PETROQUEST ENERGY INC - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

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FORM 10-Q

(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934

For the quarterly period ended: June 30, 2003

[ ] 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

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

DELAWARE 72-1440714
(State of Incorporation) (I.R.S. Employer Identification No.)

400 E. KALISTE SALOOM RD., SUITE 6000
LAFAYETTE, LOUISIANA 70508
(Address of principal executive offices) (Zip code)

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

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

Yes X No
------- -------

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

Yes X No
------- -------

As of August 8, 2003, there were 44,195,394 shares of the registrant's
common stock, par value $.001 per share, outstanding.

PETROQUEST ENERGY, INC.

Table of Contents

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

See accompanying Notes to Consolidated Financial Statements.

1

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

See accompanying Notes to Consolidated Financial Statements.

2

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

See accompanying Notes to Consolidated Financial Statements.

3

PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 BASIS OF PRESENTATION

The consolidated financial information for the three- and six-month
periods ended June 30, 2003 and 2002, respectively, have been prepared by the
Company and was not audited by its independent public accountants. In the
opinion of management, all normal and recurring adjustments have been made to
present fairly the financial position, results of operations, and cash flows of
the Company at June 30, 2003 and for all reported periods. Results of operations
for the interim periods presented are not necessarily indicative of the
operating results for the full year or any future periods.

The balance sheet at December 31, 2002 has been derived from the
audited financial statements at that date. Certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. These consolidated financial statements should be read in
conjunction with the financial statements and related notes thereto included in
the Company's Annual Report on Form 10-K for the year ended December 31, 2002.

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

Certain reclassifications of prior year amounts have been made to
conform with the current year presentation.

NOTE 2 EARNINGS PER SHARE

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 relevant periods. 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 dilutive
computed using the treasury stock method.

Options to purchase 1,225,753 shares of common stock were outstanding
during the six-month period ended June 30, 2003, but were not included in the
computation of diluted earnings per share because the options' exercise prices
were greater than the average market prices of the common shares during the
periods. These options' exercise prices were between $3.13-$7.65 and expire in
2010-2012. For the three months ended June 30, 2003, 2,369,919 of the Company's
options and warrants were not included in the computation of diluted loss per
share because the effect of the assumed exercise of these stock options as of
the beginning of the year would have an antidilutive effect. For the six months
ended June 30, 2002, 3,476,749 of the Company's options and warrants were not
included in the computation of diluted loss per share because the effect of the
assumed exercise of these stock options as of the beginning of the year would
have an antidilutive effect. Options to purchase 160,000 shares of common stock
were outstanding during the three-month period ended June 30, 2002, but were not
included in the computation of diluted earnings per share because the options'
exercise prices were greater than the average market prices of the common shares
during the periods. These options' exercise prices were between $6.25-$7.65 and
expire in 2011.

NOTE 3 LONG-TERM DEBT

The Company entered into a bank credit facility on May 14, 2003 with a
group of two banks. The Company expensed $203,000 of deferred financing costs,
which is included in interest expense, during the quarter ended June 30, 2003
relating to the previous credit facility.

Pursuant to the new credit facility agreement, PetroQuest and our
subsidiary PetroQuest Energy, L.L.C. (the "Borrower") have a $75 million
revolving credit facility with a group of two banks which permits the Borrower
to borrow amounts from time to time based on its 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 as of April 1 and October 1 of each year of

4

the Borrower's mortgaged properties, projected oil and gas prices, and any other
factors deemed relevant by the lenders. The Company or the lenders may also
request additional borrowing base redeterminations. As of June 30, 2003, the
borrowing base under this credit facility was $14.25 million and is subject to
monthly reductions of $1.25 million. The banks will determine future monthly
reductions in connection with each borrowing base redetermination.

Outstanding balances on the revolving credit facility bear interest at
either the bank's prime rate plus a margin (based on a sliding scale of 0.75% to
1.25% based on borrowing base usage but never less than the Federal Funds
Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a
sliding scale of 2.0% to 2.5% depending on borrowing base usage). The credit
facility also allows the Company to use up to $5 million of the borrowing base
for letters of credit for fees equal to the applicable margin rate for
Eurodollar advances. At August 8, 2003, the Company had $7 million of borrowings
and $4.2 million in letters of credit issued pursuant to the credit facility.

