollution control. Although no assurances can be made, the Company believes
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 the capital expenditures,
earnings or the competitive position of the Company with respect to its existing
assets and operations. The Company 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
the Company's operations could have on its activities.

Activities of PetroQuest with respect to natural gas facilities,
including the operation and construction of pipelines, plants and other
facilities for transporting, processing, treating or storing natural gas and
other 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 the
Company believes that compliance with environmental regulations will not have a
material adverse effect on it, 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 the
Company.

SOLID AND HAZARDOUS WASTE. The Company owns or leases numerous
properties that have been used for production of oil and gas for many years.
Although the Company has 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. The Company 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, the Company 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.

The Company generates 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 the

7

Company's 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 found 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. Neither the Company nor its predecessors have been designated as a
potentially responsible party by the EPA under CERCLA 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. The Company believes it currently has established adequate
financial responsibility. While financial responsibility requirements under OPA
may be amended to impose additional costs on the Company, the impact of any
change in these requirements should not be any more burdensome to the Company
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. The
Company is required to prepare and comply with such plans and to obtain and
comply with discharge permits. The Company believes it is in substantial
compliance with these requirements and that any noncompliance would not have a
material adverse effect on it. 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. The operations of the Company 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 the Company to forego construction or operation of certain air emission
sources. The Company believes that it is in substantial compliance with air
pollution control requirements and that, if a particular permit application were
denied, it would have enough permitted or permittable capacity to continue its
operations without a material adverse effect on any particular producing field.

OSHA. The Company is 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 the Company to organize and/or disclose
information about hazardous materials used or produced in its operations.
Certain of this information must be provided to employees, state and local
governmental authorities and local citizens.

Management believes that the Company is 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
the Company.

8

EMPLOYEES

The Company had 57 employees as of December 31, 2002. In addition to
the services of its full time employees, the Company utilizes the services of
independent contractors to perform certain services. PetroQuest believes that
its relationships with its employees are satisfactory. None of the Company's
employees are covered by a collective bargaining agreement.

INTERNET WEBSITE

PetroQuest's Internet website can be found at www.petroquest.com.
PetroQuest makes available free of charge, or through the "Financials" section
of our Internet 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.

RISK FACTORS

RISKS RELATED TO OUR BUSINESS, INDUSTRY AND STRATEGY

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

As is generally the case in the Gulf Coast Basin, many of our producing
properties are characterized by a high initial production rate, followed by a
steep decline in production. As a result, we must 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.

We may not be able to maintain our historical rates of growth.

We may not be able to maintain the rate of growth in our reserves,
production and financial results that we have achieved since our management team
acquired its equity interest in PetroQuest. Our growth rates have to a certain
extent been unusually high because PetroQuest was a very small company, with
total reserves of approximately 14 Bcfe as of December 31, 1998. As a result, as
we continue to grow, our growth rates may be lower than those achieved in our
recent history.

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 us.

Our revenues, 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
depend 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:

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

o market uncertainty;

o the level of consumer product demand;

o weather conditions in the United States;

o the condition of the United States economy;

o the action of the Organization of Petroleum Exporting Countries;

9

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

o political instability in the Middle East and elsewhere;

o the foreign supply of oil and natural gas;

o the price of foreign imports; and

o the 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 prices may decline. Declines in oil and natural gas prices may adversely
affect our financial condition, liquidity 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.

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

This document contains estimates of oil and natural gas reserves, and
the future net cash flows attributable to those reserves, prepared by Ryder
Scott Company, L.P., our independent petroleum and geological engineers. There
are 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:

o the available data;

o assumptions regarding future oil and natural gas prices;

o estimated expenditures for future development and exploitation
activities; and

o 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 document. In addition, reserve
engineers may make different estimates of reserves and cash flows based on the
same available data. In calculating reserves on a Mcfe basis, oil was converted
to natural gas equivalent at the ratio of six Mcf of natural gas to one Bbl of
oil. While this ratio approximates the energy equivalency of natural gas to oil
on a Btu basis, it may not represent the relative prices received by us from the
sale of our oil and natural gas production.

Approximately 38% of our estimated proved reserves are undeveloped.
Estimates of undeveloped 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 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.

10

You should not assume that the present value of future net revenues
referred to in this document and the information incorporated by reference is
the current market value of our estimated oil and natural gas reserves. In
accordance with Securities and Exchange Commission requirements, the estimated
discounted future net cash flows from proved reserves are generally 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 Securities and
Exchange 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.

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 net capitalized costs of
oil and natural gas properties exceed the ceiling limit, we must charge the
amount of the excess to earnings. 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.

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:

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

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

o the availability of pipeline capacity;

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

o the availability of alternate fuel sources;

o the effect of inclement weather;

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

o 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.

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:

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

11

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

o the intermediate 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.

RISKS RELATING TO FINANCING OUR BUSINESS

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

We have historically addressed our long-term liquidity needs through the
use of credit facilities, the issuance of equity securities and the use of cash
provided by operating activities. We continue to examine the following
alternative sources of long-term capital:

o borrowings from banks or other lenders;

o the issuance of debt securities;

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

o joint venture financing; and

o 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 and our
market value and operating performance. We may be unable to execute our
operating strategy if we cannot obtain capital from these sources.

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 complete 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.

Leverage may materially affect our operations.

We presently have and may incur from time to time debt under our bank
credit facility. The borrowing base limitation on 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 level of debt affects our operations in several important ways,
including the following:

o a portion of our cash flow from operations is used to pay interest on
borrowings;

o the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds or to dispose of assets;

o the covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes in
business conditions;

12

o a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes;

o our leveraged financial position may make us more vulnerable to
economic downturns and may limit our ability to withstand competitive
pressures;

o any debt that we incur under our credit facilities will be at variable
rates, which could make us vulnerable to increases in interest rates;
and

o a high level of debt will affect our flexibility in planning for or
reacting to changes in market conditions.

In addition, we may significantly alter our capitalization in order to
make future acquisitions or develop our properties. These changes in
capitalization may significantly increase our level of debt. A higher level of
debt increases the risk that we may default on our debt obligations. Our ability
to meet our debt obligations and to reduce our level of debt depends on our
future performance. General economic conditions and financial, business and
other factors affect our operations and our future performance. Many of these
factors are beyond our control.

If we are unable to repay our debt at maturity out of cash on hand, we
could attempt to refinance such debt, or repay such debt with the proceeds of an
equity offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that future borrowings
or equity financing will be available to pay or refinance such debt. The terms
of our bank credit facility may also prohibit us from taking such actions.
Factors that will affect our ability to raise cash through an offering of our
capital stock or a refinancing of our debt include financial market conditions
and our market value and operating performance at the time of such offering or
other financing. We cannot assure you that any such offering or refinancing can
be successfully completed.

RISKS RELATING TO OUR ONGOING OPERATIONS

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

Our operations are dependent upon a relatively small group of key
management and technical personnel. 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 these individuals could have a detrimental
effect on our operations.

Operating hazards may adversely affect our ability to conduct business.

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

o unexpected drilling conditions including blowouts, cratering and
explosions;

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

o equipment failures, fires or accidents;

o pollution and other environmental risks; and

o 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.

13

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.

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.

Compliance with environmental and other government regulations is
costly and could negatively impact production.

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

o require the acquisition of permits before drilling commences;

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

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

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

o impose substantial liabilities for pollution resulting from our
operations.

The recent 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 may create
conflicts of interest.

Certain of our executive officers and directors or their respective
affiliates are working interest owners or overriding royalty interest owners in
particular 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. A conflict of
interest may exist between us and such officers and directors with respect to
the drilling of additional wells or other development operations with respect to
these properties.

14

RISKS RELATING TO OUR COMMON STOCK OUTSTANDING

Our management controls a significant percentage of our outstanding
common stock and their interests may conflict with those of our stockholders.

