Back to GetFilings.com
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
(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, 2001
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. 98-0115468
400 E. Kaliste Saloom Road, Suite 3000
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
(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 the 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. | |
The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $218,988,808 as of March 11, 2002 (based on the
last reported sale price of such stock on the Nasdaq National Market System).
As of March 11, 2002, the registrant had outstanding 37,756,691 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 April 30, 2002
which is incorporated into Part III of this Form 10-K.
TABLE OF CONTENTS
Page No.
--------
PART I
Item 1. Business ...................................................... 1
Item 2. Properties .................................................... 14
Item 3. Legal Proceedings ............................................. 16
Item 4. Submission of Matters to a Vote of Security Holders ........... 16
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters ....................................................... 16
Item 6. Selected Financial Data ....................................... 17
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations ..................................... 18
Item 7A. Quantitative and Qualitative Disclosure About Market Risks .... 23
Item 8. Financial Statements and Supplementary Data ................... 23
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure ...................................... 23
PART III
Item 10. Directors and Executive Officers of the Registrant ............ 24
Item 11. Executive Compensation ........................................ 24
Item 12. Security Ownership of Certain Beneficial Owners and
Management .................................................... 24
Item 13. Certain Relationships and Related Transactions ................ 24
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K ...................................................... 24
Index to Financial Statements ................................. F-1
This Form 10-K contains "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended (the "Securities Act"),
and Section 21E of the Securities Exchange Act of 1934, as amended (the
"Exchange Act"). All statements other than statements of historical facts
included in and incorporated by reference into this Form 10-K are forward
looking statements. These forward looking statements 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 give any assurance 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.
1
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
Natural gas is stated in billion cubic feet ("Bcf"), million cubic feet
("MMcf") or thousand cubic feet ("Mcf"). Oil is stated in barrels ("Bbl") or
thousand barrels ("MBbl). Mmcfe and Mcfe represent the equivalent of one million
and one thousand cubic feet of natural gas, respectively. Oil is converted to
gas at a ratio of one barrel of liquids per six Mcf of gas, based on relative
energy content. "Net" acres, production or wells refers to the total acres,
production or wells in which PetroQuest has a working interest, multiplied by
the percentage working interest owned by PetroQuest.
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, 2001, the Company's estimated proved reserves totaled
6,213 MBbl of oil and 44,944 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 $88,230,449. Approximately 55%
of the Company's reserves are proved developed reserves. The Company operates
nine 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. This field has
produced in excess of 350 billion cubic feet equivalent to date. During 2001,
the Company drilled and completed four wells that produced over 4.9 Bcf net to
the Company. The Company had a fifth well in progress at year-end that was
completed in February 2002. 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 nine additional
developmental wells and three exploratory wells. Reprocessed 3-D data is
currently being reviewed for additional opportunities.
TURTLE BAYOU FIELD, TERREBONNE PARISH, LA. To date, the Company has
participated in the drilling of fifteen wells in the Turtle Bayou Field. As of
December 31, 2001, there are four producing wells in the field in which we hold
a working interest. Collectively, the four producing wells averaged
approximately 26,000 Mcf of natural gas and 570 barrels of oil per day for the
month of December 2001. 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, 2001.
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. The field began
production in December 2000 and, during 2001, produced at an average rate of
approximately 750 Bbls per day of oil and 2,500 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 2001 production averaged approximately 2,500 Mcfe per day net
to PetroQuest. Additional exploration opportunities have been identified and are
currently being evaluated for future drilling.
2
VALENTINE FIELD, LAFOURCHE PARISH, LA. The Valentine Field has to date
produced in excess of one trillion cubic feet of gas equivalent. For the month
of December 2001, production averaged 250 Bbls of oil per day and 3,100 Mcf of
natural gas per day from six wells. We recently sold our interest in this field
for $18.6 million, effective 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.
MARKETS
PetroQuest's ability to market oil and gas from the Company's wells
depends upon numerous factors beyond the Company's control, including the extent
of domestic production and imports of oil and gas, the proximity of the gas
production to gas pipelines, the availability of capacity in such pipelines, the
demand for oil and gas by utilities and other end users, the availability of
alternative fuel sources, the effects of inclement weather, state and federal
regulation of oil and gas production and federal regulation of gas sold or
transported in interstate commerce. No assurance can be given that 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, 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.
For the year ended December 31, 1999, the Company had three customers who
accounted for 22%, 12% and 10% 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;
- 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,
- permits pipelines to file for authority to charge different maximum
cost-based rates for peak and off-peak periods,
- encourages, but does not mandate, auctions for pipeline capacity,
- requires pipelines to implement imbalance management services,
- restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow
orders, and
3
- 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.
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
4
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 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 requirements for obtaining drilling permits, the method of developing
new fields, the spacing and operation of wells and the prevention of waste of
oil and gas
5
resources. 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 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
6
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.
7
EMPLOYEES
The Company had 53 employees as of December 31, 2001. 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.
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:
- relatively minor changes in the supply of and the demand for oil and
natural gas;
- market uncertainty;
- the level of consumer product demand;
- weather conditions in the United States;
- the condition of the United States economy;
- the action of the Organization of Petroleum Exporting Countries;
- domestic and foreign governmental regulation, including price
controls adopted by the Federal Energy Regulatory Commission;
- political instability in the Middle East and elsewhere;
- the foreign supply of oil and natural gas;
- the price of foreign imports; and
8
- 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:
- the available data;
- assumptions regarding future oil and natural gas prices;
- estimated expenditures for future development and exploitation
activities; and
- engineering and geological interpretation and judgment.
Reserves and future cash flows may also be subject to material downward or
upward revisions based upon production history, development and exploitation
activities and oil and natural gas prices. Actual future production, revenue,
taxes, development expenditures, operating expenses, quantities of recoverable
reserves and the value of cash flows from those reserves may vary significantly
from the assumptions and estimates in this 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.
Over 40% 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.
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
9
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:
- the level of domestic production and imports of oil and natural gas;
- the proximity of natural gas production to natural gas pipelines;
- the availability of pipeline capacity;
- the demand for oil and natural gas by utilities and other end users;
- the availability of alternate fuel sources;
- the effect of inclement weather;
- state and federal regulation of oil and natural gas marketing; and
- federal regulation of natural gas sold or transported in interstate
commerce.
If these factors were to change dramatically, our ability to market oil
and natural gas or obtain favorable prices for our oil and natural gas could be
adversely affected.
We face strong competition from larger oil and natural gas companies that
may negatively affect our ability to carry on operations.