The Company is subject to certain restrictive financial and
non-financial covenants under the credit facility, including a minimum current
ratio, a minimum tangible net worth, maximum debt to EBITDA ratio, maximum G&A
expenses, and limiting authorization for expenditures on dry hole costs, all as
defined in the credit facility. The credit facility also requires the Borrower
to establish and maintain commodity hedges covering at least 50% of its proved
developed producing reserves on a rolling twelve-month basis. The credit
facility matures on May 14, 2006.

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 derivative expense
in the Company's income statement. At June 30, 2003, the Company recognized a
liability of $384,000 related to these derivative instruments.

NOTE 4 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 adopted SFAS 143 effective January 1, 2003. The net
difference between the Company's previously recorded abandonment liability and
the amounts estimated under SFAS 143, after taxes, totaled a gain of $849,000,
which has been recognized as a cumulative effect of a change in accounting
principle. The gain is due to the effect on the historical depletion as a result
of the retirement obligation being recorded at fair value. On a pro forma basis,
the impact for the six months ended June 30, 2002 would have increased net
income by $180,000.

The Company has legal obligations to plug, abandon and dismantle
existing wells and facilities that it has acquired and constructed during its
existence. As of January 1, 2003, the Company recognized a $9,467,000 liability
for its asset retirement obligations and recorded the related additional assets
that will be depreciated using the units-of-production method. The following
table describes all changes to the Company's asset retirement obligation
liability:

5

In January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which requires extensive disclosures (including certain disclosures that are
applicable to December 31, 2002 financial statements) and will require companies
to evaluate variable interest entities to determine whether to apply the
consolidation provisions of FIN 46 to those entities. Companies must apply FIN
46 to entities with which they are involved if the entity's equity has specified
characteristics. If it is reasonably possible that a company will have a
significant variable interest in a variable interest entity at the date FIN 46's
consolidation requirements become effective, the company must disclose the
nature, purpose, size and activities of the variable interest entity and the
consolidated enterprise's maximum exposure to loss resulting from its
involvement with the variable interest entity in all financial statements issued
after January 31, 2003 (including December 31, 2002 financial statements)
regardless of when the variable interest entity was created. The consolidation
provisions of FIN 46, if applicable, would apply to variable interest entities
created after January 31, 2003 immediately, and to variable interest entities
created before February 1, 2003 in the Company's interim period beginning after
June 15, 2003. The Company believes that the implementation of the provisions of
FIN 46 will not have a material effect on the Company's consolidated financial
statements.

NOTE 5 EQUITY

Other Comprehensive Income and Derivative Instruments

The following table presents a recap of the Company's comprehensive
income for the three- and six-month periods ended June 30, 2003 and 2002 (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 June 30, 2003, the Company had three fixed price
swap contracts with third parties designated as hedges, whereby a fixed price
has been established for a certain period. For the three months ended June 30,
2003 and 2002, the effect of derivative financial instruments is net of deferred
income tax benefit of $342,000 and $202,000, respectively. For the six months
ended June 30, 2003, the effect of derivative financial instruments is net of
deferred income tax benefit of $161,000. The cash settlements of these hedges
are recorded in oil and gas revenues. Oil and gas sales include reductions
related to gas hedges of $624,000 and $591,000 and oil hedges of $287,000 and
zero for the three months ended June 30, 2003 and 2002, respectively.

6

Oil and gas sales include reductions related to gas hedges of $2,269,000 and
$729,000 and oil hedges of $1,011,000 and zero for the six months ended June 30,
2003 and 2002, respectively.

During the quarter ended June 30, 2003, one of the Company's commodity
hedges became ineffective and a $1,300,000 mark-to-market charge was recorded on
the income statement. This charge was recorded on the income statement because
of a decline in production in the specific field to which the derivative was
designated.

Public Offering

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.

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.

NOTE 6 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,
"Accounting for Stock Issued to Employees." No stock option compensation cost is
reflected in net income (loss), as all options granted under the plan had an
exercise price equal to the market value of the underlying common stock on the
date of grant. The Company is recognizing compensation expense as a result of
the Original Owners granting options to three officers as discussed in Note 5.
The following table illustrates the effect on net income (loss) and earnings
(loss) per share if the Company had applied the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock Based Compensation" pursuant
to the disclosure requirements of SFAS No. 148, "Accounting for Stock-Based
Compensation - Transition and Disclosure" (in thousands, except per share data):

7

Item 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

GENERAL

PetroQuest Energy, Inc. 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. The Company and its
predecessors have been active in this area since 1986, which gives the Company
extensive geophysical, technical and operational expertise in this area.