Our directors and executive officers and their affiliates beneficially
own about 25% of our outstanding common stock at March 7, 2003. If these persons
were to act in concert, they would, as a practical matter, be able to
effectively control our affairs. This concentration of ownership could also have
the effect of delaying or preventing a change in control of or otherwise
discouraging a potential acquiror from attempting to obtain control of us. This
could have a material adverse effect on the market price of our common stock or
prevent our stockholders from realizing a premium over the then prevailing
market prices for their shares of our 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 exploration and development drilling program,
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 our corporate documents could delay or prevent a change
in control of our company, even if that change would be beneficial to our
stockholders.

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

o the charter authorization of "blank check" preferred stock;

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

o a restriction on the ability of stockholders to take actions by
written consent.

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.

NOTICE REGARDING CONSENT OF ARTHUR ANDERSEN LLP

On June 15, 2002, Arthur Andersen LLP, our former independent auditors,
was convicted of federal obstruction of justice. On June 28, 2002, our Board of
Directors, upon the approval of its Audit Committee, engaged Ernst & Young, LLP
as independent auditors and dismissed Arthur Andersen LLP. After reasonable
efforts, we have not been able to obtain the consent of Arthur Andersen LLP to
the incorporation by reference of its audit report dated March 7, 2002 into our
registration statements on Form S-3 and Form S-8. As permitted under Rule 437a
promulgated under the Securities Act of 1933, we have not filed the written
consent of Arthur Andersen LLP that would otherwise be required by the
Securities Act. Because Arthur Andersen LLP has not consented to the
incorporation of reference of their report in these registration statement, you
may not be

15

able to recover amounts from Arthur Andersen LLP under Section 11(a) of the
Securities Act for any untrue statement of a material fact or any omission to
state a material fact, if any, contained in or omitted from our financial
statements included in our Annual Report on Form 10-K for the fiscal year ended
December 31, 2001, which are incorporated by reference in these registration
statements.

ITEM 2. PROPERTIES

For a description of the Company's exploration and development
activities and its significant properties, see Item 1. Business-Exploration and
Development and - Significant Properties.

OIL AND GAS RESERVES

The following table sets forth certain information about the estimated
proved reserves of the Company as of December 31, 2002.

Ryder Scott Company, L.P. prepared the estimates of proved reserves and
future net cash flows (and present value thereof) attributable to such proved
reserves at December 31, 2002. Reserves were estimated using oil and gas prices
and production and development costs in effect at December 31, 2002 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 $30.44 per
Bbl of oil and $4.48 per MMBtu of gas. Because of the high Btu content of the
Company's Gulf Coast gas, this equates to an average price realized of
approximately $4.79 per Mcf.

The Company has not filed any reports with other federal agencies which
contain an estimate of total proved net oil and gas reserves.

16

OIL AND GAS DRILLING ACTIVITY

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

The Company owned working interests in 31 gross (15.7 net) producing
oil and gas wells at December 31, 2002. At December 31, 2002, the Company had
one well in progress.

LEASEHOLD ACREAGE

The following table shows the approximate developed and undeveloped
(gross and net) leasehold acreage of the Company as of December 31, 2002:

TITLE TO PROPERTIES

The Company believes that the title to its 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 the opinion of the
Company, are not so material as to detract substantially from the use or value
of such properties. The Company's properties are typically subject, in one
degree or another, to one or more of the following:

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

o overriding royalties and other burdens created by the Company or its
predecessors in title,

o 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,

o back-ins and reversionary interests existing under purchase agreements
and leasehold assignments,

o 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,

17

o pooling, unitization and communitization agreements, declarations and
orders, and

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

To the extent that such burdens and obligations affect the Company's
rights to production revenues, they have been taken into account in calculating
the Company's net revenue interests and in estimating the size and value of the
Company's reserves. The Company believes that the burdens and obligations
affecting its properties are conventional in the industry for properties of the
kind owned by the Company.

ITEM 3. LEGAL PROCEEDINGS

There are no legal proceedings to which the Company or its subsidiaries
is a party or by which any of its property is subject, other than ordinary and
routine litigation due to the business of producing and exploring for oil and
natural gas, except as follows:

PetroQuest Energy, Inc. f/k/a Optima Energy (U.S.) Corp. v. The
Meridian Resource & Exploration Company f/k/a Texas Meridian Resources
Exploration, Inc., bearing Civil Action No. 99-2394 of the United States
District Court for the Western District of Louisiana was filed on February 24,
2000. The Company asserts a claim for damages against Meridian resulting from
Meridian's activities as operator of the Southwest Holmwood property, Calcasieu
Parish, Louisiana. Meridian's activities as operator resulted in a final
judgment of the United States District Court for the Western District of
Louisiana ordering cancellation of the Company's rights to a productive oil and
gas lease and the associated joint exploration agreement, forfeiture to two
producing wells on the lease and substantial damages against Meridian causing
the Company the loss of its investment and profits.

The Meridian Resource & Exploration Company v. PetroQuest Energy, Inc.,
bearing Docket No. 996192A of the 15th Judicial District Court in and for the
Parish of Lafayette, Louisiana was filed on December 17, 1999. Meridian asserts
that the Company is responsible as an investor under its participation agreement
with Meridian for $530,004 of the losses, costs, expense and liability of
Meridian resulting from the final judgment that was rendered in favor of Amoco
and against Meridian in legal proceedings relative to the Southwest Holmwood
Field, Calcasieu Parish, Louisiana in the matter "Amoco Production Company v.
Texas Meridian Resource & Exploration Company," bearing Civil Action No. 96-1639
in the United States District Court for the Western District of Louisiana (Civil
Action No. 98-30724 in the United States Court of Appeals for the Fifth
Circuit). Although the Company accrued $555,000 when the district court decision
was rendered against Meridian in December 1997, the Company denies liability to
Meridian for losses sustained by Meridian as operator as a result of the Amoco
litigation and is vigorously defending the lawsuit. Meridian initially withheld
$737,620 from production revenues due the Company from other properties. On
January 9, 2002 Meridian released to the Company $211,476 of the withheld
revenues. The Company is pursuing recovery of the balance of the withheld
revenues from Meridian as discussed in PetroQuest Energy, Inc. f/k/a Optima
Energy (U.S.) Corp. v. The Meridian Resource & Exploration Company f/k/a Texas
Meridian Resources Exploration, Inc.

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 2002.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

MARKET PRICE OF AND DIVIDENDS ON COMMON STOCK

The Company's common stock trades on The Nasdaq Stock Market under the
symbol "PQUE." On January 19, 2001, the Company voluntarily delisted its common
stock from the Toronto Stock Exchange ("TSE") where it formally traded under the
symbol "PQU." The Company delisted its stock from the TSE because it no longer
had Canadian operations and substantially all of its trading volume was on The
Nasdaq Stock Market. The following table lists high and low sales prices per
share for the periods indicated:

18

As of March 10, 2003, there were approximately 572 common stockholders
of record.

The Company has not paid dividends on the common stock and intends to
retain its cash flow from operations for the future operation and development of
its business. In addition, the Company's credit facility with a group of three
banks restricts the declaration or payment of any dividends or distributions
without prior written consent of certain members of the bank group.

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, 2002
have 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.

(a) The Company's financial statements for 1998-2001 were audited by Arthur
Andersen LLP, who has ceased operations.

19

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

GENERAL

PetroQuest is an independent oil and gas company engaged in the
exploration, development, acquisition and operation of oil and gas properties
onshore and offshore in the Gulf Coast Region. We have been active in this area
since 1986, which gives us extensive geophysical, technical and operational
expertise in this area. Our business strategy is to increase production, cash
flow and reserves through exploration, development and acquisition of properties
located in the Gulf Coast Region.