We operate in the highly competitive areas of oil and natural gas
exploration, development and production. Factors that affect our ability to
compete successfully in the marketplace include:
- the availability of funds and information relating to a property;
- the standards established by us for the minimum projected return on
investment; and
- the 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.
10
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:
- borrowings from banks or other lenders;
- the issuance of debt securities;
- the sale of common stock, preferred stock or other equity
securities;
- joint venture financing; and
- production payments.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and natural gas prices 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:
- a portion of our cash flow from operations is used to pay interest
on borrowings;
- the covenants contained in the agreements governing our debt limit
our ability to borrow additional funds or to dispose of assets;
- the covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes in
business conditions;
- 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;
- our leveraged financial position may make us more vulnerable to
economic downturns and may limit our ability to withstand
competitive pressures;
- 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
11
- 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:
- unexpected drilling conditions including blowouts, cratering and
explosions;
- uncontrollable flows of oil, natural gas or well fluids;
- equipment failures, fires or accidents;
- pollution and other environmental risks; and
- shortages in experienced labor or shortages or delays in the
delivery of equipment.
These risks could result in substantial losses to us from injury and loss of
life, damage to and destruction of property and equipment, pollution and other
environmental damage and suspension of operations. Our offshore operations are
also subject to a variety of operating risks peculiar to the marine environment,
such as hurricanes or other adverse weather conditions and more extensive
governmental regulation. These regulations may, in certain circumstances, impose
strict liability for pollution damage or result in the interruption or
termination of operations.
Losses and liabilities from uninsured or underinsured drilling and
operating activities could have a material adverse effect on our financial
condition and operations.
We maintain several types of insurance to cover our operations, including
maritime employer's liability and comprehensive general liability. Amounts over
base coverages are provided by primary and excess umbrella liability policies
with maximum limits of $50 million. We also maintain operator's extra expense
coverage, which covers the control of drilled or producing wells as well as
redrilling expenses and pollution coverage for wells out of control.
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.
12
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:
- require the acquisition of permits before drilling commences;
- restrict the types, quantities and concentration of various
substances that can be released into the environment from drilling
and production activities;
- limit or prohibit drilling activities on certain lands lying within
wilderness, wetlands and other protected areas;
- require remedial measures to mitigate pollution from former
operations, such as plugging abandoned wells; and
- impose substantial liabilities for pollution resulting from our
operations.
The 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 in certain of our properties by certain of
our officers and directors may create conflicts of interest.
Certain of our executive officers and directors, and their respective
affiliates, are working interest owners in our Turtle Bayou Field. These
interests were acquired by these officers and directors and their respective
affiliates prior to the acquisition of their equity interests in PetroQuest in
1998. 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. 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
this property.
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 29% of our outstanding common stock at March 1, 2002. 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.
13
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:
- the charter authorization of "blank check" preferred stock;
- provisions that directors may be removed only for cause, and then
only on approval of holders of a majority of the outstanding voting
stock; and
- a restriction on the ability of stockholders to take actions by
written consent.
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, 2001.
Oil (Mbbls) Gas (MMcfs)
----------- -----------
Proved developed: 3,104 26,847
Proved undeveloped: 3,109 18,097
Total proved: 6,213 44,944
Estimated pre-tax future net cash flows $116,035,936
Discounted pre-tax future net cash flows $ 88,230,449
Standardized measure of discounted future $ 75,046,568
net cash flows
Ryder Scott Company prepared the estimates of proved reserves and future
net cash flows (and present value thereof) attributable to such proved reserves
at December 31, 2001. Reserves were estimated using oil and gas prices and
production and development costs in effect at December 31, 2001 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
14
developing the above estimates averaged $18.49 per Bbl of oil and $2.65 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 $2.69 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.
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:
2001 2000 1999
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploration:
Productive 1 0.41 3 1.32 4 1.33
Non-productive 2 0.68 1 0.40 1 0.05
---- ---- ---- ---- ---- ----
Total 3 1.09 4 1.72 5 1.38
==== ==== ==== ==== ==== ====
Development:
Productive 9 5.78 3 1.23 1 0.41
Non-productive 1 0.54 1 0.40 -- --
---- ---- ---- ---- ---- ----
Total 10 6.32 4 1.63 1 0.41
==== ==== ==== ==== ==== ====
The Company owned working interests in 57 gross (35.6 net) producing oil
and gas wells at December 31, 2001. At December 31, 2001, 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, 2001:
Leasehold Acreage
-----------------
Developed Undeveloped
--------- -----------
Gross Net Gross Net
----- --- ----- ---
Mississippi (onshore) 721 450 8,110 5,190
Louisiana (onshore) 7,566 4,190 16,361 11,127
Texas (offshore) 1,440 636 -- --
Federal Waters 40,970 22,078 61,561 32,969
------ ------ ------ ------
Total 50,697 27,354 86,032 49,286
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: royalties and other burdens and
obligations, express or implied, under oil and gas leases; overriding royalties
and other burdens created by the Company or its predecessors in title; a variety
of contractual obligations (including, in some cases, development obligations)
arising under operating agreements, farmout agreements, production sales
contracts and other agreements that may affect the properties or their titles;
back-ins and reversionary interests existing under purchase agreements and
leasehold assignments; liens that arise in the normal course of operations, such
as those for unpaid taxes, statutory liens securing obligations to unpaid
suppliers and contractors and contractual liens under operating agreements;
pooling, unitization and communitization agreements, declarations and orders;
and easements, restrictions, rights-of-way and other matters that commonly
affect property. To the extent that such burdens and obligations affect the
Company's rights to production revenues, they have been taken into account in
calculating the Company's
15
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.