The Company's business strategy is to increase production, cash flow
and reserves through exploration, development and acquisition of properties
located in the Gulf Coast Region. At June 30, 2003, the Company operated
approximately 95% of all of its proved reserves. For the six months ended June
30, 2003, approximately 51% of the Company's equivalent production was oil and
49% was natural gas.

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 relate 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.

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.

8

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

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 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.

9

RESULTS OF OPERATIONS

The following table (unaudited) sets forth certain operating
information with respect to our oil and gas operations for the periods noted:

The above sales include reductions related to gas hedges of $624,000 and
$591,000 and oil hedges of $287,000 and zero for the three months ended June 30,
2003 and 2002, respectively. The above sales include reductions related to gas
hedges of $2,269,000 and $729,000 and oil hedges of $1,011,000 and zero for the
six months ended June 30, 2003 and 2002, respectively.

Net loss and income totaled $1,698,000 and $255,000 for the quarters ended June
30, 2003 and 2002, respectively. Net income and loss totaled $1,295,000 and
$109,000 for the six-month periods ended June 30, 2003 and 2002, respectively.
The results are attributable to the following components:

PRODUCTION. Oil production in 2003 decreased 16% and 7% from the second quarter
and six months ended June 30, 2002, respectively. Natural gas production in 2003
decreased 56% and 43% from the second quarter and six months ended June 30,
2002, respectively. On a Mcfe basis, production for the quarter and six months
ended June 30, 2003 decreased 40% and 29% over the same periods in 2002,
respectively. The decrease in current year production as compared to 2002 was
due to well performance at our Bordeaux and Berry Lake wells, the consistent
decline of our Gulf Coast production and the absence of the addition of a
significant amount of new discoveries.

PRICES. Average oil prices per Bbl for the quarter and six months ended June 30,
2003 were $27.39 and $29.31, as compared to $25.51 and $23.01, respectively, for
the same periods in 2002. Average gas prices per Mcf were $4.78 and $5.29 for
the quarter and six months ended June 30, 2003, as compared to $3.03 and $2.67,
respectively, for the same periods in 2002. Stated on a Mcfe basis, unit prices
received during the second quarter and six months ended June 30, 2003 were 32%
and 63% higher, respectively, than the prices received during the comparable
2002 periods.

REVENUE. Oil and gas sales during the second quarter ended June 30, 2003
decreased to $9,060,000 as compared to sales of $11,357,000 for the same period
in 2002. The decrease in production volumes resulted in a decrease in revenue.
Oil and gas sales during the six months ended June 30, 2003 increased to
$25,214,000 as compared to sales of $21,866,000 for the same period in 2002. The
increase in commodity prices partially offset by a decrease in production
volumes, resulted in a decrease in revenue.

EXPENSES. Lease operating expenses for the quarter and six months ended June 30,
2003 increased to $2,504,000 and $5,266,000, respectively as compared to
$2,404,000 and $4,752,000, respectively, for the same periods in 2002. On a Mcfe
basis, lease operating expenses for the quarter and six months ended June 30,
2003 increased to $1.29 and $1.06, respectively, as compared to $0.75 and $0.68
for the same periods during 2002. The increase is primarily due to the decrease
in production volumes without a comparable reduction of the fixed costs in our
major fields.

General and administrative expenses during the second quarter and six months
ended June 30, 2003 totaled $1,126,000 and $2,348,000, respectively, as compared
to expenses of $1,542,000 and $2,743,000, respectively,

10

during the 2002 periods. The Company capitalized $918,000 and $1,895,000,
respectively, of general and administrative costs during the quarter and six
months ended June 30, 2003 as compared to $1,043,000 and $1,968,000,
respectively in the comparable 2002 periods. We have recognized $69,000 and
$155,000, respectively, of non-cash compensation expense during the quarter and
six months ended June 30, 2003. We recorded non-cash compensation expense of
$86,000 and $172,000, respectively, during the quarter and six months ended June
30, 2002.

