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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2003
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number: 019020
PETROQUEST ENERGY, INC.
(Exact name of registrant as specified in its charter)
State of incorporation: Delaware I.R.S. Employer Identification No.
72-1440714
400 E. Kaliste Saloom Road, Suite 6000
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (337) 232-7028
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12 (g) of the Act:
Common Stock, Par Value $.001 Per Share
Preferred Stock Purchase Rights
(Title of Class)
Indicate by check mark whether the registrant: (1) has filed all
reports required to be filed by Section 13 or 15 (d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
[ X ] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Exchange Act Rule 12b-2).
[ X ] Yes [ ] No
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $76,544,656 as of June 30, 2003 (based on
the last reported sale price of such stock on The Nasdaq National Market
System).
As of March 5, 2004, the registrant had outstanding 44,555,693 shares
of Common Stock, par value $.001 per share.
Document incorporated by reference: Proxy Statement of PetroQuest
Energy, Inc. relating to the Annual Meeting of Stockholders to be held on May
12, 2004, which is incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
Page No.
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PART I
Item 1. Business................................................................................................ 1
Item 2. Properties.............................................................................................. 17
Item 3. Legal Proceedings....................................................................................... 19
Item 4. Submission of Matters to a Vote of Security............................................................. 19
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.......................................................................... 19
Item 6. Selected Financial Data................................................................................. 20
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 20
Item 7A. Quantitative and Qualitative Disclosure About Market Risks.............................................. 28
Item 8. Financial Statements and Supplementary Data ............................................................ 29
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.................... 29
Item 9A. Controls and Procedures................................................................................. 29
PART III
Item 10. Directors and Executive Officers of the Registrant...................................................... 30
Item 11. Executive Compensation.................................................................................. 30
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.......... 30
Item 13. Certain Relationships and Related Transactions.......................................................... 30
Item 14. Principal Accountant Fees and Services.................................................................. 30
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................................ 30
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 assure you that such expectations reflected in these
forward looking statements will prove to have been correct.
When used in this Form 10-K, the words "expect," "anticipate,"
"intend," "plan," "believe," "seek," "estimate" and similar expressions are
intended to identify forward-looking statements, although not all
forward-looking statements contain these identifying words. Because these
forward-looking statements involve risks and uncertainties, actual results could
differ materially from those expressed or implied by these forward-looking
statements for a number of important reasons, including those discussed under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Risk Factors" and elsewhere in this Form 10-K.
You should read these statements carefully because they discuss our
expectations about our future performance, contain projections of our future
operating results or our future financial condition, or state other
"forward-looking" information. Before you invest in our common stock, you should
be aware that the occurrence of any of the events described under "Management's
Discussion and Analysis of Financial Condition and Results of Operations," "Risk
Factors" elsewhere in this Form 10-K could substantially harm our business,
results of operations and financial condition and that upon the occurrence of
any of these events, the trading price of our common stock could decline, and
you could lose all or part of your investment.
We cannot guarantee any future results, levels of activity, performance
or achievements. Except as required by law, we undertake no obligation to update
any of the forward-looking statements in this Form 10-K after the date of this
Form 10-K.
As used in this Form 10-K, the words "we", "our", "us", "PetroQuest"
and the "Company" refer to PetroQuest Energy, Inc., its predecessors and
subsidiaries, except as otherwise specified.
PART I
ITEM 1. BUSINESS
OVERVIEW
PetroQuest Energy, Inc. 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 Basin and East Texas area. Our business strategy is
to increase production, cash flow and reserves through generation, exploration,
development and acquisition of properties located in the Gulf Coast Region, as
well as finding additional opportunities in areas with longer reserve lives.
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
We have provided definitions for some of the oil and natural gas
industry terms used in this Form 10-K in "Glossary of Oil and Natural Gas Terms"
on page 34.
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OUR STRATEGY
Our business strategy is to build shareholder value by increasing per
share reserves, production, cash flow and earnings at low finding and
development costs through the exploration and development of properties located
in the Gulf Coast Basin, either onshore or in shallow waters offshore, and the
East Texas area. We plan to achieve this goal by continuing to:
- Focus on the Gulf Coast Basin. We have assembled a large acreage
position and 3-D seismic database in the Gulf Coast Basin because we
believe this area represents one of the most attractive exploration and
development regions in North America. We also believe our management
and technical team's expertise and experience developed over
approximately the last 25 years will allow us to develop attractive
reinvestment opportunities that will permit continuing growth.
- Diversify our reserve base and technical expertise. We have acquired a
significant leasehold position in a producing portion of the Southeast
Carthage Field in the East Texas area. In addition, we have added
appropriate personnel to our technical team to evaluate and exploit
this area. The East Texas acquisition strengthens our asset base by
adding reserves that have a longer life than our Gulf Coast reserves.
- Target under-exploited fields that have low current production levels.
Using a rigorous prospect selection process that enables us to leverage
our experience and knowledge of the Gulf Coast Basin, we target
properties with an established production history and existing
infrastructure. These fields have often produced from only shallower
sands and contain multiple productive horizons that were not targeted
during their initial phase of development. By targeting properties with
limited current production, our acquisition costs are typically only a
small portion of the total capital we will employ over the life of the
project.
- Emphasize and apply technical expertise. By applying the latest 3-D and
other geoscience technologies to under-exploited properties, we believe
we can identify opportunities to significantly increase reserves and
production from these properties.
- Operate properties and balance risk. By operating the majority of our
properties, we can better control the timing and execution of our
exploration and development plans. We also balance the risk and reward
potential of our prospects by determining our desired working interest
and selling the remainder to industry partners on terms where they
often agree to pay a disproportionate share of drilling costs relative
to their interests. Our management team has developed many successful
relationships with major, integrated and large independent producers.
We believe these relationships allow us to allocate our capital
spending in a way that maximizes return while reducing the inherent
risk of exploration activities.
- Maintain our financial flexibility. We seek to maintain unused
borrowing capacity under our bank credit facility and sub-debt facility
in order to take advantage of new opportunities. We also evaluate
potential property acquisitions and dispositions, and routinely discuss
those opportunities with third parties. While dispositions of producing
properties reduce current revenues, sales of properties can provide
additional capital for exploration and development of properties that
are more important to our long-term growth.
EXPLORATION AND DEVELOPMENT
We are engaged in the exploration, development, acquisition and
operation of oil and gas properties onshore and offshore in the Gulf Coast
Region, as well as the East Texas area. As of December 31, 2003, our estimated
proved reserves totaled 4,245 MBbl of oil and 57,793 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
$214,365,000. Approximately 67% of our reserves are proved developed reserves.
We operate 10 fields representing approximately 75% of the total discounted cash
flow attributable to estimated proved reserves.
SIGNIFICANT PROPERTIES
SHIP SHOAL 72, FEDERAL OUTER CONTINENTAL SHELF WATERS. We retained a
100% working interest position in all wells drilled in this field prior to 2003.
During 2003, we sold working interests in three wells to industry partners.
During 2003, we drilled and completed three wells, and the field produced
approximately 4.8 Bcfe net to us from twelve producing wells.
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Additional developmental opportunities and exploration potential in deeper
horizons have been identified and are currently being evaluated for future
drilling. Current plans call for one additional developmental well and one
exploratory well to be drilled during 2004. We may continue to seek to obtain
industry partners in the future development of this property. Reprocessed 3-D
data is currently being reviewed for additional opportunities.
SE CARTHAGE FIELD, PANOLA COUNTY, TX. During December 2003, we acquired
a working interest in approximately 41,000 acres in this field, which had
approximately 80 producing wells and produced approximately 5,500 Mcfe per day,
net to us upon acquisition. Current plans call for seven developmental wells to
be drilled during 2004.
MAIN PASS 74, LOUISIANA STATE WATERS. We and our partners drilled a
well on this property during the fourth quarter of 2003 and logged approximately
71 feet of net productive sands. The well began producing during 2003 at an
initial gross rate of approximately 9,000 Mcfe per day. Current plans call for
one additional developmental well to be drilled during the first quarter of
2004.
TURTLE BAYOU FIELD, TERREBONNE PARISH, LA. As of December 31, 2003,
there are three producing wells in the field in which we hold a working
interest. Collectively, the three producing wells averaged approximately 2,800
Mcf of natural gas and 90 barrels of oil per day, net to us, for the year ended
December 31, 2003. Our working interest varies between 14% and 43% with a
weighted average working interest of approximately 34%. As a result of
reprocessing a 3-D regional seismic set shot in 1998, we have identified an
additional prospect. Current plans call for us to drill an exploratory well
during 2004.
VERMILION BLOCK 376, FEDERAL OUTER CONTINENTAL SHELF WATERS ("FALCON
PROSPECT"). We and our 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). We are the operator of the project and own
a 43% working interest. During 2000, an approximately 2,500 ton production
platform was fabricated and placed in service. During 2003, the field produced
at an average rate of approximately 420 Bbls per day of oil and 1,100 Mcf per
day of natural gas, net to us.
BERRY LAKE FIELD, IBERVILLE PARISH, LA. We and our partners drilled a
well on this property in the third quarter of 2002 and logged approximately 71
feet of net productive sands. During 2003, the well produced at an average rate
of approximately 330 Bbls per day of oil and 500 Mcf per day of natural gas, net
to us.