PetroQuest Energy, Inc. and PetroQuest Energy One, L.L.C. v. Schlumberger
Technology Corporation, et al, bearing Civil Action No. 00-2823 of the United
States District Court, Western District of Louisiana was filed on December 29,
2000. This matter is a lawsuit filed by the Company's subsidiaries, PetroQuest
Energy, Inc., a Louisiana corporation, and PetroQuest Energy One, L.L.C. (now
PetroQuest Energy, L.L.C.) seeking to recover cost overruns in the amount of
approximately $2,850,000 which were incurred in the completion of theOCSG-15243
#2 Well located at Eugene Island Block 147. The Company asserts that cost
overruns were incurred due to the negligence of Schlumberger Technology
Corporation. On May 17, 2001, Schlumberger Technology Corporation filed a
counter-claim for $437,200, plus interest, attorney's fees and costs for goods
and services allegedly provided in connection with the OCSG-15243 #2 Well.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter of 2001.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
MARKET PRICE OF AND DIVIDENDS ON COMMON STOCK
The Company's Common Stock trades on The Nasdaq Stock Market under the
symbol "PQUE". On January 19, 2001, the Company voluntarily delisted its Common
Stock from the Toronto Stock Exchange ("TSE") where it formally traded under the
symbol "PQU." The Company delisted its stock from the TSE because it no longer
had Canadian operations and
16
substantially all of its trading volume was on The Nasdaq Stock Market. The
following table lists high and low sales prices per share for the periods
indicated:
Nasdaq Stock Market Toronto Stock Exchange
------------------- ----------------------
Quarter Ended High Low High Low
------------- ---- --- ---- ---
(U.S.$) (U.S.$) (CDN $) (CDN $)
2000
1st Quarter 2.25 1.38 3.00 2.10
2nd Quarter 3.00 1.38 4.50 2.05
3rd Quarter 4.38 2.13 6.75 2.50
4th Quarter 4.94 2.81 6.80 4.00
2001
1st Quarter 5.63 3.69 6.50 5.05
2nd Quarter 8.99 4.00 N/A N/A
3rd Quarter 7.34 3.95 N/A N/A
4th Quarter 7.35 4.66 N/A N/A
As of February 15, 2002, there were approximately 595 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 Hibernia National
Bank, Royal Bank of Canada and Union Bank of California, N.A. restricts the
declaration or payment of any dividends or distributions without prior written
consent of Hibernia National Bank and either Royal Bank of Canada or Union Bank
of California N.A.
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, 2001
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.
Years Ended December 31,
------------------------
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands except share data)
Revenues $ 55,281 $22,561 $ 8,607 $ 3,377 $ 4,145
Net Income (Loss) 11,645 9,924 (310) (16,240) (2,914)
Net Income (Loss) per share:
Basic 0.37 0.37 (0.01) (1.20) (0.26)
Diluted 0.34 0.35 (0.01) (1.20) (0.26)
Oil and Gas Properties, net 101,029 56,344 21,490 17,423 12,862
Total Assets 114,639 83,072 29,901 20,066 20,163
Long-term Debt 33,000 6,804 2,927 1,300 100
Stockholders' Equity 54,215 41,456 18,105 13,336 18,740
17
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.
MERGER OF OPTIMA ENERGY (U.S.) CORPORATION
On September 1, 1998, the Company, formerly known as Optima Petroleum
Corporation, 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.
Pursuant to the Merger, the Company issued to the original owners of
American Explorer 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 entitle 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 as the
trading price for the Common Stock closes at $5.00 or higher for 20 consecutive
trading dates. 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.
On December 31, 2000, we underwent a subsequent corporate reorganization.
Our 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.
NEW ACCOUNTING STANDARDS
On January 1, 2001, we 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. At January 1, 2001, we
recognized a liability of $609,295 related to costless collars; the cumulative
catch-up adjustment is recorded as a charge to other comprehensive income. These
collars were designated as cash flow hedges.
We recognized $1,630,000 in oil and gas revenues during the year ended
December 31, 2001 as a result of the settlement of costless collars. We had no
open commodity hedging contracts at December 31, 2001.
During the fourth quarter, we entered into three $5 million interest rate
swaps covering our floating rate debt. The swaps which are for one, two and
three year periods have fixed interest rates of 2.78%, 2.78%-4.56% and
3.05%-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, 2001, the fair value of open interest rate swaps was a liability of $61,000.
In July 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations," which requires recording the fair value of a liability for an
asset retirement obligation in the period incurred. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
permitted. The Company expects to adopt this standard effective January 1, 2003.
We have not completed an evaluation of the impact of this new standard.
18
CRITICAL ACCOUNTING POLICIES
Full cost method
We use the full cost method of accounting, which involves capitalizing all
acquisition, exploration and development costs. Once incurred, costs are
recorded in the full cost pool or in unevaluated properties. Unevaluated
property costs are not subject to depletion. We review our unevaluated costs on
an ongoing basis, and we expect for such costs to be evaluated in one to three
years and transferred to the full cost pool at that time.
We calculate depletion using the units-of-production method. Under this
method, the full cost pool and all estimated future development costs are
divided by the total amount of proved reserves. This rate is applied to our
total production for the period, and the appropriate expense is recorded.
We 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. We also capitalize the portion of general and
administrative costs that are attributable to our acquisition, exploration and
development activities.
To the extent that total capitalized oil and gas property costs (net of
accumulated depreciation, depletion and amortization) exceed the present value
(using a 10% discount rate) of estimated future net cash flow from proved oil
and natural gas reserves, and the lower of cost and fair value of unproved
properties, excess costs are charged to operations. Once incurred, a write-down
of oil and natural gas properties is not reversible at a later date even if oil
or natural gas prices increase. We could be required to write-down our oil and
gas properties if there is a decline in oil and natural gas prices, or downward
adjustments are made to our proved reserves.
Reserves
Oil and gas reserve estimates are prepared by our independent petroleum
and geological engineers. Proved reserves, and the cash flows related to these
reserves, are estimated based on a combination of historical data and estimates
of future activity. Reserve estimates are used in calculating depletion and in
preparation of the full cost ceiling test.
Derivative Instruments
We follow SFAS 133 accounting for derivative instruments. The accounting
standard requires that we record our derivatives at fair market value as of the
balance sheet date. The calculations of fair value are estimates of the
derivatives future values based on current factors.
For a more complete discussion of our accounting policies see our Notes to
Consolidated Financial Statements on page F-7.
19
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, 2001, 2000 and
1999:
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
Production:
Oil (Bbls) 791,405 160,631 104,761
Gas (Mcf) 9,025,240 3,984,461 2,830,803
Total Production (Mcfe) 13,773,670 4,948,246 3,459,369
Sales:
Total oil sales $20,171,659 $ 4,809,382 $1,933,192
Total gas sales 34,794,876 17,457,307 6,583,026
Average sales prices:
Oil (per Bbl) $ 25.49 $ 29.94 $ 18.45
Gas (per Mcf) 3.86 4.38 2.33
Per Mcfe 3.99 4.50 2.46
The above sales include income related to gas collars of $1,247,000 and oil
collars of $384,000 for the year ended December 31, 2001. We were not hedged
during 2000 and 1999.
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.
20
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.
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.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2000 AND
1999
The net income for the year ended December 31, 2000 was $9,924,000 as
compared to a net loss of $310,000 for the same period ended 1999. The positive
results are due to the following components:
Production
Oil production in 2000 increased 53% over the year ended December 31,
1999. Natural gas production in 2000 increased 41% over the year ended December
31, 1999. On an Mcfe basis, production for the year ended December 31, 2000
increased 43% over the same period in 1999. The increase in 2000 production
volumes, as compared to 1999, was primarily due to three new wells that were not
producing in 1999. CL&F #14 and CL&F #15 at Turtle Bayou and Valentine Sugars #1
came on-line during December 1999, May 2000, and August 2000, respectively.