Depreciation, depletion and amortization ("DD&A") expense for the three- and
six-month periods ended June 30, 2003 decreased and increased 11% and 5%,
respectively, from the 2002 periods. On a Mcfe basis, which reflects the changes
in production, the DD&A rate for the second quarter of 2003 was $3.02 per Mcfe
as compared to $2.06 per Mcfe for the same period in 2002. The DD&A rate for the
six months ended June 30, 2003 was $2.89 per Mcfe compared to $1.96 per Mcfe for
the same period in 2002. The increase in 2003 as compared to 2002 is due
primarily to the significant capital expended during the previous twelve months
without a comparable increase in our reserve base.

Interest expense, net of amounts capitalized on unevaluated prospects, increased
$213,000 and $27,000 during the second quarter and six months ended June 30,
2003, respectively, as compared to the same periods in 2002. The increases are
the result of an increase in the average debt levels during the current year. We
capitalized $109,000 and $144,000 of interest during the three months ended June
30, 2003 and 2002, respectively, and $233,000 and $307,000 during the six months
ended June 30, 2003 and 2002, respectively.

Derivative expense increased $1,444,000 and $1,445,000 during the second quarter
and six months ended June 30, 2003, respectively, as compared to the same
periods in 2002. These increases are primarily the result of a $1,300,000
mark-to-market charge on one of our gas derivatives. This charge was recorded on
the income statement because of a decline in production in the specific field to
which the derivative was designated. Additionally, the monthly settlements
related to this derivative have been recorded to derivative expense effective
during June 2003.

Income tax benefit and expense of $914,000 and $241,000 was recognized during
the second quarter and six months ended June 30, 2003, respectively, as compared
to expense and benefit of $137,000 and $59,000 during the same periods of 2002.
The changes are a result of fluctuations in the operating profit during the
current year. We provide for income taxes at a statutory rate of 35%.

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 six months ended June 30, 2003
decreased from $14,168,000 in 2002 to $13,051,000 in 2003. This decrease
resulted primarily from the decrease in production volumes during the current
year. Additionally, we utilized discretionary cash flow to reduce our vendor
payables and debt during the first six months of 2003, which decreased our net
cash flow from operations. The working capital deficit was reduced from $(15.8)
million at December 31, 2002 to $(11.3) million at June 30, 2003. This decrease
was caused primarily by our effort to utilize cash flow to first reduce our
working capital deficit and second to drill prospects. These strategies were
partially offset by an increase in the current portion of long-term debt due to
the borrowing base reductions as required by our credit facility. In order to
reduce expenses for the remainder of 2003, our management team has voluntarily
reduced salaries, and we have reduced our staff, which should result in an
aggregate annual savings of in excess of $1 million.

Source of Capital: Debt

We entered into a new bank credit facility on May 14, 2003 with a group of two
banks. We expensed $203,000 of deferred financing costs, which is included in
interest expense, during the quarter ended June 30, 2003 relating to our
previous credit facility.

Pursuant to the new credit facility agreement, PetroQuest and our subsidiary
PetroQuest Energy, L.L.C. (the "Borrower") have a $75 million revolving credit
facility with a group of two 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

11

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 as of
April 1 and October 1 of each year 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. As of June 30, 2003, the borrowing base under this credit
facility was $14.25 million and is subject to monthly reductions of $1.25
million. The banks will determine future monthly reductions in connection with
each borrowing base redetermination.

Outstanding balances on the revolving credit facility bear interest at either
the bank's prime rate plus a margin (based on a sliding scale of 0.75% to 1.25%
based on borrowing base usage but never less than the Federal Funds Effective
Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a sliding scale
of 2.0% to 2.5% depending on borrowing base usage). The credit facility also
allows us to use up to $5 million of the borrowing base for letters of credit
for fees equal to the applicable margin rate for Eurodollar advances. At August
8, 2003, we had $7 million of borrowings and $4.2 million in letters of credit
issued pursuant to the credit facility.

We are subject to certain restrictive financial and non-financial covenants
under the credit facility, including a minimum current ratio, a minimum tangible
net worth, maximum debt to EBITDA ratio, maximum G&A expenses, and limiting
authorization for expenditures on dry hole costs, all as defined in the credit
facility. The credit facility also requires the Borrower to establish and
maintain commodity hedges covering at least 50% of its proved developed
producing reserves on a rolling twelve month basis. The credit facility matures
on May 14, 2006.