MARKETS AND CUSTOMERS
We sell our natural gas and oil production under fixed or floating
market contracts. Customers purchase all of our natural gas and oil production
at current market prices. The terms of the arrangement generally require
customers to pay us within 30 days after the production month ends. As a result,
if the customers were to default on their payment obligations to us, near-term
earnings and cash flows would be adversely affected. However, due to the
availability of other markets and pipeline connections, we do not believe that
the loss of these customers or any other single customer would adversely affect
our ability to market production. Our ability to market oil and gas from our
wells depends upon numerous factors beyond our control, including:
- the extent of domestic production and imports of oil and gas,
- the proximity of the gas production to gas pipelines,
- the availability of capacity in such pipelines,
- the demand for oil and gas by utilities and other end users,
- the availability of alternative fuel sources,
- the effects of inclement weather,
- state and federal regulation of oil and gas production, and
- federal regulation of gas sold or transported in interstate
commerce.
3
No assurance can be given that we will be able to market all of the oil
or gas we produce or that favorable prices can be obtained for the oil and gas
we produce.
In view of the many uncertainties affecting the supply and demand for
oil, gas and refined petroleum products, we are unable to predict future oil and
gas prices and demand or the overall effect such prices and demand will have on
the Company. For the year ended December 31, 2003, we had five customers who
accounted for 22%, 18%, 18%, 14% and 12% of total revenues, respectively. For
the year ended December 31, 2002, we had three customers who accounted for 25%,
22% and 19% of total revenues, respectively. For the year ended December 31,
2001, we had four customers who accounted for 19%, 19%, 15% and 13% of total
revenues, respectively. These percentages do not consider the effects of
financial hedges. We do not believe that the loss of any of our oil or gas
purchasers would have a material adverse effect on our operations due to the
availability of other purchasers.
FEDERAL REGULATIONS
SALES AND TRANSPORTATION OF NATURAL GAS. Historically, the
transportation and sales for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938 ("NGA"), the Natural Gas
Policy Act of 1978 ("NGPA") and Federal Energy Regulatory Commission ("FERC")
regulations. Effective January 1, 1993, the Natural Gas Wellhead Decontrol Act
deregulated the price for all "first sales" of natural gas. Thus, all of our
sales of gas may be made at market prices, subject to applicable contract
provisions. Sales of natural gas are affected by the availability, terms and
cost of pipeline transportation. Since 1985, the FERC has implemented
regulations intended to make natural gas transportation more accessible to gas
buyers and sellers on an open-access, non-discriminatory basis.
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
- 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. There have
been recent instances when FERC and the courts have disagreed as to the proper
tests to apply in determining whether certain natural gas gathering systems in
the
4
shallow waters of the OCS are subject to transportation lines subject to FERC
jurisdiction or exempt as gathering lines. In response to sometimes confusing
and conflicting decisions, FERC convened a public conference on September 23,
2003 to explore whether it should reformulate its tests for defining non
jurisdictional gathering in the shallow waters of the OCS. Costs to transport
gas from offshore leases to market is subject to FERC rules and tariffs while
non jurisdictional gathering lines may charge market rates.
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 us 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.
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. Our sales of crude oil,
condensate and natural gas liquids are not currently regulated, and are subject
to applicable contract provisions made at market prices. In a number of
instances, however, the ability to transport and sell such products is dependent
on pipelines whose rates, terms and conditions of service are subject to the
FERC's jurisdiction under the Interstate Commerce Act. In other instances, the
ability to transport and sell such products is dependent on pipelines whose
rates, terms and conditions of service are subject to regulation by state
regulatory bodies under state statutes.
The regulation of pipelines that transport crude oil, condensate and
natural gas liquids is generally more light-handed than the FERC's regulation of
gas pipelines under the NGA. Regulated pipelines that transport crude oil,
condensate, and natural gas liquids are subject to common carrier obligations
that generally ensure non-discriminatory access. With respect to interstate
pipeline transportation subject to regulation of the FERC under the Interstate
Commerce Act, rates generally must be cost-based, although market-based rates or
negotiated settlement rates are permitted in certain circumstances. Pursuant to
FERC Order No. 561, pipeline rates are subject to an indexing methodology. Under
this indexing methodology, pipeline rates are subject to changes in the Producer
Price Index for Finished Goods, minus one percent. A pipeline can seek to
increase its rates above index levels provided that the pipeline can establish
that there is a substantial divergence between the actual costs experienced by
the pipeline and the rate resulting from application of the index. A pipeline
can seek to charge market-based rates if it establishes that it lacks
significant market power. In addition, a pipeline can establish rates pursuant
to settlement if agreed upon by all current shippers. A pipeline can seek to
establish initial rates for new services through a cost-of-service proceeding, a
market-based rate proceeding, or through an agreement between the pipeline and
at least one shipper not affiliated with the pipeline. The FERC indicated in
Order No. 561 that it will assess in 2000 how the rate-indexing method is
operating. The FERC issued a Notice of Inquiry on July 27, 2000 seeking comment
on whether to retain or to change the existing index. After consideration of 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. We maintain operations located on federal oil and gas
leases, which are administered by the Minerals Management Service pursuant to
the Outer Continental Shelf Lands Act. These leases are issued through
competitive bidding
5
and contain relatively standardized terms. These leases require compliance with
detailed Minerals Management Service regulations and orders that are subject to
interpretation and change by the Minerals Management Service.
For offshore operations, lessees must obtain Minerals Management
Service approval for exploration, development and production plans prior to the
commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the Minerals
Management Service prior to the commencement of drilling. The Minerals
Management Service has promulgated regulations requiring offshore production
facilities located on the Outer Continental Shelf to meet stringent engineering
and construction specifications. The Minerals Management Service also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and oil
without prior authorization. Similarly, the Minerals Management Service has
promulgated other regulations governing the plugging and abandonment of wells
located offshore and the installation and removal of all production facilities.
To cover the various obligations of lessees on the Outer Continental
Shelf, the Minerals Management Service generally requires that lessees have
substantial net worth or post bonds or other acceptable assurances that such
obligations will be met. The cost of these bonds or assurances can be
substantial, and there is no assurance that they can be obtained in all cases.
Under some circumstances, the Minerals Management Service may require operations
on federal leases to be suspended or terminated.
The Minerals Management Service also administers the collection of
royalties under the terms of the Outer Continental Shelf Lands Act and the oil
and gas leases issued under the Act. The amount of royalties due is based upon
the terms of the oil and gas leases as well as of the regulations promulgated by
the Minerals Management Service. These regulations are amended from time to
time, and the amendments can affect the amount of royalties that we are
obligated to pay to the Minerals Management Service. However, we do not believe
that these regulations or any future amendments will affect us in a way that
materially differs from the way it affects other oil and gas producers, gathers
and marketers.
FEDERAL, STATE OR AMERICAN INDIAN LEASES. In the event we conduct
operations on federal, state or American Indian oil and gas leases, such
operations must comply with numerous regulatory restrictions, including various
nondiscrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other appropriate permits
issued by the Bureau of Land Management ("BLM") or Minerals Management Service
or other appropriate federal or state agencies.
The Mineral Leasing Act of 1920 ("Mineral Act") prohibits direct or
indirect ownership of any interest in federal onshore oil and gas leases by a
foreign citizen of a country that denies "similar or like privileges" to
citizens of the United States. Such restrictions on citizens of a
"non-reciprocal" country include ownership or holding or controlling stock in a
corporation that holds a federal onshore oil and gas lease. If this restriction
is violated, the corporation's lease can be cancelled in a proceeding instituted
by the United States Attorney General. Although the regulations of the BLM
(which administers the Mineral Act) provide for agency designations of
non-reciprocal countries, there are presently no such designations in effect. We
own interests in numerous federal onshore oil and gas leases. It is possible
that holders of our equity interests may be citizens of foreign countries, which
at some time in the future might be determined to be non-reciprocal under the
Mineral Act.
STATE REGULATIONS
Most states regulate the production and sale of oil and natural gas,
including:
- requirements for obtaining drilling permits;
- the method of developing new fields;
- the spacing and operation of wells;
- the prevention of waste of oil and gas resources; and
- the plugging and abandonment of wells.
The rate of production may be regulated and the maximum daily
production allowable from both oil and gas wells may be established on a market
demand or conservation basis or both.
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We may enter into agreements relating to the construction or operation
of a pipeline system for the transportation of natural gas. To the extent that
such gas is produced, transported and consumed wholly within one state, such
operations may, in certain instances, be subject to the jurisdiction of such
state's administrative authority charged with the responsibility of regulating
intrastate pipelines. In such event, the rates that we could charge for gas, the
transportation of gas, and the construction and operation of such pipeline would
be subject to the rules and regulations governing such matters, if any, of such
administrative authority.
LEGISLATIVE PROPOSALS
In the past, Congress has been very active in the area of natural gas
regulation. There are legislative proposals pending in the various state
legislatures which, if enacted, could significantly affect the petroleum
industry. At the present time it is impossible to predict what proposals, if
any, might actually be enacted by Congress or the various state legislatures and
what effect, if any, such proposals might have on our operations.
ENVIRONMENTAL REGULATIONS
GENERAL. Our activities are subject to existing federal, state and
local laws and regulations governing environmental quality and pollution
control. Although no assurances can be made, we believe that, absent the
occurrence of an extraordinary event, compliance with existing federal, state
and local laws, regulations and rules regulating the release of materials in the
environment or otherwise relating to the protection of the environment will not
have a material effect upon our capital expenditures, earnings or competitive
position with respect to our existing assets and operations. We cannot predict
what effect additional regulation or legislation, enforcement policies
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from our operations could have on our activities.