Prices
Average oil and natural gas prices realized were $29.94 and $4.38 for the
year ended December 31, 2000, as compared to $18.45 and $2.33 for the same
period ended 1999. This represents price increases of 62% for oil, 88% for
natural gas and 83% on an Mcfe basis.
Oil and Gas Revenues
Oil and gas sales increased from $8,516,000 to $22,267,000 in 2000 or an
increase of 162%. This increase is the result of both increases in production
volumes and higher product prices for both oil and gas.
Lease Operating Expenses
Lease operating expenses increased 7% from $2,638,000 to $2,831,000. This
resulted from the additional wells discussed above as well as high initial costs
of three new wells drilled in the fourth quarter of 2000. On an Mcfe basis,
operating expenses for the year decreased from $.76 in 1999 to $.57 in 2000 as a
result of increased production.
21
Depreciation, Depletion and Amortization
Depreciation, depletion and amortization (DD&A) increased 43% from
$4,472,000 to $6,386,000. This is due to the increased production for the year
and capital additions to property. On a Mcfe basis, which reflects changes in
production, the DD&A rate for 2000 and 1999 was $1.29 per Mcfe.
General and Administrative Expenses
Expensed general and administrative costs increased from $1,625,000 in
1999 to $3,248,000 in 2000. In 2000 and 1999, $2,084,000 and $1,361,000 of
general and administrative costs were capitalized as related directly to the
acquisition, exploration and development efforts of our resources. Total general
and administrative costs increased in 2000 due to an increase of 79% in staffing
levels related to the generation of prospects, exploration for oil and gas
reserves and operation of properties.
Interest Expense
Interest expense increased from $0 in 1999 to $78,000 in 2000, net of
amounts capitalized, as a result of interest incurred on producing properties.
We capitalized interest of $434,000 in 1999, as compared to $439,169 in 2000.
LIQUIDITY AND CAPITAL RESOURCES
We have financed our exploration and development activities to date
principally through cash flow from operations, bank borrowings, and private and
public offerings of Common Stock. Net cash flow from operations before working
capital changes during the year increased from $15,927,000 in 2000 to
$42,317,000 in 2001. This increase resulted from increased production as the
result of successful exploration and development activities. However, working
capital (before considering debt) decreased from $(1.9) million at December 31,
2000 to $(10.4) million at December 31, 2001. This was caused primarily by
capital expenditures related to our active exploration and development program
during 2001. The proceeds from our recent underwritten public offering and the
sale of the Valentine Field discussed below have eliminated our working capital
deficit (before considering debt) of approximately $10.4 million at December 31,
2001, and significantly reduced the balance due on our credit facility.
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.
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 will not recognize any gain or loss as a
result of this sale.
PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the "Borrower")
have a $100 million revolving credit facility with Hibernia National Bank, Royal
Bank of Canada and Union Bank of California, N.A. 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 March 1, 2002, the borrowing base under the credit
facility was adjusted to $28 million and is subject to quarterly reductions of
$3 million commencing on April 30, 2002.
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
March 7, 2002, we had $5 million of borrowings and a $2.6 million letter of
credit issued pursuant to the credit facility.
22
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 March 7, 2002. The credit
facility matures on June 30, 2004.
As of December 31, 2001, $19 million of the outstanding balance under the
credit facility was classified as long term debt reflecting the remaining
borrowing base that would be available at December 31, 2002. Based upon this
determination, the remaining balance outstanding under the credit facility at
December 31, 2001 of $14 million was classified as debt subsequently refinanced
as a result of the public offering in February and March of 2002.
We have an exploration and development program budget for the year 2002
which will require significant capital. Our budget for direct capital for new
projects in 2002 is approximately $40-$45 million. Our management believes the
cash flows from operations, available borrowing capacity under our credit
facility, proceeds from the underwritten public offering and sale of the
Valentine Field will be sufficient to fund planned 2002 exploration and
development activities. In the future, our exploration and development
activities could require additional financings, which may include sales of
additional equity or debt securities, additional bank borrowings, or joint
venture arrangements with industry partners. There can be no assurances 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.
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 2002, a 10%
decline in the estimated average 2002 prices the Company receives for its crude
oil and natural gas production would have an approximate $4.7 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. The Company had no open commodity hedging contracts as
of December 31, 2001.
During the fourth quarter, we entered into three interest rate swaps
covering $5 million of our floating rate debt. The swaps which are for one, two
and three year periods have fixed interest rates of 2.78%, 2.78%-4.56% and
3.05%-5.665%, respectively. The swaps are stated at their fair value and are
marked-to-market through other income in our income statement.
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
approximately 99% of the Company's total debt as of December 31, 2001. Based
upon an analysis utilizing the actual interest rate in effect and balances
outstanding as of December 31, 2001 and assuming a 10% increase in interest
rates and no changes in the amount of debt outstanding, the potential effect on
interest expense for 2002 is approximately $157,000.
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
None.
23
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 April 30, 2002,
which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference.
PART IV
ITEM 14. 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-17 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 2001 and 2000
Consolidated Statements of Operations for the three years ended
December 31, 2001
Consolidated Statements of Stockholder's Equity for the three years
ended December 31, 2001
Consolidated Statements of Cash Flows for the three years ended
December 31, 2001
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 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 July 27, 2001).
4.1 Registration Rights Agreement dated as of September 1, 1998
among Optima Petroleum Corporation, Charles T. Goodson,
Alfred J. Thomas, II, Ralph J. Daigle, Janell B. Thomas,
Alfred J. Thomas, III, Blaine A. Thomas, and Natalie A.
Thomas (incorporated herein by reference to Exhibit 99.1 to
Form 8-K dated September 16, 1998).
4.2 Form of Certificate of Contingent Stock Issue Right
(incorporated herein by reference to Exhibit 4.3 to Form 8-K
dated September 16, 1998).
4.3 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)
24
4.4 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)
4.5 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 July 27, 2001).
4.6 Form of Rights Certificate (incorporated herein by reference
to Exhibit C of the Rights Agreement attached as Exhibit 1 to
Form 8-A filed July 27, 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).
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.
10.11 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).
10.12 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 Ralph J. Daigle (incorporated
herein by reference to Exhibit 10.4 to Form 8-K dated
September 16, 1998).
10.14 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)
10.15 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).
25
10.16 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).
10.17 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).
10.18 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).
10.19 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).