NEW ACCOUNTING STANDARDS

In June 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations," which requires recording the fair
value of an asset retirement obligation associated with tangible long-lived
assets in the period incurred. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel. We will record the fair value of these obligations on January 1, 2003,
and will record the related additional assets. The estimated fair value of the
obligations at January 1, 2003 is approximately $9,500,000. The net difference
between our previously recorded abandonment liability and the amounts estimated
under SFAS 143, after taxes, is expected to total a gain of approximately
$850,000, which will be recognized as a cumulative effect of a change in
accounting principle.

In December 2002, the FASB issued SFAS No. 148, "Accounting for
Stock-Based Compensation - Transition and Disclosure - an amendment of SFAS No.
123." SFAS No. 148 amends SFAS No. 123 to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. In addition, this statement amends the
disclosure requirements of SFAS No. 123 to require disclosures in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on the reported results.
SFAS No. 148 is effective for the year ended December 31, 2002 and for interim
financial statements commencing in 2003. Our adoption of this pronouncement did
not have an impact on financial condition or results of operations.

CRITICAL ACCOUNTING POLICIES

Full Cost Method of Accounting

We use the full cost method of accounting for our investments in oil
and gas properties. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of exploring for and developing and 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 related to unevaluated leasehold acreage
and delay rentals, seismic data and capitalized interest. These costs are either
transferred to the amortization base with the costs of drilling the related well
or are assessed quarterly for possible impairment or reduction in value.

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

20

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

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

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

Future Abandonment Costs

Future abandonment costs include costs to dismantle and relocate or
dispose of our production platforms, gathering systems, wells and related
structures and restoration costs of land and seabed. We develop estimates of
these costs for each of our properties based upon the type of production
structure, depth of water, reservoir characteristics, depth of the reservoir,
market demand for equipment, currently available procedures and consultations
with construction and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs is difficult
and requires management to make estimates and judgments that are subject to
future revisions based upon numerous factors, including changing technology and
the political and regulatory environment. The accounting for future abandonment
costs changed on January 1, 2003, with the adoption of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." See
New Accounting Standards in the Notes to Consolidated Financial Statements for a
further discussion of this accounting standard.

Reserve Estimates

Our estimates of oil and gas reserves are, by necessity, 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. 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 treatment
due to being highly effective are recorded to Other Comprehensive Income until
the hedged oil or natural gas quantities are produced.

Estimating the fair values of hedging derivatives requires complex
calculations incorporating estimates of future prices, discount rates and price
movements. Instead, we choose to obtain the fair value of our commodity
derivatives from the

21

counter parties to those contracts. Since the counter parties are market makers,
they are able to provide us with a literal market value, or what they would be
willing to settle such contracts for as of the given date.

RESULTS OF OPERATIONS

The following table sets forth certain operating information with
respect to our oil and gas operations for the years ended December 31, 2002,
2001 and 2000:

The above sales include income related to gas hedges of ($733,000) and
$1,247,000 and oil hedges of ($128,000) and $384,000 for the years ended
December 31, 2002 and 2001, respectively. We were not hedged during 2000.

COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
2001

Net income totaled $2,307,000 and $11,645,000 for the years ended
December 31, 2002 and 2001, respectively. The results are attributable to the
following components:

Production

Oil production in 2002 increased 17% over the year ended December 31,
2001. Natural gas production in 2002 decreased 14% over the year ended December
31, 2001. On a Mcfe basis, total production for the year ended December 31, 2002
decreased 3% over the same period in 2001. The decrease in 2002 total production
volumes, as compared to 2001, was due to the consistent decline of our Gulf
Coast production partially offset by the drilling success during 2002.

Prices

Average oil prices per Bbl during 2002 were $25.07 as compared to
$25.49 for the same period in 2001. Average gas prices per Mcf were $3.20 during
2002 as compared to $3.86 for the same period in 2001. Stated on a Mcfe basis,
unit prices received during 2002 were 10% lower than the prices received during
2001.

Revenue

Oil and gas sales during 2002 decreased 12% to $48,141,000 as compared
to 2001 revenues of $54,967,000. The slight decrease in production volumes and
reduced commodity prices resulted in the decrease in revenue.

Expenses

Lease operating expenses for 2002 increased to $9,988,000 from
$7,172,000 during 2001. On a Mcfe basis, lease operating expenses increased from
$0.52 per Mcfe in 2001 to $0.75 in 2002. The increase during 2002 is primarily
due to increased insurance costs and an increase in the repairs and maintenance
at the Ship Shoal 72 Field.

22

General and administrative expenses during 2002 totaled $5,009,000 as
compared to expenses of $4,752,000 during 2001, net of amounts capitalized of
$3,664,000 and $2,651,000, respectively. The increases in general and
administrative expenses are primarily due to an increase in staffing levels and
rent expense related to the generation of prospects, exploration for oil and gas
reserves and operation of properties. We recognized $345,000 and $765,000 of
non-cash compensation expense during 2002 and 2001, respectively.

Depreciation, depletion and amortization ("DD&A") expense for 2002
increased 22% to $28,196,000 as compared to $23,094,000 in 2001. On a Mcfe
basis, which reflects the changes in production, the DD&A rate for 2002 was
$2.11 per Mcfe as compared to $1.68 per Mcfe for 2001. The increase in 2002 as
compared to 2001 is due primarily to costs in excess of previous estimates
during the previous twelve months and unsuccessful exploration drilling results
during 2002.

Interest expense, net of amounts capitalized on unevaluated prospects,
decreased $1,833,000 during 2002 as compared to 2001. The decrease is the result
of an decrease in the average debt levels and interest rates during 2002. We
capitalized $619,000 and $1,001,000 of interest during 2002 and 2001,
respectively.

Income tax expense of $1,288,000 was recognized during 2002 as compared
to $5,411,000 being recorded during 2001. The decrease is due to a decrease in
operating profit during the current year. We provide for income taxes at a
statutory rate of 37% adjusted for permanent differences expected to be
realized, primarily statutory depletion.

COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001 AND
2000

Net income totaled $11,645,000 and $9,924,000 for the years ended
December 31, 2001 and 2000, respectively. The positive results are attributable
to the following components:

Production

Oil production in 2001 increased 393% over the year ended December 31,
2000. Natural gas production in 2001 increased 127% over the year ended December
31, 2000. On a Mcfe basis, production for the year ended December 31, 2001
increased 178% over the same period in 2000. The increase in 2001 production
volumes, as compared to 2000, was due to our successful drilling program, which
had a 77% success rate completing 10 of 13 wells drilled in 2001.

Prices

Average oil prices per Bbl during 2001 were $25.49 as compared to
$29.94 for the same period in 2000. Average gas prices per Mcf were $3.86 during
2001 as compared to $4.38 for the same period in 2000. Stated on a Mcfe basis,
unit prices received during 2001 were 11% lower than the prices received during
2000.

Revenue

Oil and gas sales during 2001 increased 147% to $54,967,000 as compared
to 2000 revenues of $22,267,000. The significant growth in production volumes
partially offset by reduced commodity prices resulted in significant increases
in revenue.

Expenses

Lease operating expenses for 2001 increased to $7,172,000 from
$2,831,000 during 2000. The increase during 2001 is primarily due to the 178%
increase in production on a Mcfe basis. On a Mcfe basis, lease operating
expenses decreased from $0.57 per Mcfe in 2000 to $0.52 in 2001.

General and administrative expenses during 2001 totaled $4,752,000 as
compared to expenses of $3,248,000 during 2000, net of amounts capitalized of
$2,651,000 and $2,084,000, respectively. The increases in general and
administrative expenses are primarily due to an 33% increase in staffing levels
related to the generation of prospects, exploration for oil and gas reserves and
operation of properties. Additionally, we have recognized $765,000 of non-cash
compensation expense during 2001. As a result of extending the life of two
directors' options, we recognized $413,000 of non-cash compensation expense
during the fourth quarter. We also recognized $352,000 of non-cash compensation
expense related to the amortization of unearned deferred compensation.