Our activities with respect to 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 we believe that
compliance with environmental regulations will not have a material adverse
effect on us, risks of substantial costs and liabilities are inherent in oil and
gas production operations, and there can be no assurance that significant costs
and liabilities will not be incurred. Moreover it is possible that other
developments, such as stricter environmental laws and regulations, and claims
for damages to property or persons resulting from oil and gas production, would
result in substantial costs and liabilities to us.
SOLID AND HAZARDOUS WASTE. We own or lease numerous properties that
have been used for production of oil and gas for many years. Although we have
utilized operating and disposal practices standard in the industry at the time,
hydrocarbons or other solid wastes may have been disposed or released on or
under these properties. In addition, many of these properties have been operated
by third parties. We had no control over such entities' treatment of
hydrocarbons or other solid wastes and the manner in which such substances may
have been disposed or released. State and federal laws applicable to oil and gas
wastes and properties have gradually become stricter over time. Under these
laws, we could be required to remove or remediate previously disposed wastes
(including wastes disposed or released by prior owners or operators) or property
contamination (including groundwater contamination by prior owners or operators)
or to perform remedial plugging operations to prevent future contamination.
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We generate wastes, including hazardous wastes, that are subject to the
federal Resource Conservation and Recovery Act ("RCRA") and comparable state
statutes. The EPA has limited the disposal options for certain hazardous wastes.
Furthermore, it is possible that certain wastes currently exempt from regulation
as "hazardous wastes" generated by our oil and gas operations may in the future
be designated as "hazardous wastes" under RCRA or other applicable statutes, and
therefore be subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
persons with respect to the release or threatened release of a "hazardous
substance" into the environment. These persons include the owner and operator of
a site and persons that disposed or arranged for the disposal of the hazardous
substances 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 we nor our 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. We believe we currently have established adequate financial
responsibility. While financial responsibility requirements under OPA may be
amended to impose additional costs on us, the impact of any change in these
requirements should not be any more burdensome to us than to others similarly
situated.
CLEAN WATER ACT. The Clean Water Act ("CWA") regulates the discharge of
pollutants to waters of the United States, including wetlands, and requires a
permit for the discharge of pollutants, including petroleum, to such waters.
Certain facilities that store or otherwise handle oil are required to prepare
and implement Spill Prevention, Control and Countermeasure Plans and Facility
Response Plans relating to the possible discharge of oil to surface waters. We
are required to prepare and comply with such plans and to obtain and comply with
discharge permits. We believe we are in substantial compliance with these
requirements and that any noncompliance would not have a material adverse effect
on us. The CWA also prohibits spills of oil and hazardous substances to waters
of the United States in excess of levels set by regulations and imposes
liability in the event of a spill. State laws further provide civil and criminal
penalties and liabilities for spills to both surface and groundwaters and
require permits that set limits on discharges to such waters.
AIR EMISSIONS. Our operations are subject to local, state and federal
regulations for the control of emissions from sources of air pollution.
Administrative enforcement actions for failure to comply strictly with air
regulations or permits may be resolved by payment of monetary fines and
correction of any identified deficiencies. Alternatively, regulatory agencies
could impose civil and criminal liability for non-compliance. An agency could
require us to forego construction or operation of certain air emission sources.
We believe that we are in substantial compliance with air pollution control
requirements and that, if a particular permit application were denied, we would
have enough permitted or permittable capacity to continue our operations without
a material adverse effect on any particular producing field.
COASTAL COORDINATION. There are various federal and state programs that
regulate the conservation and development of coastal resources. The federal
Coastal Zone Management Act ("CZMA") was passed to preserve and, where possible,
restore the natural resources of the Nation's coastal zone. The CZMA provides
for federal grants for state management programs that regulate land use, water
use and coastal development.
8
The Louisiana Coastal Zone Management Program ("LCZMP") was established
to protect, develop and, where feasible, restore and enhance coastal resources
of the state. Under the LCZMP, coastal use permits are required for certain
activities, even if the activity only partially infringes on the coastal zone.
Among other things, projects involving use of state lands and water bottoms,
dredge or fill activities that intersect with more than one body of water,
mineral activities, including the exploration and production of oil and gas, and
pipelines for the gathering, transportation or transmission of oil, gas and
other minerals require such permits. General permits, which entail a reduced
administrative burden, are available for a number of routine oil and gas
activities. The LCZMP and its requirement to obtain coastal use permits may
result in additional permitting requirements and associated project schedule
constraints.
The Texas Coastal Coordination Act ("CCA") provides for coordination
among local and state authorities to protect coastal resources through
regulating land use, water, and coastal development and establishes the Texas
Coastal Management Program ("CMP") that applies in the nineteen counties that
border the Gulf of Mexico and its tidal bays. The CCA provides for the review of
state and federal agency rules and agency actions for consistency with the goals
and policies of the Coastal Management Plan. This review may affect agency
permitting and may add a further regulatory layer to some of our projects.
OSHA. We are subject to the requirements of the federal Occupational
Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard
communication standard, the EPA community right-to-know regulations under Title
III of the federal Superfund Amendments and Reauthorization Act and similar
state statutes require us to organize and/or disclose information about
hazardous materials used or produced in our operations. Certain of this
information must be provided to employees, state and local governmental
authorities and local citizens.
Management believes that we are in substantial compliance with current
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse impact on us.
CORPORATE OFFICES
Our headquarters are located in Lafayette, Louisiana, in approximately
40,000 square feet of leased space, with an exploration office in Houston,
Texas, in approximately 5,500 square feet of leased space. We also maintain
owned or leased field offices in the area of the major fields in which we
operate properties or have a significant interest. Replacement of any of our
leased offices would not result in material expenditures by us as alternative
locations to our leased space are anticipated to be readily available.
EMPLOYEES
We had 44 employees as of December 31, 2003. In addition to our full
time employees, we utilize the services of independent contractors to perform
certain functions. We believe that our relationships with our employees are
satisfactory. None of our employees are covered by a collective bargaining
agreement.
AVAILABLE INFORMATION
PetroQuest's Internet website can be found at www.petroquest.com. We
make available free of charge, or through the "Financials" section of our
Internet website at www.petroquest.com, access to our annual report on Form
10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and
amendments to those reports filed pursuant to Section 13(a) or 15(d) of the
Exchange Act as soon as reasonably practicable after such material is filed, or
furnished to the Securities and Exchange Commission.
RISK FACTORS
RISKS RELATED TO OUR BUSINESS, INDUSTRY AND STRATEGY
Our future success depends upon our ability to find, develop and
acquire additional oil and natural gas reserves that are economically
recoverable.
As is generally the case in the Gulf Coast Basin where the majority of
our current production is located, many of our producing properties are
characterized by a high initial production rate, followed by a steep decline in
production. 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
9
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, if
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
- 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.
10
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 and natural
gas liquids were converted to natural gas equivalent at the ratio of six Mcf of
natural gas to one Bbl of oil or natural gas liquid. While this ratio
approximates the energy equivalency of natural gas to oil or natural gas liquid
on a Btu basis, it may not represent the relative prices received by us from the
sale of our oil or natural gas liquid and natural gas production.
Approximately 33% 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 is the current market value of our estimated oil
and natural gas reserves. In accordance with Securities and Exchange Commission
requirements, the estimated discounted future net cash flows from proved
reserves are generally based on prices and costs as of the date of the estimate.
Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of the estimate. Any changes in consumption by natural
gas purchasers or in governmental regulations or taxation may also affect actual
future net cash flows. The timing of both the production and the expenses from
the development and production of oil and natural gas properties will affect the
timing of actual future net cash flows from proved reserves and their present
value. In addition, the 10% discount factor, which is required by the Securities
and Exchange Commission to be used in calculating discounted future net cash
flows for reporting purposes, is not necessarily the most accurate discount
factor. The effective interest rate at various times and the risks associated
with our operations or the oil and natural gas industry in general will affect
the accuracy of the 10% discount factor.
Lower oil and natural gas prices may cause us to record ceiling test
write-downs.
We use the full cost method of accounting to account for our oil and
natural gas operations. Accordingly, we capitalize the cost to acquire, explore
for and develop oil and natural gas properties. Under full cost accounting
rules, the net capitalized costs of oil and natural gas properties may not
exceed a "ceiling limit" which is based upon the present value of estimated
future net cash flows from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. If net capitalized costs of
oil and natural gas properties exceed the ceiling limit, we must charge the
amount of the excess to earnings. This is called a "ceiling test write-down."
This charge does not impact cash flow from operating activities, but does reduce
our stockholders' equity. The risk that we will be required to write down the
carrying value of oil and natural gas properties increases when oil and natural
gas prices are low or volatile. In addition, write-downs may occur if we
experience substantial downward adjustments to our estimated proved reserves.
11
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.
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, sub-debt 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;
12
- 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 and sub-debt 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
- 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 and sub-debt 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
13
offering or refinancing can be successfully completed.
Hedging production may limit potential gains from increases in
commodity prices or result in losses.
We enter into hedging arrangements from time to time to reduce our
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. These financial arrangements take the form of cashless
collars or swap contracts and are placed with major trading counter parties we
believe represent minimum credit risks. We cannot assure you that these trading
counter parties will not become credit risks in the future. Hedging arrangements
expose us to risks in some circumstances, including situations when the other
party to the hedging contract defaults on its contract obligations or there is a
change in the expected differential between the underlying price in the hedging
agreement and actual prices received. These hedging arrangements may limit the
benefit we could receive from increases in the prices for natural gas and oil.