* 10.20 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 and Daniel G. Fournerat.
* 10.21 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 and Arthur
M. Mixon, III.
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 Public Accountant.
- ----------
* Filed herewith.
26
REPORTS ON FORM 8-K
The Company filed a report on Form 8-K on October 3, 2001 relating to the
Company's change in transfer agent and registrar.
The Company filed a report on form 8-K on October 16, 2001 relating to the
resignation of certain of its directors.
The Company filed a report on Form 8-K on November 8, 2001 relating to third
quarter 2001 results.
The Company filed a report on Form 8-K on November 9, 2001 relating to the
adoption of a shareholder rights plan.
The Company filed a report on Form 8-K on December 14, 2001 relating to the
drilling of a well.
27
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, 2002.
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, 2002.
By: /S/ Charles T. Goodson Chairman of the Board, Chief Executive
------------------------------- Officer and Director (Principal
CHARLES T. GOODSON Executive Officer)
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
MICHAEL O. ALDRIDGE (Principal Financial and Accounting
Officer)
By: /S/ Jay B. Langner Director
-------------------------------
JAY B. LANGNER
By: Director
-------------------------------
E. WAYNE NORDBERG
By: /S/ William W. Rucks, IV Director
-------------------------------
WILLIAM W. RUCKS, IV
28
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants .................................. F-2
Consolidated Balance Sheets of PetroQuest Energy, Inc. as of
December 31, 2001 and 2000 .............................................. F-3
Consolidated Statements of Operations of PetroQuest Energy, Inc.
for the years ended December 31, 2001, 2000 and 1999 .................... F-4
Consolidated Statements of Stockholders' Equity of PetroQuest Energy,
Inc. for the years ended December 31, 2001, 2000 and 1999 ............... F-5
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc. for
the years ended December 31, 2001, 2000 and 1999 ........................ F-6
Notes to Consolidated Financial Statements ................................ F-7
F-1
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
F-2
PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
December 31, December 31,
2001 2000
---- ----
ASSETS
Current assets:
Cash and cash equivalents $ 1,063 $ 7,549
Oil and gas revenue receivable 5,582 5,148
Joint interest billing receivable 4,609 10,151
Other current assets 135 1,432
------------ ------------
Total current assets 11,389 24,280
------------ ------------
Oil and gas properties:
Oil and gas properties, full cost method 150,726 85,443
Unevaluated oil and gas properties 14,682 12,431
Accumulated depreciation, depletion and amortization (64,379) (41,530)
------------ ------------
Oil and gas properties, net 101,029 56,344
------------ ------------
Plugging and abandonment escrow 1,034 495
Other assets, net of accumulated depreciation and amortization 1,187 1,953
of $2,144 and $558, respectively ------------ ------------
Total Assets $ 114,639 $ 83,072
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 19,749 $ 18,893
Advances from co-owners 2,044 7,297
Current portion of long-term debt 329 7,873
------------ ------------
Total current liabilities 22,122 34,063
Long-term debt 19,000 6,804
Debt subsequently refinanced 14,000 --
Deferred income taxes 4,690 --
Other liabilities 612 749
Commitments and contingencies -- --
Stockholders' equity:
Common stock, $.001 par value; authorized 75,000
shares; issued and outstanding 32,530 and 30,256
shares, respectively 33 30
Paid-in capital 64,083 62,290
Unearned deferred compensation (682) --
Accumulated deficit (9,219) (20,864)
------------ ------------
Total stockholders' equity 54,215 41,456
------------ ------------
Total liabilities and stockholders' equity $ 114,639 $ 83,072
============ ============
See accompanying Notes to Consolidated Financial Statements.
F-3
PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
Revenues:
Oil and gas sales $54,967 $ 22,267 $ 8,516
Interest and other income 314 294 170
------- -------- --------
55,281 22,561 8,686
------- -------- --------
Expenses:
Lease operating expenses 7,172 2,831 2,638
Production taxes 1,096 944 406
Depreciation, depletion and amortization 23,094 6,386 4,472
General and administrative 4,752 3,248 1,625
Interest expense 2,111 78 --
Other -- -- (145)
------- -------- --------
38,225 13,487 8,996
------- -------- --------
Income (loss) from operations 17,056 9,074 (310)
Income tax expense (benefit) 5,411 (850) --
------- -------- --------
Net income (loss) $11,645 $ 9,924 $ (310)
======= ======== ========
Earnings (loss) per common share:
Basic $ 0.37 $ 0.37 $ (0.01)
======= ======== ========
Diluted $ 0.34 $ 0.35 $ (0.01)
======= ======== ========
Weighted average number of common shares:
Basic 31,818 26,919 21,528
Diluted 34,271 28,249 21,528
See accompanying Notes to Consolidated Financial Statements.
F-4
PETROQUEST ENERGY, INC.
Consolidated Statements of Stockholders' Equity
(Amounts in Thousands, Except Share Data)
Unearned Other Total
Common Paid-In Deferred Comprehensive Retained Stockholders'
Stock Capital Compensation Income Deficit Equity
----- ------- ------------ ------ ------- ------
December 31, 1998 $ 19 $ 43,795 $ -- $ -- $(30,478) $ 13,336
Options Exercised -- 76 -- -- -- 76
Stock based employee compensation -- 118 -- -- -- 118
(78,375 shares)
Stock issued for oil and gas properties -- 413 -- -- -- 413
Sale of common stock and warrants 5 4,467 -- -- -- 4,472
Net loss -- -- -- -- (310) (310)
------ -------- ------------ ------------ -------- -------------
December 31, 1999 $ 24 $ 48,869 $ -- $ -- $(30,788) $ 18,105
------ -------- ------------ ------------ -------- -------------
Options and warrants exercised 1 1,586 -- -- -- 1,587
Stock based employee compensation -- 555 -- -- -- 555
(221,500 shares)
Sale of common stock 5 11,280 -- -- -- 11,285
Net income -- -- -- $ -- 9,924 9,924
------ -------- ------------ ------------ -------- -------------
December 31, 2000 $ 30 $ 62,290 -- -- $(20,864) $ 41,456
------ -------- ------------ ------------ -------- -------------
Options and warrants exercised 3 1,510 (1,034) -- -- 479
Amortization of deferred compensation -- 413 352 -- -- 765
Tax effect of deferred compensation -- (130) -- -- -- (130)
Cumulative effect of change in accounting
principle, net of taxes -- -- -- (383) -- (383)
Amortization of derivative fair value adjustment -- -- -- 383 -- 383
Net income -- -- -- -- 11,645 11,645
------ -------- ------------ ------------ -------- -------------
December 31, 2001 $ 33 $ 64,083 $ (682) $ -- $ (9,219) $ 54,215
------ -------- ------------ ------------ -------- -------------
See accompanying Notes to Consolidated Financial Statements.