23

Depreciation, depletion and amortization ("DD&A") expense for 2001
increased 265% to $23,094,000 as compared to $6,386,000 in 2000. The rise in
DD&A is primarily due to increased production from bringing new wells on-line
since the first quarter of 2000. On a Mcfe basis, which reflects the changes in
production, the DD&A rate for 2001 was $1.68 per Mcfe as compared to $1.29 per
Mcfe for 2000. The increase in 2001 as compared to 2000 is due primarily to the
significant capital and future development costs related to our offshore
projects.

Interest expense, net of amounts capitalized on unevaluated prospects,
increased $2,033,000 during 2001 as compared to 2000. The increase is the result
of an increase in debt levels during 2001 resulting from property acquisitions
and a higher capital budget, which has been partially funded by borrowings. We
capitalized $1,001,000 and $439,000 of interest during 2001 and 2000,
respectively.

Income tax expense of $5,411,000 was recognized during 2001 as compared
to an $850,000 benefit being recorded during 2000. The increase is the result of
fully reversing the valuation allowance on our deferred tax asset during 2000.
We provide for income taxes at a statutory rate of 37% adjusted for permanent
differences expected to be realized, primarily statutory depletion.

LIQUIDITY AND CAPITAL RESOURCES

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

Source of Capital: Operations

Net cash flow from operations during the year decreased from
$40,869,000 in 2001 to $29,178,000 in 2002. This decrease resulted primarily
from a decrease in the average realized commodity prices. Working capital
(before considering debt) increased from $(10.4) million at December 31, 2001 to
$(9.2) million at December 31, 2002. This was caused primarily by the reduction
of payables from our fourth quarter 2002 common stock offering.

Source of Capital: Debt

PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the
"Borrower") have a $100 million revolving credit facility with a group of three
banks which permits us to borrow amounts from time to time based on our
available borrowing base as determined in the credit facility. The credit
facility is secured by a mortgage on substantially all of the Borrower's oil and
gas properties, a pledge of the membership interest of the Borrower and
PetroQuest's corporate guarantee of the indebtedness of the Borrower. The
borrowing base under this credit facility is based upon the valuation on March
31 and September 30 of the Borrower's mortgaged properties, projected oil and
gas prices, and any other factors deemed relevant by the lenders. We or the
lenders may also request additional borrowing base redeterminations. On
September 30, 2002, the borrowing base under the credit facility was adjusted to
$25 million and is subject to quarterly reductions of $5 million commencing on
January 31, 2003.

Outstanding balances on the revolving credit facility bear interest at
either the prime rate (plus 0.375% per year whenever the borrowing base usage
under the credit facility is greater than or equal to 90%) or the Eurodollar
rate plus a margin (based on a sliding scale of 1.625% to 2.375% depending on
borrowing base usage). The credit facility also allows us to use up to $10
million of the borrowing base for letters of credit for fees of 2% per annum. At
December 31, 2002, we had $9 million of borrowings and a $2.6 million letter of
credit issued pursuant to the credit facility.

The credit facility contains covenants and restrictions common to
borrowings of this type, including maintenance of certain financial ratios. We
were in compliance with all of our covenants at December 31, 2002. The credit
facility matures on June 30, 2004.

Source of Capital: Issuance of Equity Securities

We have an effective universal shelf registration statement relating to
the potential public offer and sale by PetroQuest of any combination of debt
securities, common stock, preferred stock, depositary shares, and warrants from
time to time or when financing needs arise. The registration statement does not
provide assurance that we will or could sell any such securities.

24

During October and November 2002, we completed the offering of
5,000,000 shares of our common stock. The shares were sold to the public for
$4.25 per share. After underwriting discounts, we realized proceeds of
approximately $20.4 million.

During February and March 2002, we completed the offering of 5,193,600
shares of our common stock. The shares were sold to the public for $4.40 per
share. After underwriting discounts, we realized proceeds of approximately $21.9
million.

Source of Capital: Sales of Properties

On March 1, 2002, we closed the sale of our interest in Valentine Field
for $18.6 million. The transaction had an effective date of January 1, 2002. At
December 31, 2001, our independent reservoir engineering firm attributed 7.3
Bcfe of proved reserves net to our interest in this field. Consistent with the
full cost method of accounting, we did not recognize any gain or loss as a
result of this sale. The proceeds were treated as a reduction of the full cost
pool.

Use of Capital: Exploration and Development

We have an exploration and development program budget for the year
2003 which will require significant capital. Our capital budget for direct
capital for new projects in 2003 is approximately $25 million. Our management
believes the cash flows from operations and available borrowing capacity under
our credit facility, after the March 31 and September 30 regularly scheduled
redeterminations, will be sufficient to fund planned 2003 exploration and
development activities. Currently, the borrowing base is scheduled to be reduced
to $5 million as of December 31, 2003. Management believes that the regularly
scheduled redeterminations will generate an increased borrowing capacity above
such amount at year-end. In the future, our exploration and development
activities could require additional financings, which may include sales of
additional equity or debt securities, additional bank borrowings, sales of
properties, or joint venture arrangements with industry partners. We cannot
assure you that such additional financings will be available on acceptable
terms, if at all. If we are unable to obtain additional financing, we could be
forced to delay or even abandon some of our exploration and development
opportunities or be forced to sell some of our assets on an untimely or
unfavorable basis.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

The Company experiences market risks primarily in two areas: interest
rates and commodity prices. The Company believes that its business operations
are not exposed to significant market risks relating to foreign currency
exchange risk.

The Company's revenues are derived from the sale of its crude oil and
natural gas production. Based on projected annual sales volumes for 2003, a 10%
decline in the estimated average 2003 prices the Company receives for its crude
oil and natural gas production would have an approximate $5.7 million impact on
the Company's revenues.

In a typical hedge transaction, the Company 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, the
Company is required to pay the counterparts this difference multiplied by the
quantity hedged. The Company is required to pay the difference between the
floating price and the fixed price (when the floating price exceeds the fixed
price) regardless of whether the Company has 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 the Company to
make payments under the hedge agreements even though such payments are not
offset by sales of production. Hedging will also prevent the Company from
receiving the full advantage of increases in oil or gas prices above the fixed
amount specified in the hedge. As of December 31, 2002, the Company had open
fixed price swap contracts with third parties, whereby a fixed price has been
established for a certain period. These agreements in effect for 2003 are for
oil volume of 1,000 barrels per day at a weighted average price of $25.75, and
gas volume of 7,000Mmbtu per day at a weighted average price of $4.02. At
December 31, 2002, the Company recognized a liability of $1,841,000 related to
these derivative instruments, which have been designated as cash flow hedges.

We currently have two interest rate swaps covering $5 million of our
floating rate debt. The swaps which expire in November 2003 and 2004 have fixed
interest rates of 4.56% and 4.25%-5.665%, respectively. The swaps are stated at
their fair value and are marked-to-market through other income in our income
statement. As of December 31, 2002, the fair value of the open interest rate
swaps was a liability of $477,000.

25

The Company also evaluated the potential effect that reasonably
possible near term changes may have on the Company's credit facility. Debt
outstanding under the facility is subject to a floating interest rate and
represents 100% of the Company's total debt as of December 31, 2002. Based upon
an analysis utilizing the actual interest rate in effect and balances
outstanding as of December 31, 2002 and assuming a 10% increase in interest
rates and no changes in the amount of debt outstanding, the potential effect on
interest expense for 2003 is approximately $34,000.

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

Previously reported on Form 8-K, dated July 1, 2002.

PART III

ITEMS 10, 11, 12 & 13

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 Item 13. Certain Relationships and
Related Transactions, see the definitive Proxy Statement of PetroQuest Energy,
Inc. relating to the Annual Meeting of Stockholders to be held May 7, 2003,
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.