We cannot assure you that the hedging transactions we have entered into, or will
enter into, will adequately protect us from fluctuations in natural gas and oil
prices.
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.
14
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 and overriding royalty interests in
certain of our properties by certain of our officers and directors potentially
creates conflicts of interest.
Certain of our executive officers and directors or their respective
affiliates are working interest owners or overriding royalty interest owners in
particular properties. In their capacity as working interest owners, they are
required to pay their proportionate share of all costs and are entitled to
receive their proportionate share of revenues in the normal course of business.
As overriding royalty interest owners they are entitled to receive their
proportionate share of revenues in the normal course of business. There is a
potential conflict of interest between us and such officers and directors with
respect to the drilling of additional wells or other development operations with
respect to these properties.
RISKS RELATING TO OUR 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 20.3% of our outstanding common stock at March 1, 2004. 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 acquirer 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.
15
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.
Issuance of shares in connection with financing transactions or under
stock incentive plans will dilute current stockholders.
Pursuant to our stock incentive plan, our management is authorized to
grant stock awards to our employees, directors and consultants. You will incur
dilution upon exercise of any outstanding stock awards. In addition, if we raise
additional funds by issuing additional common stock, or securities convertible
into or exchangeable or exercisable for common stock, further dilution to our
existing stockholders will result, and new investors could have rights superior
to existing stockholders.
The number of shares of our common stock eligible for future sale could
adversely affect the market price of our stock.
We have reserved approximately 4.3 million shares of common stock for
issuance under outstanding options. These shares of common stock are registered
for resale on currently effective registration statements. In addition, we have
registered the resale of approximately 13.1 million shares of common stock that
were issued in private placements to accredited investors in 1999 and 2000, and
have granted piggy-back registration rights with respect to 2.25 million shares
of common stock underlying a warrant. We may issue additional restricted
securities or register additional shares of common stock under the Securities
Act in the future. The issuance of a significant number of shares of common
stock upon the exercise of stock options, or the availability for sale, or sale,
of a substantial number of the shares of common stock eligible for future sale
under effective registration statements, under Rule 144 or otherwise, could
adversely affect the market price of the common stock.
Provisions in certificate of incorporation, bylaws, shareholder rights
plan and Delaware law could delay or prevent a change in control of our company,
even if that change would be beneficial to our stockholders.
Certain provisions of our certificate of incorporation, bylaws and
shareholder rights plan and the provisions of Delaware General Corporation Law
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.
We are also subject to Section 203 of the Delaware General Corporation
Law, which generally prohibits a Delaware corporation from engaging in any of a
broad range of business combinations with an interested stockholder for a period
of three years following the date on which the stockholder became an interested
stockholder.
In November 2001, our board of directors adopted a shareholder rights
plan, pursuant to which uncertificated preferred stock purchase rights were
distributed to our stockholders at a rate of one right for each share of common
stock held of record as of November 19, 2001. The rights plan is designed to
enhance the board's ability to prevent an acquirer from depriving stockholders
of the long-term value of their investment and to protect stockholders against
attempts to acquire us by means of unfair or abusive takeover tactics. However,
the existence of the rights plan may impede a takeover not supported by
16
our board, including a takeover that may be desired by a majority of our
stockholders or involving a premium over the prevailing stock price.
NOTICE REGARDING CONSENT OF ARTHUR ANDERSEN LLP
On June 15, 2002, Arthur Andersen LLP, our former independent auditors,
was convicted of federal obstruction of justice. On June 28, 2002, our Board of
Directors, upon the approval of its Audit Committee, engaged Ernst & Young, LLP
as independent auditors and dismissed Arthur Andersen LLP. After reasonable
efforts, we have not been able to obtain the consent of Arthur Andersen LLP to
the incorporation by reference of its audit report dated March 7, 2002 into our
registration statements on Form S-3 and Form S-8. As permitted under Rule 437a
promulgated under the Securities Act of 1933, we have not filed the written
consent of Arthur Andersen LLP that would otherwise be required by the
Securities Act. Because Arthur Andersen LLP has not consented to the
incorporation of reference of their report in these registration statements, you
may not be able to recover amounts from Arthur Andersen LLP under Section 11(a)
of the Securities Act for any untrue statement of a material fact or any
omission to state a material fact, if any, contained in or omitted from our
financial statements included in our Annual Report on Form 10-K for the fiscal
year ended December 31, 2001, which are incorporated by reference in these
registration statements.
ITEM 2. PROPERTIES
For a description of the Company's exploration and development
activities and its significant properties, see Item 1. Business-Exploration and
Development and - Significant Properties.
OIL AND GAS RESERVES
The following table sets forth certain information about the estimated
proved reserves of the Company as of December 31, 2003.
Oil Gas and NGL
(Mbbls) (MMcfe)
------- -------
Proved developed: 3,446 34,655
Proved undeveloped: 799 23,138
Total proved: 4,245 57,793
Estimated pre-tax future net cash flows $ 293,348,933
Discounted pre-tax future net cash flows $ 214,364,855
Standardized measure of discounted future net cash flows $ 175,225,692
Ryder Scott Company, L.P. prepared the estimates of proved reserves and
future net cash flows (and present value thereof) attributable to such proved
reserves at December 31, 2003. Reserves were estimated using oil and gas prices
and production and development costs in effect at December 31, 2003 without
escalation, and were prepared in accordance with Securities and Exchange
Commission regulations regarding disclosure of oil and gas reserve information.
The product prices used in developing the above estimates averaged $32.24 per
Bbl of oil and $5.58 per MMBtu of gas. Because of the high Btu content of our
Gulf Coast gas, this equates to an average price realized of approximately $6.02
per Mcf. The above cash flow amounts include a reduction for estimated plugging
and abandonment costs that will also be reflected as a liability on our balance
sheet at December 31, 2003, in accordance with Statement of Financial Standards
No. 143.
We have not filed any reports with other federal agencies which contain
an estimate of total proved net oil and gas reserves.
17
OIL AND GAS DRILLING ACTIVITY
The following table sets forth the wells drilled and completed by us
during the periods indicated. All such wells were drilled in the continental
United States:
2003 2002 2001
---- ---- ----
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Exploration:
Productive 4 1.55 2 1.72 1 0.41
Non-productive 2 1.20 1 0.50 2 0.68
- ---- - ---- - ----
Total 6 2.75 3 2.22 3 1.09
= ==== = ==== = ====
Development:
Productive 4 1.96 5 4.02 9 5.78
Non-productive - - 2 0.77 1 0.54
- ---- - ---- -- ----
Total 4 1.96 7 4.79 10 6.32
= ==== = ==== == ====
We owned working interests in 113 gross (88.4 net) producing oil and
gas wells at December 31, 2003. At December 31, 2003, we had no wells in
progress.
LEASEHOLD ACREAGE
The following table shows our approximate developed and undeveloped
(gross and net) leasehold acreage as of December 31, 2003:
Leasehold Acreage
-----------------
Developed Undeveloped
--------- -----------
Gross Net Gross Net
----- --- ----- ---
Mississippi (onshore) 721 458 1,438 913
Louisiana (onshore) 3,025 701 4,415 1,638
Louisiana (offshore) 674 454 - -
Oklahoma (onshore) 627 627 2,791 2,442
Texas (onshore) 16,446 8,180 25,044 12,949
Federal Waters 39,103 16,525 55,398 35,481
------ ------ ------ ------
Total 60,596 26,945 89,086 53,423
TITLE TO PROPERTIES
We believe that the title to our oil and gas properties is good and
defensible in accordance with standards generally accepted in the oil and gas
industry, subject to such exceptions which, in our opinion, are not so material
as to detract substantially from the use or value of such properties. Our
properties are typically subject, in one degree or another, to one or more of
the following:
- royalties and other burdens and obligations, express or implied, under
oil and gas leases;
- overriding royalties and other burdens created by us or our
predecessors in title;
- a variety of contractual obligations (including, in some cases,
development obligations) arising under operating agreements, farmout
agreements, production sales contracts and other agreements that may
affect the properties or their titles;
- back-ins and reversionary interests existing under purchase agreements
and leasehold assignments;
- liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing obligations to unpaid suppliers
and contractors and contractual liens under operating agreements;
18
- pooling, unitization and communitization agreements, declarations and
orders; and
- easements, restrictions, rights-of-way and other matters that commonly
affect property
To the extent that such burdens and obligations affect our rights to
production revenues, they have been taken into account in calculating our net
revenue interests and in estimating the size and value of our reserves. We
believe that the burdens and obligations affecting our properties are
conventional in the industry for properties of the kind that we own.
ITEM 3. LEGAL PROCEEDINGS
There are no legal proceedings to which PetroQuest 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.
On December 10, 2003, our wholly owned subsidiary, PetroQuest Energy,
L.L.C. ("PetroQuest Energy") entered into a settlement agreement with The
Meridian Resource & Exploration LLC relating to the litigation "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" and "The Meridian Resource & Exploration Company v.
PetroQuest Energy, Inc., bearing Docket No. 996192A of the 15th Judicial
District Court in and for Lafayette Parish, Louisiana" which related to our
Southwest Holmwood property in Calcasieu Parish, Louisiana.
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 2003.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITES
MARKET PRICE OF AND DIVIDENDS ON COMMON STOCK
Our common stock trades on The Nasdaq Stock Market under the symbol
"PQUE." The following table lists high and low sales prices per share for the
periods indicated:
Nasdaq Stock Market
-------------------
Quarter Ended High Low
------------- ---- ---
(U.S.$) (U.S.$)
2002
1st Quarter 6.49 4.20
2nd Quarter 6.85 5.20
3rd Quarter 5.75 3.65
4th Quarter 5.05 3.61
2003
1st Quarter 4.37 1.48
2nd Quarter 2.79 1.20
3rd Quarter 2.48 1.85
4th Quarter 3.34 2.00
As of March 5, 2004, there were approximately 529 common stockholders
of record.