F-5
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(Amounts in Thousands)
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
Cash flows from operating activities:
Net income (loss) $ 11,645 $ 9,924 $ (310)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities:
Deferred tax expense (benefit) 5,411 (850) --
Amortization of debt issuance costs 1,369 -- --
Compensation expense 765 555 118
Depreciation, depletion and amortization 23,094 6,386 4,472
Other 61 -- --
Plugging and abandonment costs (28) (89) --
Changes in working capital accounts:
Accounts receivable (434) (2,811) (1,321)
Joint interest billing receivable 5,542 (7,961) (2,190)
Accounts payable and accrued liabilities (61) 15,870 885
Other assets (1,011) (1,744) --
Advances from co-owners (5,253) 4,140 3,157
Provision for revenue dispute -- -- (145)
Plugging and abandonment escrow (539) (240) 34
Other 308 (345) (299)
-------- -------- --------
Net cash provided by operating activities 40,869 22,835 4,401
-------- -------- --------
Cash flows from investing activities:
Investment in oil and gas properties (66,678) (40,972) (10,062)
Sale of Canadian properties -- -- 1,868
Net cash used in investing activities (66,678) (40,972) (8,194)
-------- -------- --------
Cash flows from financing activities:
Exercise of options and warrants 671 1,587 76
Proceeds from borrowing 28,000 22,620 8,220
Repayment of debt (9,348) (12,812) (7,050)
Issuance of common stock -- 11,285 4,472
-------- -------- --------
Net cash provided by financing activities 19,323 22,680 5,718
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (6,486) 4,543 1,925
Cash and cash equivalents balance beginning of period 7,549 3,006 1,081
-------- -------- --------
Cash and cash equivalents balance end of period $ 1,063 $ 7,549 $ 3,006
======== ======== ========
Supplentmental disclosure of cash flow information
Cash paid during the period from:
Interest $ 1,464 $ 409 $ 233
======== ======== ========
Income taxes $ -- $ -- $ --
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
F-6
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-7
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, 2001, 2000 and 1999
were not significant.
Certain Concentrations
During 2001, 66% of the Company's oil and gas production was sold to four
customers. During 2000 and 1999, 84% and 44%, respectively, 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, 2001 and 2000 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. At January 1, 2001,
the
F-8
Company recognized a liability of $609,295 related to costless collars; the
cumulative catch-up adjustment was recorded as a charge to other comprehensive
income. These collars were designated as cash flow hedges.
We recognized $1,630,000 in oil and gas revenues during the year ended
December 31, 2001 as a result of the settlement of costless collars. We had no
open commodity hedging contracts at December 31, 2001.
During the fourth quarter, we entered into three $5 million interest rate
swaps covering our floating rate debt. The swaps which are for one, two and
three year periods have fixed interest rates of 2.78%, 2.78%-4.56% and
3.05%-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, 2001, the fair value of the open interest rate swaps was a
liability of $61,000.
New Accounting Standards
In July 2001, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations," which requires recording the fair value of a liability for an
asset retirement obligation in the period incurred. The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
permitted. The Company expects to adopt this standard effective January 1, 2003.
We have not completed an evaluation of the impact of this new standard.
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. For purposes of computing
earnings per share in a loss year, common stock equivalents have been excluded
from the computation of weighted average common shares outstanding because their
effect is antidilutive.
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. For 1999, none of the Company's options and warrants were
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. 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.
NOTE 3 - EQUITY
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.
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,
F-9
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 also recognized $352,000 of non-cash compensation expense related
to the amortization of unearned deferred compensation. In addition, as a result
of extending the life of two directions' options, we recognized $413,000 of
non-cash compensation expense during the fourth quarter
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.
NOTE 4 - DEBT
PetroQuest and our subsidiary PetroQuest Energy, L.L.C. (the "Borrower") have a
$100 million revolving credit facility with Hibernia National Bank, Royal Bank
of Canada and Union Bank of California, N.A. 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 March 1, 2002, the borrowing base under the credit
facility was adjusted to $28 million and is subject to quarterly reductions of
$3 million commencing on April 30, 2002. As of December 31, 2001, $19 million
outstanding under the credit facility is classified as long term reflecting the
remaining borrowing base at December 31, 2002. Based upon this determination,
the remaining balance outstanding under the credit facility of $14 million has
been classified as debt subsequently refinanced as a result of the public
offering in February 2002.
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
March 7, 2002, we had $5 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 March 7, 2002. The credit
facility matures on June 30, 2004.
On April 21, 1999, the Company entered into a loan agreement for
non-recourse financing to fund completion, flow line and facility costs of its
High Island Block 494 property. The property is security for the loan. Interest
is payable at 12% and the lender receives a 2 1/2% overriding royalty interest
in the property. The loan agreement requires 85% of the net cash flow from the
property (assuming production levels of 12.5 MMcf/day) to be dedicated to debt
service. At December 31, 2001, $329,000 remained outstanding under this loan,
and the Company estimates the loan will be paid in 2002.
NOTE 5 - RELATED PARTY TRANSACTIONS
Certain officers and directors and their affiliates are working interest
owners in properties operated by the Company and are billed for and pay their
proportionate share of drilling and operating costs in the normal course of
business.
During 2000 and 1999, the Company was charged consulting expenses of
$10,000 and $143,462, respectively, by companies owned by former directors.
Office expense includes $1,662 and $18,500 for 2000 and 1999, respectively, paid
to a company owned by a former director.
F-10
During 2001, 2000 and 1999 the Company paid fees and reimbursable expenses
of $526,000, $208,789 and $139,001, respectively to Onebane, Bernard, Torian,
Diaz, McNamara & Abell to perform various legal services for the Company. A
senior officer of the Company was of counsel with Onebane, Bernard, Torian,
Diaz, McNamara & Abell prior to joining the Company during 2001.
NOTE 6 - COMMON STOCK AND WARRANTS
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 a private placement during the fourth quarter of 1999, the Company
issued 238,500 shares of common stock (with a fair market value $413,000) in
exchange for additional working interests in producing properties. The effective
date of these acquisitions was June 1, 1999. The net operating income of $89,000
attributable to these interests during the period from the effective date to the
closing date was recorded as an adjustment to the purchase price of the
properties.
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. Net proceeds of $4,508,000 from sale of
the units were allocated between the stock and warrants based on their relative
fair market value on the date of the transaction. 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. In addition, the Company issued to the placement agents
of the units, warrants to purchase 500,000 shares of the Company's common stock.