ITEM 14. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Within 90 days prior to the filing date of this Form 10-K, our
principal executive officer ("CEO") and principal financial officer ("CFO")
carried out an evaluation of the effectiveness of PetroQuest's disclosure
controls and procedures. Based on those evaluations, the CEO and CFO believe

i. that our disclosure controls and procedures are designed to
ensure that information required to be disclosed by PetroQuest
in the reports it files under the Securities Exchange Act of
1934 is recorded, processed, summarized and reported within
the time periods specified in the SEC's rules and forms, and
that such information is accumulated and communicated to the
PetroQuest's management, including the CEO and CFO, as
appropriate to allow timely decisions regarding required
disclosure; and

ii. that our disclosure controls and procedures are effective.

CHANGES IN INTERNAL CONTROLS

There have been no significant changes in our internal controls or in
other factors that could significantly affect our internal controls subsequent
to the evaluation referred to above, nor have there been any corrective actions
with regard to significant deficiencies or material weaknesses.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

(a) 1. FINANCIAL STATEMENTS

The following financial statements of the Company and the Report of the
Company's Independent Public Accountants thereon are included on pages F-1
through F-19 of this Form 10-K.

26

Report of Independent Auditors

Report of Independent Public Accountants

Consolidated Balance Sheets as of December 31, 2002 and 2001

Consolidated Statements of Operations for the three years
ended December 31, 2002

Consolidated Statements of Stockholder's Equity for the three
years ended December 31, 2002

Consolidated Statements of Cash Flows for the three years
ended December 31, 2002

Notes to Consolidated Financial Statements

2. FINANCIAL STATEMENT SCHEDULES:

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

3. EXHIBITS:

2.1 Plan and Agreement of Merger by and among Optima Petroleum
Corporation, Optima Energy (U.S.) Corporation, its
wholly-owned subsidiary, and Goodson Exploration Company, NAB
Financial L.L.C., Dexco Energy, Inc., American Explorer,
L.L.C. (incorporated herein by reference to Appendix G of the
Proxy Statement on Schedule 14A filed July 22, 1998).

3.1 Certificate of Incorporation of 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 Form of Certificate of Contingent Stock Issue Right
(incorporated herein by reference to Exhibit 4.3 to Form 8-K
dated September 16, 1998).

4.2 Form of Warrant to Purchase Shares of Common Stock of
PetroQuest Energy, Inc. (incorporated herein by reference to
Exhibit 4.1 to Form 8-K dated August 9, 1999).

4.3 Form of Placement Agent Warrant to Purchase Shares of Common
Stock of PetroQuest Energy, Inc. (incorporated herein by
reference to Exhibit 4.2 to Form 8-K dated August 9, 1999).

4.4 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).

4.5 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).

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 11,
2001, by and among PetroQuest Energy, L.L.C., a Louisiana
limited liability company, PetroQuest Energy, Inc., a Delaware
corporation, and Hibernia National Bank, and the Financial
Institutions named therein as Lenders, and Hibernia National
Bank as Administrative Agent (incorporated herein by reference
to Exhibit 10.3 to Form 10-Q filed May 15, 2001).

10.3 Revolving Note dated May 11, 2001 in the principal amount of
$50,000,000.00 payable to Hibernia National Bank (incorporated
herein by reference to Exhibit 10.4 to Form 10-Q filed May 15,
2001).

10.4 Revolving Note dated May 11, 2001 in the principal amount of
$25,000,000.00 payable to Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.5 to Form 10-Q
filed May 15, 2001).

27

10.5 Revolving Note dated May 11, 2001 in the principal amount of
$25,000,000.00 payable to Royal Bank of Canada (incorporated
herein by reference to Exhibit 10.6 to Form 10-Q filed May 15,
2001).

10.6 Commercial Guaranty made as of May 11, 2001, by PetroQuest
Energy, Inc., a Delaware corporation, in favor of Hibernia
National Bank (incorporated herein by reference to Exhibit
10.7 to Form 10-Q filed May 15, 2001).

10.7 Subordination Agreement effective as of May 11, 2001, by and
among Hibernia National Bank, EnCap Energy Capital Fund III,
L.P., PetroQuest Energy, L.L.C., a Louisiana limited liability
company, and PetroQuest Energy, Inc., a Delaware corporation
(incorporated herein by reference to Exhibit 10.8 to Form 10-Q
filed May 15, 2001).

10.8 First Amendment to Amended and Restated Credit Agreement dated
and effective as of July 20, 2001, among PetroQuest Energy,
L.L.C., PetroQuest Energy, Inc., Royal Bank of Canada, Union
Bank of California, N.A., and Hibernia National Bank, a
national banking association, individually as a lender and as
Administrative Agent (incorporated herein by reference to
Exhibit 10.1 to Form 8-K filed February 15, 2002).

10.9 Second Amendment to Amended and Restated Credit Agreement
dated as of December 24, 2001, among PetroQuest Energy,
L.L.C., PetroQuest Energy, Inc., Royal Bank of Canada, Union
Bank of California, N.A., and Hibernia National Bank, a
national banking association, individually as a lender and as
Administrative Agent (incorporated herein by reference to
Exhibit 10.2 to Form 8-K filed February 15, 2002).

10.10 Third Amendment to Amended and Restated Credit Agreement dated
as of March 1, 2002, among PetroQuest Energy, L.L.C.,
PetroQuest Energy, Inc., Royal Bank of Canada, Union Bank of
California, N.A., and Hibernia National Bank, a national
banking association, individually as a lender and as
Administrative Agent (incorporated herein by reference to
Exhibit 10.10 to Form 10-K filed March 13, 2002).

10.11 Fourth Amendment to Amended and Restated Credit Agreement
dated as of November 13, 2002, but effective as of September
20, 2002, among PetroQuest Energy, L.L.C., PetroQuest Energy,
Inc., Royal Bank of Canada, Union Bank of California, N.A.,
and Hibernia National Bank, a national banking association,
individually as a lender and as Administrative Agent
(incorporated herein by reference to Exhibit 10.1 to Form 10-Q
filed November 14, 2002).

10.12 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).

10.13 Employment Agreement dated September 1, 1998, between
PetroQuest Energy, Inc. and Alfred J. Thomas, II (incorporated
herein by reference to Exhibit 10.3 to Form 8-K dated
September 16, 1998).

10.14 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).

10.15 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).

10.16 First Amendment to Employment Agreement dated September 1,
1998 between PetroQuest Energy, Inc. and Alfred J. Thomas, II
dated July 30, 1999 (incorporated herein by reference to
Exhibit 10.2 to Form 8-K dated August 9, 1999).

10.17 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).

10.18 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).

10.19 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).

10.20 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).

*10.21 Employment Agreement dated April 20, 2001 between PetroQuest
Energy, Inc. and Dalton F. Smith III.

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

28

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

21.1 Subsidiaries of the Company (incorporated herein by reference
to Exhibit 21.1 to Form 10-K filed March 30, 2001).

*23.1 Consent of Independent Auditors.

23.2 Consent of Arthur Andersen LLP (omitted pursuant to Rule 437a
under the Securities Act of 1933, as amended).

*23.3 Consent of Ryder Scott Company, L.P.

*99.1 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002.

*99.2 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002.

- ----------
* Filed herewith.

29

REPORTS ON FORM 8-K

(i) The Company filed a report on Form 8-K on October 30, 2002, relating to
an underwritten public offering.

(ii) The Company filed a report on Form 8-K on November 4, 2002, relating to
the closing of an underwritten public offering.

(iii) The Company filed a report on Form 8-K on November 6, 2002, relating to
third quarter 2002 results.

(iv) The Company filed a report on Form 8-K on November 21, 2002, relating
to gas hedges for 2003 and operations updates.

30

GLOSSARY OF 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.

Development 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.

31

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. 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.