19
We have not paid dividends on the common stock and intend to retain our
cash flow from operations for the future operation and development of its
business. In addition, the bank credit facility and sub-debt facility restrict
the declaration or payment of any dividends or distributions.
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, 2003 has
been derived from the audited Consolidated Financial Statements of the Company
for such periods. The information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements and notes thereto. The
following information is not necessarily indicative of future results of the
Company. All amounts are stated in U.S. dollars unless otherwise indicated.
Years Ended December 31,
------------------------
2003 2002 2001 (a) 2000 (a) 1999 (a)
---- ---- -------- -------- --------
(in thousands except share data)
Revenues $ 48,688 $ 48,238 $ 55,342 $ 22,561 $ 8,607
Net Income (Loss) 3,640 2,307 11,645 9,924 (310)
Net Income (Loss) per share:
Basic 0.08 0.06 0.37 0.37 (0.01)
Diluted 0.08 0.06 0.34 0.35 (0.01)
Oil and Gas Properties, net 160,229 120,746 101,029 56,344 21,490
Total Assets 176,384 132,063 114,639 83,072 29,901
Long-term Debt 22,200 2,400 33,000 6,804 2,927
Stockholders' Equity 107,727 97,770 54,215 41,456 18,105
- ------------------
(a) The Company's financial statements for 1999-2001 were audited by Arthur
Andersen LLP, which has ceased operations.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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 and the East Texas area. We have
been active in the Gulf Coast 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, as
well as finding additional opportunities in areas with longer reserve lives.
During 2003, the Company completed a $20 million subordinated term
credit facility with Macquarie Americas Corp. ("Macquarie"). The sub-debt
facility is available for advances at any time until December 31, 2004 subject
to restrictive covenants. Macquarie received warrants to purchase 2,250,000 of
our common stock at an exercise price of $2.30 per share. We also completed an
acquisition in the Southeast Carthage Field in East Texas during 2003. This
property increased our proved reserves by approximately 29 Bcfe and was funded
primarily through our credit facilities. As a result of this acquisition, we
expect an increase in our 2004 production rate and revenues, as well as an
increase in operating expenses and interest expense.
20
NEW ACCOUNTING STANDARDS
In June 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations," which requires recording the fair
value of an asset retirement obligation associated with tangible long-lived
assets in the period incurred. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel.
We adopted SFAS 143 effective January 1, 2003. The net difference
between our previously recorded abandonment liability and the amounts estimated
under SFAS 143, after taxes, totaled a gain of $849,000, which has been
recognized as a cumulative effect of a change in accounting principle. The gain
is due to the effect on the historical depletion as a result of the retirement
obligation being recorded at fair value. On a pro forma basis, the impact for
the year ended December 31, 2002 would have increased net income by
approximately $360,000.
We have legal obligations to plug, abandon and dismantle existing wells
and facilities that we have acquired and constructed during our existence. As of
January 1, 2003, we recognized a $9,467,000 liability for our asset retirement
obligations and recorded the related additional assets that will be depreciated
using the unit-of-production method.
In January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which requires companies to evaluate variable interest entities to determine
whether to apply the consolidation provisions of FIN 46 to those entities. The
consolidation provisions of FIN 46, if applicable, would apply to variable
interest entities created after January 31, 2003 immediately, and to variable
interest entities created before February 1, 2003 in our interim period
beginning October 1, 2003. We believe that we have no interests in these types
of entities.
CRITICAL ACCOUNTING POLICIES
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil
and gas properties. Under this method, all acquisition, exploration and
development costs, including certain related employee costs, incurred for the
purpose of exploring for and developing and oil and natural gas are capitalized.
Acquisition costs include costs incurred to purchase, lease or otherwise acquire
property. Exploration costs include the costs of drilling exploratory wells,
including those in progress and geological and geophysical service costs in
exploration activities. Development costs include the costs of drilling
development wells and costs of completions, platforms, facilities and pipelines.
Costs associated with production and general corporate activities are expensed
in the period incurred. Sales of oil and gas properties, whether or not being
amortized currently, are accounted for as adjustments of capitalized costs, with
no gain or loss recognized, unless such adjustments would significantly alter
the relationship between capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially
included in the amortization base and related to unevaluated leasehold acreage
and delay rentals, seismic data and capitalized interest. These costs are either
transferred to the amortization base with the costs of drilling the related well
or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using
the unit-of-production method based upon production and estimates of proved
reserve quantities. Unevaluated costs and related carrying costs are excluded
from the amortization base until the properties associated with these costs are
evaluated. In addition to costs associated with evaluated properties, the
amortization base includes estimated future development costs and dismantlement,
restoration and abandonment costs, net of estimated salvage values. Our
depletion expense is affected by the estimates of future development costs,
unevaluated costs and proved reserves, and changes in these estimates could have
an impact on our future earnings.
We capitalize certain internal costs that are directly identified with
the acquisition, exploration and development activities. The capitalized
internal costs include salaries, employee benefits, costs of consulting services
and other related expenses and do not include costs related to production,
general corporate overhead or similar activities. We also capitalize a portion
of the interest costs incurred on our debt. Capitalized interest is calculated
using the amount of our unevaluated property and our effective borrowing rate.
21
Capitalized costs of oil and gas properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved oil and gas reserves, discounted at 10 percent, plus the lower of
cost or fair value of unproved properties, as adjusted for related income tax
effects (the full cost ceiling). If capitalized costs exceed the full cost
ceiling, the excess is charged to write-down of oil and gas properties in the
quarter in which the excess occurs. Declines in prices or reserves could result
in a future write-down of oil and gas properties. For purposes of calculating
the full cost ceiling test, the liability recognized under SFAS 143 is netted
against property cost and the future abandonment obligations are included in
estimated future net cash flows.
Given the volatility of oil and gas prices, it is probable that our
estimate of discounted future net cash flows from proved oil and gas reserves
will change in the near term. If oil or gas prices decline, even for only a
short period of time, or if we have downward revisions to our estimated proved
reserves, it is possible that write-downs of oil and gas properties could occur
in the future.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the use of the purchase
method of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review of impairment. The new standard also requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no
impact on our financial position or results of operations. A reporting issue has
arisen regarding the application of certain provisions of SFAS No. 141 and 142
to companies in the extractive industries, including oil and gas companies. The
issue is whether SFAS No. 142 requires registrants to classify the costs of
mineral rights associated with extracting oil and gas as intangible assets in
the balance sheet, apart from other capitalized oil and gas property costs, and
provide specific footnote disclosures. Historically, we have included the costs
of mineral rights associated with extracting oil and gas as a component of oil
and gas properties. These costs include those to acquire contract based drilling
and mineral use rights such as delay rentals, lease bonuses, commissions and
brokerage fees, and other leasehold costs. If it is ultimately determined that
SFAS No. 142 requires oil and gas companies to classify these costs as a
separate item on the balance sheet, we would be required to reclassify
approximately $27.5-$28.5 million at December 31, 2003 and approximately $5-$6
million at December 31, 2002. Our cash flows and results of operations would not
be affected since such intangible assets would continue to be depleted and
assessed for impairment in accordance with full cost accounting rules, as
allowed by SFAS No. 142. Further, we believe the classification of the costs of
mineral rights associated with extracting oil and gas as intangible assets would
have an impact on our compliance with the minimum tangible net worth covenant
under our bank credit facility.
PetroQuest will continue to classify its oil and gas leasehold costs as
tangible oil and gas properties until further guidance is provided. We
anticipate there will be no effect on our results of operations or cash flows.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or
dispose of our production platforms, gathering systems, wells and related
structures and restoration costs of land and seabed. We develop estimates of
these costs for each of our properties based upon the type of production
structure, depth of water, reservoir characteristics, depth of the reservoir,
market demand for equipment, currently available procedures and consultations
with construction and engineering consultants. Because these costs typically
extend many years into the future, estimating these future costs is difficult
and requires management to make estimates and judgments that are subject to
future revisions based upon numerous factors, including changing technology and
the political and regulatory environment. The accounting for future abandonment
costs changed on January 1, 2003, with the adoption of Statement of Financial
Accounting Standards No. 143, "Accounting for Asset Retirement Obligations." See
New Accounting Standards in the Notes to Consolidated Financial Statements for a
further discussion of this accounting standard.
Reserve Estimates
Our estimates of oil and gas reserves are, by necessity, projections
based on geologic and engineering data, and there are uncertainties inherent in
the interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve engineering is a
subjective process of estimating underground accumulations of oil and gas that
are difficult to measure. The accuracy of any reserve estimate is a function of
the quality of available data, engineering and geological interpretation and
judgment. Estimates of economically recoverable oil and gas reserves and future
net cash flows necessarily depend upon a number of variable factors and
assumptions, such as historical production from the area
22
compared with production from other producing areas, the assumed effect of
regulations by governmental agencies, and assumptions governing future oil and
gas prices, future operating costs, severance taxes, development costs and
workover costs, all of which may in fact vary considerably from actual results.
The future drilling costs associated with reserves assigned to proved
undeveloped locations may ultimately increase to the extent that these reserves
may be later determined to be uneconomic. For these reasons, estimates of the
economically recoverable quantities of expected oil and gas attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows may vary substantially.