Natural gas and oil prices have a significant impact on our cash flows available
for capital expenditures and our ability to borrow and raise additional capital.
The amount we can borrow under our credit facility is subject to periodic
re-determination based in part on changing expectations of future prices. Lower
prices may also reduce the amount of natural gas and oil that we can
economically produce. Additionally, the production declines of certain producing
wells resulted in lower production in the six months ended June 30, 2003. Lower
prices and/or lower production may decrease revenues, cash flows and the
borrowing base under the credit facility, thus reducing the amount of financial
resources available to meet our capital requirements.

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.

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 that
will require significant capital. Our capital budget for capital for new
projects in 2003 is approximately $20-25 million of which $10.3 million had been
incurred by June 30, 2003. We have completed the drilling of our Murphy Castle
and Knight prospects, and are currently drilling our Trout and Pinot Grigio
prospects. Our management believes that cash flows from operations will be
sufficient to fund planned 2003 exploration and development activities. We will
actively seek industry partners for certain of our prospects to provide further
funding for our 2003 planned activities. In the future, our

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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.

DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

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

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

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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 the remaining six
months of 2003, a 10% change in the prices the Company receives for its crude
oil and natural gas production would have an approximate $1.7 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 June 30, 2003, 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 the remainder of 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 June 30, 2003,
the Company recognized a liability of $2,518,000 related to these derivative
instruments, of which three have been designated as cash flow hedges and one has
been deemed ineffective and recorded through derivative expense on the income
statement.

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 derivative expense in our
income statement. As of June 30, 2003, the fair value of the open interest rate
swaps was a liability of $384,000.

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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 June 30, 2003. Based upon an analysis, utilizing the
actual interest rate in effect and balances outstanding as of June 30, 2003 and
assuming a 10% increase in interest rates and no changes in the amount of debt
outstanding, the potential effect on interest expense for the remaining six
months of 2003 is approximately $13,000.

Item 4. CONTROLS AND PROCEDURES

Within the 90-day period prior to the date of this report, the Company carried
out an evaluation, under the supervision and with the participation of the
Company's management, including the Company's Chief Executive Officer and Chief
Financial Officer, of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Rule 13a-14 of the
Securities Exchange Act of 1934 (the "Exchange Act"). Based upon that
evaluation, the Chief Executive Officer and Chief Financial Officer concluded
that the Company's disclosure controls and procedures are effective, in all
material respects, with respect to the recording, processing, summarizing and
reporting, within the time periods specified in the Securities and Exchange
Commission's rules and forms, of information required to be disclosed by the
issuer in the reports that it files or submits under the Exchange Act.

There have been no significant changes in the Company's internal controls or in
other factors that could significantly affect internal controls subsequent to
the date the Company carried out its evaluation.

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PART II

Item 1. LEGAL PROCEEDINGS

NONE.

Item 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

NONE.

Item 3. DEFAULTS UPON SENIOR SECURITIES

NONE.

Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On May 7, 2003, an annual meeting of stockholders of the Company was
held. The holders of 37,726,058 shares of Common Stock were present in person or
represented by proxy at the meeting. At the meeting, the stockholders elected
the following persons to serve as directors of the Company until the next annual
meeting of stockholders, or until their successors are duly elected and
qualified:

Item 5. OTHER INFORMATION

NONE.

Item 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits:

Exhibit 10.1. Amended and Restated Credit Agreement, dated as
of May 14, 2003, by and between PetroQuest Energy, LLC, PetroQuest
Energy, Inc., Bank One, NA, Banc One Capital Markets, Inc., and certain
other Lenders.

Exhibit 10.2. Guaranty dated May 14, 2003, between PetroQuest
Energy, Inc. and Bank One, NA, as Agent for the Lenders.

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

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

Exhibit 32.1. Certification Pursuant to 18 U.S.C. Section
1350, As Adopted Pursuant To Section 906 Of The Sarbanes-Oxley Act Of
2002.

15

Exhibit 32.2. Certification Pursuant to 18 U.S.C. Section 1350,
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K:

On May 8, 2003, the Company filed a current report on Form 8-K
regarding its 2003 first quarter results.

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SIGNATURE

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

PETROQUEST ENERGY, INC.

Date: August 13, 2003 By: /s/ Michael O. Aldridge
------------------- -------------------------------------
Michael O. Aldridge
Senior Vice President, Chief
Financial Officer and Treasurer
(Authorized Officer and Principal
Financial and Accounting Officer)

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