32

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 13, 2003.

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 13, 2003.

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

By: /s/ Alfred J. Thomas, II President, Chief Operating Officer and Director
-----------------------------------------------
ALFRED J. THOMAS, II

By: /s/ Ralph J. Daigle Executive Vice President and Director
-----------------------------------------------
RALPH J. DAIGLE

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

By: /s/ Jay B. Langner Director
-----------------------------------------------
JAY B. LANGNER

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

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

33

CERTIFICATIONS

I, Charles T. Goodson, certify that:

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

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves
management or other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 13, 2003 /s/ Charles T. Goodson
--------------------------------------------
Charles T. Goodson
Chairman and Chief Executive Officer

34

I, Michael O. Aldridge, certify that:

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

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

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

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the filing date of
this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

d) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

e) any fraud, whether or not material, that involves
management or other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 13, 2003 /s/ Michael O. Aldridge
--------------------------------------------
Michael O. Aldridge
Senior Vice President, Chief Financial Officer
and Treasurer

35

INDEX TO FINANCIAL STATEMENTS

Report of Independent Auditors ................................................. F-2

Report of Independent Public Accountants ....................................... F-3

Consolidated Balance Sheets of PetroQuest Energy, Inc. as of
December 31, 2002 and 2001 .................................................. F-4

Consolidated Statements of Operations of PetroQuest Energy, Inc.
for the years ended December 31, 2002, 2001 and 2000 ........................ F-5

Consolidated Statements of Stockholders' Equity of PetroQuest Energy, Inc.
for the years ended December 31, 2002, 2001 and 2000 ......................... F-6

Consolidated Statements of Cash Flows of PetroQuest Energy, Inc.
for the years ended December 31, 2002, 2001 and 2000 ......................... F-7

Notes to Consolidated Financial Statements ..................................... F-8

F-1

REPORT OF INDEPENDENT AUDITORS

To the Stockholders of
PetroQuest Energy, Inc.:

We have audited the accompanying consolidated balance sheet of PetroQuest
Energy, Inc. (a Delaware corporation) as of December 31, 2002, and the related
consolidated statements of operations, stockholders' equity and cash flows for
the year then ended. 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 audit. The financial statements of PetroQuest
Energy, Inc. for the years ended December 31, 2001 and 2000, were audited by
other auditors who have ceased operations and whose report dated March 7, 2002,
expressed an unqualified opinion on those statements and included an explanatory
paragraph that disclosed the change in the Company's method of accounting for
derivative instruments and hedging activities discussed in Note 2 to these
financial statements.

We conducted our audit in accordance with auditing standards generally accepted
in the 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 audit provides a reasonable basis for our
opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of PetroQuest
Energy, Inc. as of December 31, 2002, and the consolidated results of its
operations and its cash flow for the year then ended in conformity with
accounting principles generally accepted in the United States.

ERNST&YOUNG LLP

New Orleans, Louisiana
February 11, 2003

F-2

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of
PetroQuest Energy, Inc.:

We have audited the accompanying consolidated balance sheets of PetroQuest
Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. 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 auditing standards generally accepted
in the 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 financial position of PetroQuest Energy, Inc. and
subsidiaries as of December 31, 2001 and 2000, and the consolidated results of
their operations and their cash flow for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.

As discussed in Note 2 to the consolidated financial statements effective
January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivatives
Instruments and Hedging Activities."

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
March 7, 2002

NOTE: The report of Arthur Andersen LLP presented above is a copy of a
previously issued Arthur Andersen LLP report and said report has not been
reissued by Arthur Andersen LLP nor has Arthur Andersen LLP provided a consent
to the inclusion of its report in this Form 10-K.

F-3

PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)

See accompanying Notes to Consolidated Financial Statements.

F-4

PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)

See accompanying Notes to Consolidated Financial Statements.

F-5

PETROQUEST ENERGY, INC.
Consolidated Statements of Stockholders' Equity
(Amounts in Thousands, Except Share Data)

See accompanying Notes to Consolidated Financial Statements.

F-6

PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(Amounts in Thousands)

See accompanying Notes to Consolidated Financial Statements.

F-7

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 - ORGANIZATION

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 Region. PetroQuest and its predecessors
have been active in this area since 1986.

On December 31, 2000, the Company underwent a corporate reorganization.
The Company's subsidiary, PetroQuest Energy, Inc., a Louisiana corporation, was
merged into PetroQuest Energy One, L.L.C., a Louisiana limited liability
company. In addition, PetroQuest Energy One, L.L.C. changed its name to
PetroQuest Energy, L.L.C., a single-member Louisiana limited liability company,
and PetroQuest Energy, Inc., a Delaware corporation, continues to be its sole
member.

A new single-member Louisiana limited liability company called
PetroQuest Oil & Gas, L.L.C. was created on December 31, 2000. PetroQuest
Energy, Inc. (a Delaware corporation) is the sole member of PetroQuest Oil &
Gas, L.L.C.

NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of the
Company and its subsidiaries, PetroQuest Energy, L.L.C. and PetroQuest Oil &
Gas, L.L.C. 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.

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 computation base. The costs of
investments in unproved properties are excluded from this calculation until the
project is evaluated and proved reserves established or impaired. Oil and gas
reserves are estimated annually by independent petroleum engineers.
Additionally, 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). Transactions involving sales of reserves in place,
unless significant, are recorded as adjustments to accumulated depreciation,
depletion and amortization.

F-8

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 as 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.

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 loan costs which are amortized over the life of the related
loan.

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.

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, 2002, 2001 and 2000
were not significant.

Certain Concentrations

During 2002, 66% of the Company's oil and gas production was sold to
three customers. During 2001, 66% of the Company's oil and gas production was
sold to four customers. During 2000, 84% of the Company's oil and gas production
was sold to three customers. Based on the current demand for oil and gas, 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.

Fair Value of Financial Instruments

The fair value of accounts receivable and accounts payable approximate
book value at December 31, 2002 and 2001 due to the short-term nature of these
accounts. The fair value of the note payable and non-recourse financing
approximates book value due to the variable rate of interest charged.

Derivative Instruments

On January 1, 2001, the Company adopted Statement of Financial
Accounting Standards No. 133, as amended (SFAS 133) pertaining to the accounting
for derivative instruments and hedging activities. SFAS 133 requires an entity
to recognize all of its derivatives as either assets or liabilities on its
balance sheet and measure those instruments at fair value. If the conditions
specified in SFAS 133 are met, those instruments may be designated as hedges.
Changes in the value of hedge instruments would not impact earnings, except to
the extent that the instrument is not perfectly effective as a hedge.

F-9

The Company recognized $861,000 and $1,630,000 in oil and gas revenues
during the years ended December 31, 2002 and 2001, respectively as a result of
the settlement of costless collars. As of December 31, 2002, the Company had
open fixed price swap contracts with third parties, whereby a fixed price has
been established for a certain period. These agreements in effect for 2003 are
for oil volume of 1,000 barrels per day at a weighted average price of $25.75,
and gas volume of 7,000Mmbtu per day at a weighted average price of $4.02. At
December 31, 2002, the Company recognized a liability of $1,841,000 related to
these derivative instruments, which have been designated as cash flow hedges.

The Company currently has two interest rate swaps covering $5 million
of our floating rate debt. The swaps which expire in November 2003 and 2004 have
fixed interest rates of 4.56% and 4.25%-5.665%, respectively. The swaps are
stated at their fair value and are marked-to-market through other income in the
Company's income statement. As of December 31, 2002, the fair value of the open
interest rate swaps was a liability of $477,000.

New Accounting Standards

In June 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations," which requires recording the fair
value of an asset retirement obligation associated with tangible long-lived
assets in the period incurred. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel. The Company will record the fair value of these obligations on January
1, 2003, and will record the related additional assets. The estimated fair value
of the obligations at January 1, 2003 is approximately $9,500,000. The net
difference between the Company's previously recorded abandonment liability and
the amounts estimated under SFAS 143, after taxes, is expected to total a gain
of approximately $850,000, which will be recognized as a cumulative effect of a
change in accounting principle.