Any significant variance in the assumptions could materially affect the
estimated quantity and value of the reserves, which could affect the carrying
value of our oil and gas properties and/or the rate of depletion of such oil and
gas properties. Actual production, revenues and expenditures with respect to our
reserves will likely vary from estimates, and such variance may be material.
Derivative Instruments
The estimated fair values of our commodity derivative instruments are
recorded in the consolidated balance sheet. At inception, all of our commodity
derivative instruments represent hedges of the price of future oil and gas
production. The changes in fair value of those derivative instruments that
qualify for treatment due to being highly effective are recorded to Other
Comprehensive Income until the hedged oil or natural gas quantities are
produced. If a hedge becomes ineffective because the expected event does not
occur, the fair value of the derivative is recorded on the income statement. One
of our derivatives was deemed ineffective during 2003 because of a decline in
production in the specific field to which the derivative was designated.
Estimating the fair values of hedging derivatives requires complex
calculations incorporating estimates of future prices, discount rates and price
movements. Instead, we choose to obtain the fair value of our commodity
derivatives from the counter parties to those contracts. Since the counter
parties are market makers, they are able to provide us with a literal market
value, or what they would be willing to settle such contracts for as of the
given date.
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, 2003,
2002 and 2001:
Year Ended December 31,
-----------------------
2003 2002 2001
---- ---- ----
Production:
Oil (Bbls) 744,575 929,181 791,405
Gas (Mcf) 5,192,760 7,765,142 9,025,240
Total Production (Mcfe) 9,660,210 13,340,228 13,773,670
Sales:
Total oil sales $ 21,196,246 $ 23,294,514 $ 20,171,659
Total gas sales 26,713,611 24,846,723 34,794,876
Average sales prices:
Oil (per Bbl) $ 28.47 $ 25.07 $ 25.49
Gas (per Mcf) 5.14 3.20 3.86
Per Mcfe 4.96 3.61 3.99
The above sales include income (loss) related to gas hedges of ($2,540,000),
($733,000) and $1,247,000 and oil hedges of ($1,923,000), ($128,000) and
$384,000 for the years ended December 31, 2003, 2002 and 2001, respectively.
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2003 AND
2002
Net income totaled $3,640,000 and $2,307,000 for the years ended December 31,
2003 and 2002, respectively. The results are attributable to the following
components:
23
Production
Oil production in 2003 decreased 20% from the year ended December 31,
2002. Natural gas production in 2003 decreased 33% from the year ended December
31, 2002. On a Mcfe basis, total production for the year ended December 31, 2003
decreased 28% over the same period in 2002. The decrease in 2003 total
production volumes, as compared to 2002, was due to the consistent decline of
our Gulf Coast production and well performance at our Bordeaux and Berry Lake
wells, partially offset by the drilling success during the second half of 2003.
Prices
Average oil prices per Bbl during 2003 were $28.47 as compared to
$25.07 for the same period in 2002. Average gas prices per Mcf were $5.14 during
2003 as compared to $3.20 for the same period in 2002. Stated on a Mcfe basis,
unit prices received during 2003 were 37% higher than the prices received during
2002.
Revenue
Oil and gas sales during 2003 decreased to $47,910,000 as compared to
2002 revenues of $48,141,000. The decrease in production volumes partially
offset by the significant increase in realized commodity prices resulted in the
decrease in revenue.
Interest and other income during 2003 increased to $778,000 as compared
to $97,000 during 2002. The increase is primarily the result of the settlement
of a lawsuit during 2003 and the related accounting entries as a result of the
settlement.
Expenses
Lease operating expenses for 2003 decreased to $9,449,000 from
$9,988,000 during 2002. On a Mcfe basis, lease operating expenses increased from
$0.75 per Mcfe in 2002 to $0.98 in 2003. The increase during 2003 on a Mcfe
basis is primarily due to an overall decline in production rates and the repairs
and maintenance costs at the Ship Shoal 72 Field, which did not increase
production rates.
General and administrative expenses during 2003 totaled $4,444,000 as
compared to expenses of $5,009,000 during 2002, net of amounts capitalized of
$3,611,000 and $3,664,000, respectively. The decreases in general and
administrative expenses are primarily due to a decrease in staffing levels
during the current year. We recognized $381,000 and $345,000 of non-cash
compensation expense during 2003 and 2002, respectively.
Depreciation, depletion and amortization ("DD&A") expense for 2003
decreased 4% to $27,098,000 as compared to $28,196,000 in 2002. On a Mcfe basis,
which reflects the changes in production, the DD&A rate for 2003 was $2.81 per
Mcfe as compared to $2.11 per Mcfe for 2002. The increase in 2003 as compared to
2002 is due primarily to costs in excess of previous estimates during the
previous twelve months and unsuccessful exploration drilling results during 2002
and 2003.
Interest expense, net of amounts capitalized on unevaluated prospects,
increased $301,000 during 2003 as compared to 2002. The increase is the result
of an increase in the average debt levels during 2003, the higher interest rates
on the new subordinated term credit facility and the previously capitalized
costs that were expensed on our prior credit facility. We capitalized $451,000
and $619,000 of interest during 2003 and 2002, respectively.
Derivative expense increased $513,000 during 2003 as compared to 2002.
This increase is primarily the result of one of our gas derivatives being
recorded on the income statement because of a decline in production in the
specific field to which the derivative was designated. The monthly settlements
related to this derivative have been recorded to derivative expense effective
during June 2003.
Income tax expense of $1,690,000 was recognized during 2003 as compared
to $1,288,000 being recorded during 2002. The increase is due to an increase in
operating profit during the current year. We provide for income taxes at a
statutory rate of 35% adjusted for permanent differences expected to be
realized, primarily statutory depletion.
24
COMPARISON OF RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2002 AND
2001
Net income totaled $2,307,000 and $11,645,000 for the years ended
December 31, 2002 and 2001, respectively. The results are attributable to the
following components:
Production
Oil production in 2002 increased 17% over the year ended December 31,
2001. Natural gas production in 2002 decreased 14% over the year ended December
31, 2001. On a Mcfe basis, total production for the year ended December 31, 2002
decreased 3% over the same period in 2001. The decrease in 2002 total production
volumes, as compared to 2001, was due to the consistent decline of our Gulf
Coast production partially offset by the drilling success during 2002.
Prices
Average oil prices per Bbl during 2002 were $25.07 as compared to
$25.49 for the same period in 2001. Average gas prices per Mcf were $3.20 during
2002 as compared to $3.86 for the same period in 2001. Stated on a Mcfe basis,
unit prices received during 2002 were 10% lower than the prices received during
2001.
Revenue
Oil and gas sales during 2002 decreased 12% to $48,141,000 as compared
to 2001 revenues of $54,967,000. The slight decrease in production volumes and
reduced commodity prices resulted in the decrease in revenue.
Expenses
Lease operating expenses for 2002 increased to $9,988,000 from
$7,172,000 during 2001. On a Mcfe basis, lease operating expenses increased from
$0.52 per Mcfe in 2001 to $0.75 in 2002. The increase during 2002 is primarily
due to increased insurance costs and an increase in the repairs and maintenance
at the Ship Shoal 72 Field.
General and administrative expenses during 2002 totaled $5,009,000 as
compared to expenses of $4,752,000 during 2001, net of amounts capitalized of
$3,664,000 and $2,651,000, respectively. The increases in general and
administrative expenses are primarily due to an increase in staffing levels and
rent expense related to the generation of prospects, exploration for oil and gas
reserves and operation of properties. We recognized $345,000 and $765,000 of
non-cash compensation expense during 2002 and 2001, respectively.
DD&A expense for 2002 increased 22% to $28,196,000 as compared to
$23,094,000 in 2001. On a Mcfe basis, which reflects the changes in production,
the DD&A rate for 2002 was $2.11 per Mcfe as compared to $1.68 per Mcfe for
2001. The increase in 2002 as compared to 2001 is due primarily to costs in
excess of previous estimates during the previous twelve months and unsuccessful
exploration drilling results during 2002.
Interest expense, net of amounts capitalized on unevaluated prospects,
decreased $1,833,000 during 2002 as compared to 2001. The decrease is the result
of an decrease in the average debt levels and interest rates during 2002. We
capitalized $619,000 and $1,001,000 of interest during 2002 and 2001,
respectively.
Income tax expense of $1,288,000 was recognized during 2002 as compared
to $5,411,000 being recorded during 2001. The decrease is due to a decrease in
operating profit during the current year. We provide for income taxes at a
statutory rate of 37% adjusted for permanent differences expected to be
realized, primarily statutory depletion.
LIQUIDITY AND CAPITAL RESOURCES
We have financed our exploration and development activities to date
principally through cash flow from operations, bank borrowings, private and
public offerings of common stock and sales of properties.
25
Source of Capital: Operations
Net cash flow from operations during the year increased from
$29,178,000 in 2002 to $33,163,000 in 2003. The change resulted primarily from
changes in the working capital accounts during the current year as compared to
2002. The working capital deficit decreased from $(15.8) million at December 31,
2002 to $(15.3) million at December 31, 2003. This decrease was caused primarily
by our effort to utilize cash flow to first reduce our working capital deficit
and second to drill prospects.