The warrants received by the placement agents are exercisable at any time for a
period of five years to purchase one share of the Company's common stock at a
per share purchase price of $1.25 per share. At December 31, 2001, there were
1,690,000 warrants outstanding.
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)
For the Year-Ended December 31,
-------------------------------
2001 2000 1999
------- ------- -------
Acquisition costs:
Proved $11,928 $ 6,154 $ 546
Unproved 1,250 4,670 954
Exploration costs 7,280 9,625 8,477
Development costs 43,424 18,000 1,170
Other costs 3,652 2,523 1,795
------- ------- -------
Total costs incurred $67,534 $40,972 $12,942
======= ======= =======
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. Other costs for the year ended December 31, 1999
include $1,361,000 and $434,000 of capitalized general and administrative costs
and interest costs respectively.
At December 31, 2001 and 2000, unevaluated oil and gas properties with
capitalized costs of $14,682,000 and $12,431,000 respectively, were not subject
to depletion. Of the $14,682,000 of unevaluated oil and gas property costs at
F-11
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):
December 31,
------------
2001 2000
---- ----
Net operating loss carryforwards $ 12,205 $ 9,284
Percentage depletion carryforward 1,161 441
Alternative minimum tax credit 16 29
Deferred Compensation (130) --
Temporary differences:
Oil and gas properties - full cost (18,096) (8,904)
Compensation expense 153 --
-------- -------
$ (4,691) $ 850
======== =======
For tax reporting purposes, the Company had operating loss carryforwards
of $32,986,000 and $26,525,000 at December 31, 2001 and 2000 respectively. If
not utilized, such carryforwards would begin expiring in 2009 and would
completely expire by the year 2021. The Company had available for tax reporting
purposes $3,318,000 in statutory depletion deductions that may be carried
forward indefinitely.
Income tax expense (benefit) for each of the years ended December 31,
2001, 2000 and 1999 (amounts in thousands) was different than the amount
computed using the Federal statutory rate (35%) for the following reasons:
For the Year-Ended December 31,
-------------------------------
2001 2000 1999
---- ---- ----
Amount computed using the statutory rate $ 5,970 $ 3,176 $(109)
Increase (reduction) in taxes resulting from:
State & local taxes 341 120 (5)
Percentage depletion carryforward (720) -- --
Other (180) -- --
Increase (decrease) in deferred tax asset
valuation allowance -- (4,146) 114
------- ------- -----
Income tax expense (benefit) $ 5,411 $ (850) $ --
======= ======= =====
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.
F-12
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.
PetroQuest Energy, Inc. and PetroQuest Energy One, L.L.C. v. Schlumberger
Technology Corporation, et al, bearing Civil Action No. 00-2823 of the United
States District Court, Western District of Louisiana was filed on December 29,
2000. This matter is a lawsuit filed by the Company's subsidiaries, PetroQuest
Energy, Inc., a Louisiana corporation, and PetroQuest Energy One, L.L.C. (now
PetroQuest Energy, L.L.C.) seeking to recover cost overruns in the amount of
approximately $2,850,000 which were incurred in the completion of theOCSG-15243
#2 Well located at Eugene Island Block 147. The Company asserts that cost
overruns were incurred due to the negligence of Schlumberger Technology
Corporation. On May 17, 2001, Schlumberger Technology Corporation filed a
counter-claim for $437,200, plus interest, attorney's fees and costs for goods
and services allegedly provided in connection with the OCSG-15243 #2 Well. 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. The Company maintains abandonment escrows that
have been established for future abandonment obligations of certain oil and gas
properties of the Company. The management of the Company believes the escrows
will be sufficient to offset those future abandonment liabilities; however, the
Company is responsible for any abandonment expenses in excess of the escrow
balances. As of December 31, 2001 and 2000, total estimated site restoration,
dismantlement and abandonment costs were approximately $14,056,000 and
$12,439,000 respectively, net of expected salvage value.
F-13
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, 2001 under these
operating leases are as follows (in thousands):
2002 ................................................. $ 569
2003 ................................................. 644
2004 ................................................. 650
2005 ................................................. 667
2006 ................................................. 599
Thereafter ................................................. 1,898
------
$5,027
======
Total rent expense under operating leases was approximately $411,000,
$345,000 and $193,000 in 2001, 2000 and 1999, 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, 2001, 2000 and
1999 and changes during the years ended on those dates is presented below:
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
Number of Wgtd. Avg. Number of Wgtd. Avg. Number of Wgtd. Avg.
--------- ---------- --------- ---------- --------- ----------
Options Price Options Price Options Price
------- ----- ------- ----- ------- -----
Outstanding at beginning of year 1,861,900 $ 1.92 1,126,200 $ 0.95 1,052,700 $ 0.85
Granted 622,500 5.32 1,027,500 2.67 188,000 1.42
Expired/cancelled/forfeitures (14,500) 6.17 (24,866) 1.04 (25,500) 0.85
Exercised (231,134) 0.89 (266,934) 0.85 (89,000) 0.85
---------- ---------- ---------- ---------- ---------- ----------
Outstanding at end of year 2,238,766 2.94 1,861,900 1.92 1,126,200 0.95
Options exercisable at year-end 1,030,608 1.64 800,733 0.97 897,433 0.93
Options available for future grant 268,081 182,166 584,800
Weighted average fair value of
options granted during the year $ 3.18 $ 1.99 $ 0.47
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 65.14% - 67.87%, 56.99% - 59.88%, and 55.02% - 61.23% in 2001, 2000
and 1999, respectively (c) risk-free interest rate ranges of 4.03% - 5.10%,
5.39% - 6.96% and 5.31% - 6.33% in 2001, 2000 and 1999, respectively, and (d)
expected life of 5 years for all 2001 grants and 10 years for all 2000 and 1999
grants.