Earnings per Common Share Amounts

Basic earnings or loss per common share was computed by dividing net
income or loss by the weighted average number of shares of common stock
outstanding during the year. Diluted earnings or loss per common share is
determined on a weighted average basis using common shares issued and
outstanding adjusted for the effect of stock options considered common stock
equivalents computed using the treasury stock method.

Options to purchase 273,667 shares of common stock at $5.56 to $7.65
per share were outstanding during 2002 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 180,000
shares of common stock at $5.89 to $7.65 per share were outstanding during 2001
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 682,500 shares of common stock at $3.13 to
$3.44 per share were outstanding during 2000 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. The contingent
stock rights assigned in connection with a Company merger (see Note 3) were also
excluded from the calculation of diluted earnings per share prior to their
issuance.

Stock-based Compensation

The Company accounts for its stock-based compensation plans under the
principles prescribed by the Accounting Principles Board's Opinion No. 25 ("APB
No. 25"), "Accounting for Stock Issued to Employees." See Note 10 for the
Company's disclosure of stock-based compensation under SFAS No. 123.

F-10

NOTE 3 - EQUITY

Other Comprehensive Income

The following table presents a recap of the Company's comprehensive
income for years ended December 31, 2002 and 2001 (in thousands):

The Company accounts for derivatives in accordance with Statement of Financial
Accounting Standards No. 133, as amended (SFAS 133). When the conditions
specified in SFAS 133 are met, the Company may designate these derivatives as
hedges. As of December 31, 2002, the Company had fixed price swap contracts with
third parties, whereby a fixed price has been established for a certain period.
At December 31, 2002, the effect of derivative financial instruments is net of
deferred income tax benefit of $644,000.

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 the Original Owners
granted to the officer an option to acquire, at a fixed price, certain of the
original shares the Original Owners were issued in the Merger. 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 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 until fully amortized. We recognized $345,000 and $765,000,
respectively of non-cash compensation expense during the years ended December
31, 2002 and 2001.

Common Stock Issue Rights

Pursuant to a Company merger, the Company issued to the original owners
of American Explorer L.L.C. and their respective affiliates, certain of whom
currently serve as officers and directors of the Company, 7,335,001 shares of
the Company's common stock, par value $.001 per share (the "Common Stock"), and
1,667,001 Contingent Stock Issue Rights (the "CSIRs"). The CSIRs entitled the
holders to receive an additional 1,667,001 shares of Common Stock at such time
within three years of the anniversary date of the issuance of the CSIRs if the
trading price for the Common Stock closed at $5.00 or higher for 20 consecutive
trading days. On May 3, 2001 the Common Stock closed higher than $5.00 for the
twentieth consecutive trading day, and 1,667,001 shares of Common Stock were
issued under the terms of the CSIRs.

NOTE 4 - DEBT

PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the
"Borrower") have a $100 million revolving credit facility with a group of three
banks which permits us to borrow amounts from time to time based on our
available borrowing base as determined in the credit facility. The credit
facility is secured by a mortgage on substantially all of the Borrower's oil and
gas properties, a pledge of the membership interest of the Borrower and
PetroQuest's corporate guarantee of the

F-11

indebtedness of the Borrower. The borrowing base under this credit facility is
based upon the valuation on March 31 and September 30 of the Borrower's
mortgaged properties, projected oil and gas prices, and any other factors deemed
relevant by the lenders. We or the lenders may also request additional borrowing
base redeterminations. On September 30, 2002, the borrowing base under the
credit facility was adjusted to $25 million and is subject to quarterly
reductions of $5 million commencing on January 31, 2003. As of December 31,
2002, $9 million is outstanding under the credit facility and $2.4 million is
classified as long term reflecting the remaining borrowing base at December 31,
2003.

Outstanding balances on the revolving credit facility bear interest at
either the prime rate (plus 0.375% per year whenever the borrowing base usage
under the credit facility is greater than or equal to 90%) or the Eurodollar
rate plus a margin (based on a sliding scale of 1.625% to 2.375% depending on
borrowing base usage). The credit facility also allows us to use up to $10
million of the borrowing base for letters of credit for fees of 2% per annum. At
December 31, 2002, we had $9 million of borrowings and a $2.6 million letter of
credit issued pursuant to the credit facility.

The credit facility contains covenants and restrictions common to
borrowings of this type, including maintenance of certain financial ratios. We
were in compliance with all of our covenants at December 31, 2002. The credit
facility matures on June 30, 2004.

NOTE 5 - RELATED PARTY TRANSACTIONS

Certain of the Company's executive officers and directors or their
affiliates are working interest owners or overriding royalty interest owners in
particular properties operated by the Company. 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.

NOTE 6 - COMMON STOCK AND WARRANTS

During October and November 2002, the Company completed the offering of
5,000,000 shares of its common stock. The shares were sold to the public for
$4.25 per share. After underwriting discounts, the Company realized proceeds of
approximately $20.4 million.

During February and March 2002, the Company completed the offering of
5,193,600 shares of its common stock. The shares were sold to the public for
$4.40 per share. After underwriting discounts, the Company realized proceeds of
approximately $21.9 million.

On July 20, 2000, the Company completed a private placement of 4.89
million shares of common stock to accredited investors at a purchase price of
$2.50 per share for a total consideration of $12,225,000 before fees and
expenses. After fees and expenses, including $644,168 in commissions, proceeds
to the Company were $11,294,000. The Company subsequently registered the resale
of the common stock with the Securities and Exchange Commission on Form S-3.

In August 1999, the Company received the funding of a private placement
of 5 million units at a purchase price of $1.00 per unit for a total
consideration of $5,000,000 before fees and expenses. Each unit sold in the
private placement consisted of one share of the Company's common stock and one
warrant exercisable to purchase one-half a share of the Company's common stock.
Each warrant is exercisable at any time through the fourth year after issuance
to purchase one-half of a share of the Company's common stock at a per share
purchase price of $1.25. At December 31, 2002, there were 1,647,500 warrants
outstanding.

F-12

NOTE 7 - INVESTMENT IN OIL AND GAS PROPERTIES

The following table discloses 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)

Other costs for the year ended December 31, 2002 include $3,664,000 and
$619,000 of capitalized general and administrative costs and interest costs
respectively. Other costs for the year ended December 31, 2001 include
$2,651,000 and $1,001,000 of capitalized general and administrative costs and
interest costs respectively. Other costs for the year ended December 31, 2000
include $2,084,000 and $439,000 of capitalized general and administrative costs
and interest costs respectively.

At December 31, 2002 and 2001, unevaluated oil and gas properties with
capitalized costs of $15,653,000 and $14,682,000 respectively, were not subject
to depletion. Of the $15,653,000 of unevaluated oil and gas property costs at
December 31, 2002, not subject to depletion, $6,730,000 was incurred in 2002,
$3,932,000 was incurred in 2001 and $4,991,000 was incurred in prior years. Of
the $14,682,000 of unevaluated oil and gas property costs at December 31, 2001,
not subject to depletion, $6,485,000 was incurred in 2001 and $8,197,000 was
incurred in prior years. Management expects that these properties will be
evaluated over the next one to three years.

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):

For tax reporting purposes, the Company had operating loss
carryforwards of $37,376,000 and $32,986,000 at December 31, 2002 and 2001
respectively. If not utilized, such carryforwards would begin expiring in 2009
and would

F-13

completely expire by the year 2022. The Company had available for tax reporting
purposes $3,688,000 in statutory depletion deductions that may be carried
forward indefinitely.