Source of Capital: Debt
We entered into a new bank credit facility on May 14, 2003. Pursuant to
the new credit facility agreement, PetroQuest and our subsidiary PetroQuest
Energy, L.L.C. (the "Borrower") have a $75 million revolving credit facility
which permits us to borrow amounts from time to time based on our available
borrowing base as determined in the bank credit facility. The bank 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 the bank credit facility is based upon the valuation as of
April 1 and October 1 of each year of the Borrower's mortgaged properties,
projected oil and gas prices, and any other factors deemed relevant by the
lenders. We or the lenders may also request additional borrowing base
redeterminations. As of December 31, 2003, the borrowing base under the bank
credit facility was $20.2 million and is subject to monthly reductions of $1
million commencing March 1, 2004. We have recently completed a borrowing base
redetermination as of March 1, 2004, and the borrowing base is $21.2 million and
subject to monthly reductions of $1.25 million commencing on July 1, 2004. The
bank will determine future monthly reductions in connection with each borrowing
base redetermination.
Outstanding balances on the revolving credit facility bear interest at
either the bank's prime rate plus a margin (based on a sliding scale of 0.75% to
1.25% based on borrowing base usage but never less than the Federal Funds
Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a
sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank
credit facility also allows us to use up to $5 million of the borrowing base for
letters of credit for fees equal to the applicable margin rate for Eurodollar
advances. At March 5, 2004, we had $15.5 million of borrowings and no letters of
credit issued pursuant to the bank credit facility.
We are subject to certain restrictive financial and non-financial
covenants under the bank credit facility, including a minimum current ratio of
1.0 to 1.0, all as defined in the credit facility agreement. The bank credit
facility also requires the Borrower to establish and maintain commodity hedges
covering at least 50% of its proved developed producing reserves on a rolling
twelve month basis. As of December 31, 2003, we were in compliance with all of
the covenants in the bank credit facility. The bank credit facility matures on
May 14, 2006.
On November 6, 2003, we obtained a $20 million subordinated term credit
facility from Macquarie. The sub-debt facility carries an interest rate of prime
plus 5.5%, is secured by a second mortgage on substantially all of our oil and
gas properties and matures November 30, 2006. The sub-debt facility is available
for advances at any time until December 31, 2004 subject to the restrictive
covenants of the sub-debt facility and Macquarie approval. At closing, Macquarie
received warrants to purchase 1,250,000 shares of our common stock at an
exercise price of $2.30 per share. When cumulative advances under the sub-debt
facility exceeded $5 million, $10 million and $15 million, Macquarie was to
receive warrants to purchase an additional 250,000 shares, 500,000 shares and
250,000 shares of our common stock, respectively, at the same exercise price per
share. In conjunction with the December 23, 2003 property acquisition, the
sub-debt facility was amended and the original warrant was cancelled and
reissued at which time all 2,250,000 warrants were issued to Macquarie. The
warrants are exercisable at any time through the earlier of 36 months following
the repayment in full of the sub-debt facility or 30 days after daily volume
weighted average price of our common stock as published by Nasdaq is equal to or
greater than, for a period of 30 days, the exercise price multiplied by three.
In addition, we granted Macquarie piggy-back registration rights with respect to
the shares of common stock issuable upon exercise of the warrants.
As of December 31, 2003, we had $12 million borrowed under the sub-debt
facility which was primarily used to fund our acquisition of properties in the
Southeast Carthage Field. The sub-debt facility, as amended, contains certain
restrictive financial and non-financial covenants, including a minimum current
ratio of 1.0 to 1.0, a total debt threshold of $45 million and a cumulative
minimum production and net operating cash flow threshold, all as defined in the
sub-debt facility. The sub-debt facility also requires us to establish and
maintain commodity hedges covering at least 65% of its proved developed
producing reserves through November 2006. As of December 31, 2003, we were in
compliance with all of the covenants in the sub-debt facility.
26
During January 2004, the sub-debt facility, including the note, liens, warrants
and all other rights of Macquarie thereunder, was assigned to Macquarie Bank
Limited, an affiliate of Macquarie Americas Corp.
Natural gas and oil prices have a significant impact on our cash flows
available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under our bank credit facility is
subject to periodic re-determination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of natural gas and oil
that we can economically produce. Additionally, the production declines of
certain producing wells resulted in lower production during the year ended
December 31, 2003. Lower prices and/or lower production may decrease revenues,
cash flows and the borrowing base under the bank credit facility, thus reducing
the amount of financial resources available to meet our capital requirements.
Although we do not anticipate debt covenant violations, our ability to comply
with our debt agreements is dependent upon the success of our exploration and
development program and upon factors beyond our control, such as natural gas and
oil prices.
Source of Capital: Issuance of Equity Securities
We have an effective universal shelf registration statement relating to
the potential public offer and sale by PetroQuest of any combination of debt
securities, common stock, preferred stock, depositary shares, and warrants from
time to time or when financing needs arise. The registration statement does not
provide assurance that we will or could sell any such securities.
During October and November 2002, we completed the offering of
5,000,000 shares of our common stock. The shares were sold to the public for
$4.25 per share. After underwriting discounts, we realized proceeds of
approximately $20.4 million.
During February and March 2002, we completed the offering of 5,193,600
shares of our common stock. The shares were sold to the public for $4.40 per
share. After underwriting discounts, we realized proceeds of approximately $21.9
million.
Source of Capital: Sales of Properties
On March 1, 2002, we closed the sale of our interest in Valentine Field
for $18.6 million. The transaction had an effective date of January 1, 2002. At
December 31, 2001, our independent reservoir engineering firm attributed 7.3
Bcfe of proved reserves net to our interest in this field. Consistent with the
full cost method of accounting, we did not recognize any gain or loss as a
result of this sale. The proceeds were treated as a reduction of the full cost
pool.
Use of Capital: Exploration and Development
We have an exploration and development program budget for the year
2004 which will require significant capital. Our capital budget for new projects
in 2004 is approximately $45-50 million of which approximately 80% will be
incurred in the Gulf Coast region and the remaining 20% in other areas. Our
management believes the cash flows from operations and available borrowing
capacity under our credit facilities, will be sufficient to fund planned 2004
exploration and development activities. In the future, our exploration and
development activities could require additional financings, which may include
sales of additional equity or debt securities, additional borrowings from banks
or other lenders, sales of properties, or joint venture arrangements with
industry partners. We cannot assure you that such additional financings will be
available on acceptable terms, if at all. If we are unable to obtain additional
financing, we could be forced to delay or even abandon some of our exploration
and development opportunities or be forced to sell some of our assets on an
untimely or unfavorable basis.
27
Contractual Obligations
The following table summarizes our contractual obligations as of
December 31, 2003:
After
2004 2005 2006 2007 2008 2008
---- ---- ---- ---- ---- ----
Bank debt 5,300 12,200 - - - -
Subordinated debt - - 12,000 - - -
Operating leases (1) 741 806 744 703 699 1,363
Capital projects (2) 1,054 1,694 314 124 306 8,985
(1) Consists primarily of leases for office space and leases for equipment
rentals.
(2) Consists primarily of future obligations to abandon our leased
properties.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
We experience market risks primarily in two areas: interest rates and
commodity prices. We believe that our business operations are not exposed to
significant market risks relating to foreign currency exchange risk.
Our revenues are derived from the sale of our crude oil and natural gas
production. Based on projected annual sales volumes for 2004, a 10% decline in
the estimated average 2004 prices we receive for our crude oil and natural gas
production would have an approximate $6.5 million impact on our revenues.
In a typical hedge transaction, we will have the right to receive from
the counterparts to the hedge, the excess of the fixed price specified in the
hedge over a floating price based on a market index, multiplied by the quantity
hedged. If the floating price exceeds the fixed price, we are required to pay
the counterparts this difference multiplied by the quantity hedged. We are
required to pay the difference between the floating price and the fixed price
(when the floating price exceeds the fixed price) regardless of whether we have
sufficient production to cover the quantities specified in the hedge.
Significant reductions in production at times when the floating price exceeds
the fixed price could require us to make payments under the hedge agreements
even though such payments are not offset by sales of production. Hedging will
also prevent us from receiving the full advantage of increases in oil or gas
prices above the fixed amount specified in the hedge. As of December 31, 2003,
we had entered into the following oil and gas contracts accounted for as cash
flow hedges:
INSTRUMENT WEIGHTED
PRODUCTION PERIOD TYPE DAILY VOLUMES AVERAGE PRICE
- ----------------- ---- ------------- -------------
NATURAL GAS:
2004 Costless Collar 3,700 Mmbtu $4.16 - 6.73
First Quarter 2004 Costless Collar 6,800 Mmbtu $4.50 - 7.10
Second Quarter 2004 Costless Collar 4,800 Mmbtu $4.50 - 5.53
Third Quarter 2004 Costless Collar 2,300 Mmbtu $4.50 - 5.49
2005 Swap 750 Mmbtu $4.55
2005 Costless Collar 1,500 Mmbtu $4.50 - 5.19
2006 Swap 1,500 Mmbtu $4.53
CRUDE OIL:
2004 Costless Collar 750 Bbl $25.67 - 29.14
2005 Costless Collar 500 Bbl $23.00 - 26.20
2006 Costless Collar 200 Bbl $23.00 - 26.40
At December 31, 2003, we recognized a liability of $1,561,000 related
to these derivative instruments.