F-14
The following table summarizes information regarding stock options
outstanding at December 31, 2001:
Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Price At 12/31/01 Contractual Life Price At 12/31/01 Price
----- ----------- ---------------- ----- ----------- -----
$0.85 - $0.94 458,600 7 years $0.89 458,600 $0.89
$1.44 - $1.88 491,333 8.68 years $1.67 347,333 $1.66
$3.13 - $3.75 740,833 9.08 years $3.20 224,675 $3.15
$4.25 - $7.65 548,000 10 years $5.47 -- --
----------- -----------
2,238,766 8.79 years $2.94 1,030,608 $1.64
If the compensation cost for the Company's 2001, 2000 and 1999 grants for
stock-based compensation plans had been determined consistent with the expense
recognition provisions of SFAS No. 123, the Company's 2001, 2000 and 1999 net
income and basic and diluted earnings per common share would have approximated
the pro forma amounts below (in thousands, except per share amounts):
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
As Pro As Pro As Pro
Reported Forma Reported Forma Reported Forma
-------- ----- -------- ----- -------- -----
Net income (loss) $ 11,645 $ 10,882 $ 9,924 $ 9,112 $ (310) $ (978)
Earnings (loss) per common share
Basic $ 0.37 $ 0.34 $ 0.37 $ 0.34 $ (0.01) $ (0.05)
Diluted $ 0.34 $ 0.32 $ 0.35 $ 0.32 $ (0.01) $ (0.05)
NOTE 11 - SUBSEQUENT EVENT
On March 1, 2002, the Company closed the sale of its interest in Valentine
Field for $18.6 million. The transaction had an effective date of January 1,
2002. At December 31, 2001, the Company's independent reservoir engineering firm
attributed 7.3 Bcfe of proved reserves net to the Company's interest in this
field.
NOTE 12 - OIL AND GAS RESERVE INFORMATION - UNAUDITED
A majority of the Company's net proved oil and gas reserves at December
31, 2001 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-15
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:
Oil Natural
In Gas in
MBbls MMcf
----- ----
Proved reserves as of December 31, 1998 504 10,561
Revisions of previous estimates 199 128
Extensions, discoveries and other additions 1,596 7,257
Purchase of producing properties -- 13
Production (105) (2,831)
------ -------
Proved reserves as of December 31, 1999 2,194 15,128
Revisions of previous estimates (760) 6,638
Extensions, discoveries and other additions 110 3,476
Purchase of producing properties 1,732 8,865
Production (161) (3,972)
------ -------
Proved reserves as of December 31, 2000 3,115 30,135
Revisions of previous estimates (522) (2,631)
Extensions, discoveries and other additions 3,805 14,409
Purchase of producing properties 606 12,170
Sale of producing properties -- (114)
Production (791) (9,025)
------ -------
Proved reserves as of December 31, 2001 6,213 44,944
------ -------
Proved developed reserves
As of December 31, 1999 400 6,456
====== =======
As of December 31, 2000 2,355 18,679
====== =======
As of December 31, 2001 3,104 26,847
====== =======
F-16
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. No future income taxes
were included in the computation of standardized measure in 1999 and 1998
because the Company's tax basis in oil and gas properties, along with its other
tax preference attributes, net, exceeded pretax estimated discounted future net
cash flows. Estimated future cash flows have been discounted to their present
values based on a 10% annual discount rate.
STANDARD MEASURE December 31,
------------
2001 2000 1999
---- ---- ----
Future cash flows $ 234,736 $ 391,078 $ 92,788
Future production and development costs (118,700) (66,095) (33,732)
Future income taxes (18,226) (98,190) --
--------- --------- --------
Future net cash flows 97,810 226,793 59,056
10% annual discount (22,763) (48,470) (15,987)
--------- --------- --------
Standardized measure of discounted future net cash flows $ 75,047 $ 178,323 $ 43,069
========= ========= ========
CHANGES IN STANDARDIZED MEASURE Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
Standarized measure at beginning of year $ 178,323 $ 43,069 $ 11,676
Sales and transfers of oil and gas produced,
net of production costs (45,068) (18,492) (5,472)
Changes in price, net of future production costs (188,513) 104,695 7,691
Extensions and discoveries, net of future
production and development costs 33,067 27,575 25,974
Changes in estimated future development costs,
net of development costs incurred during this period 16,333 2,801 1,013
Revisions of quantity estimates (7,742) 12,818 2,547
Accretion of discount 25,687 4,307 1,168
Net change in income taxes 65,361 (78,544) --
Purchase of reserves in place 12,730 67,052 179
Sale of reserves in place (864) -- --
Changes in production rates (timing) and other (14,267) 13,042 (1,707)
--------- --------- --------
Standardized measure at end of year $ 75,047 $ 178,323 $ 43,069
========= ========= ========
The weighted average prices of oil and gas used with the above tables at
December 31, 2001, 2000 and 1999 were $18.49, $25.29 and $25.21 respectively,
per barrel and $2.69, $10.35 and $2.48, respectively, per Mcf.
F-17
NOTE 13 - SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED
Summarized quarterly financial information is as follows (amounts in
thousands except per share data):
Quarter Ended
-------------
March-31 June-30 September-30 December-31
-------- ------- ------------ -----------
2001:
Revenues $ 12,553 $ 14,888 $ 15,468 $ 12,372
Expenses 8,412 11,034 12,960 11,230
------------ ------------ ------------ ------------
Net income (1) 4,141 3,854 2,508 1,142
============ ============ ============ ============
Earnings per share: (2)
Basic $ 0.14 $ 0.12 $ 0.08 $ 0.04
Diluted $ 0.13 $ 0.11 $ 0.07 $ 0.03
2000:
Revenues $ 3,151 $ 3,859 $ 6,132 $ 9,419
Expenses 2,521 2,823 3,113 4,180
------------ ------------ ------------ ------------
Net income 630 1,036 3,019 5,239
============ ============ ============ ============
Earnings per share: (2)
Basic $ 0.03 $ 0.04 $ 0.10 $ 0.17
Diluted $ 0.02 $ 0.04 $ 0.10 $ 0.17
- ----------
(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-18
INDEX TO 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 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 July 27, 2001).
4.1 Registration Rights Agreement dated as of September 1, 1998
among Optima Petroleum Corporation, Charles T. Goodson,
Alfred J. Thomas, II, Ralph J. Daigle, Janell B. Thomas,
Alfred J. Thomas, III, Blaine A. Thomas, and Natalie A.
Thomas (incorporated herein by reference to Exhibit 99.1 to
Form 8-K dated September 16, 1998).
4.2 Form of Certificate of Contingent Stock Issue Right
(incorporated herein by reference to Exhibit 4.3 to Form 8-K
dated September 16, 1998).
4.3 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)
4.4 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)
4.5 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 July 27, 2001).
4.6 Form of Rights Certificate (incorporated herein by reference
to Exhibit C of the Rights Agreement attached as Exhibit 1 to
Form 8-A filed July 27, 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).
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.
10.11 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).
10.12 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 Ralph J. Daigle (incorporated
herein by reference to Exhibit 10.4 to Form 8-K dated
September 16, 1998).
10.14 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)
10.15 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).
10.16 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).
10.17 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).
10.18 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).
10.19 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).
* 10.20 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 and Daniel G. Fournerat.
* 10.21 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 and Arthur
M. Mixon, III.
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 Public Accountant.
- ----------
* Filed herewith.