Income tax expense (benefit) for each of the years ended December 31,
2002, 2001 and 2000 (amounts in thousands) was different than the amount
computed using the Federal statutory rate (35%) for the following reasons:

NOTE 9 - COMMITMENTS AND CONTINGENCIES

PetroQuest Energy, Inc. f/k/a Optima Energy (U.S.) Corp. v. The
Meridian Resource & Exploration Company f/k/a Texas Meridian Resources
Exploration, Inc., bearing Civil Action No. 99-2394 of the United States
District Court for the Western District of Louisiana was filed on February 24,
2000. The Company asserts a claim for damages against Meridian resulting from
Meridian's activities as operator of the Southwest Holmwood property, Calcasieu
Parish, Louisiana. Meridian's activities as operator resulted in a final
judgment of the United States District Court for the Western District of
Louisiana ordering cancellation of the Company's rights to a productive oil and
gas lease and the associated joint exploration agreement , forfeiture to two
producing wells on the lease and substantial damages against Meridian causing
the Company the loss of its investment and profits. The Company is unable to
predict with certainty the outcome of the lawsuit at this time.

The Meridian Resource & Exploration Company v. PetroQuest Energy, Inc.,
bearing Docket No. 996192A of the 15th Judicial District Court in and for the
Parish of Lafayette, Louisiana was filed on December 17, 1999. Meridian asserts
that the Company is responsible as an investor under its participation agreement
with Meridian for $530,004 of the losses, costs, expense and liability of
Meridian resulting from the final judgment that was rendered in favor of Amoco
and against Meridian in legal proceedings relative to the Southwest Holmwood
Field, Calcasieu Parish, Louisiana in the matter "Amoco Production Company v.
Texas Meridian Resource & Exploration Company," bearing Civil Action No. 96-1639
in the United States District Court for the Western District of Louisiana (Civil
Action No. 98-30724 in the United States Court of Appeals for the Fifth
Circuit). Although the Company accrued $555,000 when the district court decision
was rendered against Meridian in December 1997, the Company denies liability to
Meridian for losses sustained by Meridian as operator as a result of the Amoco
litigation and is vigorously defending the lawsuit. Meridian initially withheld
$737,620 from production revenues due the Company from other properties. On
January 9, 2002 Meridian released to the Company $211,476 of the withheld
revenues. The Company is pursuing recovery of the balance of the withheld
revenues from Meridian as discussed in PetroQuest Energy, Inc. f/k/a Optima
Energy (U.S.) Corp. v. The Meridian Resource & Exploration Company f/k/a Texas
Meridian Resources Exploration, Inc. The Company is unable to predict with
certainty the outcome of the lawsuit at this time.

The Company is a party to other 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.

Abandonment

The Company has made, and will continue to make, expenditures for the
protection of the environment. Present and future environmental laws and
regulations applicable to the Company's operation could require substantial
capital expenditures or could adversely affect its operations in other ways that
cannot be predicted at this time. As of December 31, 2002 and 2001,

F-14

total estimated site restoration, dismantlement and abandonment costs were
approximately $13,684,000 and $14,056,000 respectively, net of expected salvage
value.

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, 2002 under these
operating leases are as follows (in thousands):

2003 ................................................. $ 615
2004 ................................................. 635
2005 ................................................. 647
2006 ................................................. 572
2007 ................................................. 546
Thereafter ........................................... 1,258
------------
4,273

Total rent expense under operating leases was approximately $577,000,
$411,000 and $345,000 in 2002, 2001 and 2000, respectively.

NOTE 10 - EMPLOYEE BENEFIT PLANS

The Company currently has one stock option plan. The 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, 2002, 2001
and 2000 and changes during the years ended on those dates is presented below:

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) divided yield of 0% (b) expected volatility
ranges of 74.50%-74.90%, 65.14% - 67.87% and 56.99% - 59.88% in 2002, 2001 and
2000, respectively (c) risk-free interest rate ranges of 4.17% - 4.54%, 4.03% -
5.10% and 5.39% - 6.96% in 2002, 2001 and 2000, respectively, and (d) expected
life of 5 years for all 2002 and 2001 grants and 10 years for all 2000 grants.

F-15

The following table summarizes information regarding stock options
outstanding at December 31, 2002:

If the compensation cost for the Company's 2002, 2001 and 2000 grants
for stock-based compensation plans had been determined consistent with the
expense recognition provisions of SFAS No. 123, the Company's 2002, 2001 and
2000 net income and basic and diluted earnings per common share would have
approximated the pro forma amounts below (in thousands, except per share
amounts):

NOTE 11 - OIL AND GAS RESERVE INFORMATION - UNAUDITED

The Company's net proved oil and gas reserves at December 31, 2002 have
been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions at the respective dates.

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.

F-16

The following table (amounts in thousands) 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:

F-17

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.

The weighted average prices of oil and gas used with the above tables
at December 31, 2002, 2001 and 2000 were $30.44, $18.49 and $25.29 respectively,
per barrel and $4.79, $2.69 and $10.35, respectively, per Mcf.

F-18

NOTE 13 - SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED

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

(1) Included in net income for the quarter ended December 31, 2001 is a tax
benefit of $759,000 primarily attributable to a revision in the
Company's estimated effective income tax rate.

(2) 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.

F-19

INDEX TO EXHIBITS

10.9 Second Amendment to Amended and Restated Credit Agreement
dated as of December 24, 2001, among PetroQuest Energy,
L.L.C., PetroQuest Energy, Inc., Royal Bank of Canada, Union
Bank of California, N.A., and Hibernia National Bank, a
national banking association, individually as a lender and as
Administrative Agent (incorporated herein by reference to
Exhibit 10.2 to Form 8-K filed February 15, 2002).

10.10 Third Amendment to Amended and Restated Credit Agreement dated
as of March 1, 2002, among PetroQuest Energy, L.L.C.,
PetroQuest Energy, Inc., Royal Bank of Canada, Union Bank of
California, N.A., and Hibernia National Bank, a national
banking association, individually as a lender and as
Administrative Agent (incorporated herein by reference to
Exhibit 10.10 to Form 10-K filed March 13, 2002).

10.11 Fourth Amendment to Amended and Restated Credit Agreement
dated as of November 13, 2002, but effective as of September
20, 2002, among PetroQuest Energy, L.L.C., PetroQuest Energy,
Inc., Royal Bank of Canada, Union Bank of California, N.A.,
and Hibernia National Bank, a national banking association,
individually as a lender and as Administrative Agent
(incorporated herein by reference to Exhibit 10.1 to Form 10-Q
filed November 14, 2002).

10.12 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).

10.13 Employment Agreement dated September 1, 1998, between
PetroQuest Energy, Inc. and Alfred J. Thomas, II (incorporated
herein by reference to Exhibit 10.3 to Form 8-K dated
September 16, 1998).

10.14 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).

10.15 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).

10.16 First Amendment to Employment Agreement dated September 1,
1998 between PetroQuest Energy, Inc. and Alfred J. Thomas, II
dated July 30, 1999 (incorporated herein by reference to
Exhibit 10.2 to Form 8-K dated August 9, 1999).

10.17 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).

10.18 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).

10.19 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).

10.20 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).

*10.21 Employment Agreement dated April 20, 2001 between PetroQuest
Energy, Inc. and Dalton F. Smith III.

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

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

21.1 Subsidiaries of the Company (incorporated herein by reference
to Exhibit 21.1 to Form 10-K filed March 30, 2001).

*23.1 Consent of Independent Auditors.

23.2 Consent of Arthur Andersen LLP (omitted pursuant to Rule 437a
under the Securities Act of 1933, as amended).

*23.3 Consent of Ryder Scott Company, L.P.

*99.1 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002.

*99.2 Certification Pursuant To 18 U.S.C. Section 1350, As Adopted
Pursuant To Section 906 Of The Sarbanes-Oxley Act of 2002

- ----------
* Filed herewith.