28
As of March 5, 2003, we had entered into the following additional oil
and gas contracts accounted for as cash flow hedges:
NATURAL GAS:
March 2004 Costless Collar 4,000 Mmbtu $4.50 - 5.71
Second Quarter 2004 Costless Collar 3,500 Mmbtu $4.50 - 5.73
July - December 2004 Costless Collar 3,000 Mmbtu $4.50 - 6.26
First Quarter 2005 Costless Collar 3,500 Mmbtu $4.50 - 7.05
Second Quarter 2005 Costless Collar 2,500 Mmbtu $4.50 - 5.33
CRUDE OIL:
March-December 2004 Costless Collar 250 Bbl $26.00 - 33.50
We currently have an interest rate swap covering $5 million of our
floating rate debt. The swap which expires in November 2004 has a fixed interest
rate of 5.665%. The swap is stated at its fair value and is marked-to-market
through derivative expense on our income statement. As of December 31, 2003, the
fair value of the open interest rate swap was a liability of $218,000.
We also evaluated the potential effect that reasonably possible near
term changes may have on our credit facilities. Debt outstanding under the
credit facilities is subject to a floating interest rate and represents 100% of
our total debt as of December 31, 2003. Based upon an analysis utilizing the
actual interest rate in effect and balances outstanding as of December 31, 2003
and assuming a 10% increase in interest rates and no changes in the amount of
debt outstanding, the potential effect on interest expense for 2004 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.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, our management
carried out an evaluation, with the participation of our principal executive
officer (the "CEO") and our principal financial officer (the "CFO"), of the
effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15
of the Securities and Exchange Act of 1934. Based on those evaluations, the CEO
and CFO believe:
(i) that our disclosure controls and procedures are designed to
ensure that information required to be disclosed by us in the reports that we
file or submit under the Securities Exchange Act of 1934 is recorded, processed,
summarized and reported within the time periods specified in the SEC's rules and
forms, and that such information is accumulated and communicated to our
management, including the CEO and CFO, as appropriate to allow timely decisions
regarding required disclosure; and
(ii) that our disclosure controls and procedures are effective.
Changes in Internal Controls Over Financial Reporting
There have been no significant changes in our internal controls over
financial reporting during the period covered by this report that has materially
affected, or are reasonably likely to materially affect, our control over
financial reporting.
29
PART III
ITEMS 10, 11, 12, 13 & 14
For information concerning Item 10. Directors and Executive Officers of
the Registrant, Item 11. Executive Compensation, Item 12. Security Ownership of
Certain Beneficial Owners and Management, Item 13. Certain Relationships and
Related Transactions and Item 14. Principal Accountant Fees and Services, see
the definitive Proxy Statement of PetroQuest Energy, Inc. relating to the Annual
Meeting of Stockholders to be held May 12, 2004, which will be filed with the
Securities and Exchange Commission and is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS
The following financial statements of the Company and the Report of the
Company's Independent Public Accountants thereon are included on pages F-1
through F-21 of this Form 10-K:
Report of Independent Auditors
Report of Independent Public Accountants
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for the three years ended
December 31, 2003
Consolidated Statements of Stockholder's Equity for the three
years ended December 31, 2003
Consolidated Statements of Cash Flows for the three years ended
December 31, 2003
Notes to Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is
inapplicable or the information is presented in the Financial Statements or the
notes thereto.
3. EXHIBITS:
2.1 Plan and Agreement of Merger by and among Optima Petroleum Corporation,
Optima Energy (U.S.) Corporation, its wholly-owned subsidiary, and
Goodson Exploration Company, NAB Financial L.L.C., Dexco Energy, Inc.,
American Explorer, L.L.C. (incorporated herein by reference to Appendix
G of the Proxy Statement on Schedule 14A filed July 22, 1998).
3.1 Certificate of Incorporation of the Company (incorporated herein by
reference to Exhibit 4.1 to Form 8-K dated September 16, 1998)
3.2 Bylaws of the Company (incorporated herein by reference to Exhibit 4.2
to Form 8-K dated September 16, 1998).
3.3 Certificate of Domestication of Optima Petroleum Corporation
(incorporated herein by reference to Exhibit 4.4 to Form 8-K dated
September 16, 1998).
3.4 Certificate of Designations, Preferences, Limitations And Relative
Rights of The Series a Junior Participating Preferred Stock of
PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit A
of the Rights Agreement attached as Exhibit 1 to Form 8-A filed
November 9, 2001).
4.1 Warrant to Purchase Common Shares of PetroQuest Energy, Inc.
(incorporated by reference to Exhibit 4.1 to Form 8-K filed December
29, 2003
30
4.2 Rights Agreement dated as of November 7, 2001 between PetroQuest
Energy, Inc. and American Stock Transfer & Trust Company, as Rights
Agent, including exhibits thereto (incorporated herein by reference to
Exhibit 1 to Form 8-A filed November 9, 2001).
4.3 Form of Rights Certificate (incorporated herein by reference to Exhibit
C of the Rights Agreement attached as Exhibit 1 to Form 8-A filed
November 9, 2001).
10.1 PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated
effective December 1, 2000 (incorporated herein by reference to
Appendix A to Proxy Statement on Schedule 14A filed April 20, 2001).
10.2 Amended and Restated Credit Agreement, dated as of May 14, 2003, by and
between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Bank One, NA,
Banc One Capital Markets, Inc., and certain other Lenders (incorporated
herein by reference to Exhibit 10.1 to Form 10-Q filed August 13,
2003).
10.3 Guaranty dated May 14, 2003, between PetroQuest Energy, Inc. and Bank
One, NA, as Agent for the Lenders (incorporated herein by reference to
Exhibit 10.2 to Form 10-Q filed August 13, 2003).
10.4 First Amendment to Amended and Restated Credit Agreement dated as of
November 6, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc.; Bank One, N.A., and Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.4 to Form 10-Q filed
November 13, 2003).
10.5 Second Amendment to Amended and Restated Credit Agreement dated as of
December 23, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc., and Bank One, N.A. (incorporated herein by reference to
Exhibit 10.2 to Form 8-K filed December 29, 2003).
10.6 Senior Second Lien Secured Credit Agreement dated November 6, 2003,
between PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the
Lenders from time to time party thereto; and Macquarie Americas Corp.,
as administrative agent for the Lenders (incorporated herein by
reference to Exhibit 10.1 to Form 10-Q filed November 13, 2003).
10.7 Unconditional Guaranty Agreement dated November 6, 2003, by PetroQuest
Energy, Inc. to Macquarie Americas Corp., as administrative agent for
the benefit of the Lenders under the Credit Agreement (incorporated
herein by reference to Exhibit 10.2 to Form 10-Q filed November 13,
2003).
10.8 First Amendment To Second Lien Secured Credit Agreement dated December
23, 2003, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc.,
each of the Lenders from time to time party thereto, and Macquarie
Americas Corp., as administrative agent for the Lenders (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed December 29,
2003).
10.9 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).
10.10 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).
10.11 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)
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 Employment Agreement dated April 20, 2001 between PetroQuest Energy,
Inc. and Dalton F. Smith III (incorporated herein by reference to
Exhibit 10.21 to Form 10-K filed March 13, 2002).
10.17 Employment agreement dated July 28, 2003, between PetroQuest Energy,
Inc. and Stephen H. Green (incorporated herein by reference to Exhibit
10.3 to Form 10-Q filed November 13, 2003).
10.18 Form of Termination Agreement Between PetroQuest Energy, Inc. and each
of its executive officers, including Charles T. Goodson, Ralph J.
Daigle, Michael O. Aldridge, Arthur M. Mixon, III, Daniel G. Fournerat,
Dalton F. Smith III and Stephen H. Green (incorporated herein by
reference to Exhibit 10.20 to Form 10-K filed March 13, 2002).
31
10.19 Form of Indemnification Agreement between PetroQuest Energy, Inc. and
each of its directors and executive officers, including Charles T.
Goodson, Ralph J. Daigle, Daniel G. Fournerat, E. Wayne Nordberg,
William W. Rucks, IV, Michael O. Aldridge, Arthur M. Mixon, III, Dalton
F. Smith III, Michael L. Finch, W.J. Gordon, III and Stephen H. Green
(incorporated herein by reference to Exhibit 10.21 to Form 10-K filed
March 13, 2002).
*14.1 Business Ethics Policy
21.1 Subsidiaries of the Company (incorporated herein by reference to
Exhibit 21.1 to Form 10-K filed March 30, 2001).
*23.1 Consent of Independent Auditors.
23.2 Consent of Arthur Andersen LLP (omitted pursuant to Rule 437a under the
Securities Act of 1933, as amended).
*23.3 Consent of Ryder Scott Company, L.P.
*31.1 Certification of Chief Executive Officer pursuant to Rule 13-a-14(a) /
Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934,
as amended.
*31.2 Certification of Chief Financial Officer pursuant to Rule 13-a-14(a) /
Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934,
as amended.
*32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive
Officer.
*32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial
Officer.
- ----------------------
* Filed herewith.
32
REPORTS ON FORM 8-K
(i) The Company filed a report on Form 8-K on November 6, 2003, relating to
third quarter 2003 results.
(ii) The Company filed a report on Form 8-K on December 29, 2003, relating
to the closing of a property acquisition and amendment of credit
facilities.
33
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a description of the meanings of some of the oil and
natural gas used in this Form 10-K.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, of crude
oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Block. A block depicted on the Outer Continental Shelf Leasing and
Official Protraction Diagrams issued by the U.S. Minerals Management Service or
a similar depiction on official protraction or similar diagrams issued by a
state bordering on the Gulf of Mexico.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production
of natural gas or oil, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable
to productive wells or wells capable of production.
Developmental well. A well drilled into a proved natural gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir or to extend a
known reservoir.
Farm-in or farm-out. An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."
Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
34
MMBls. Million barrels of crude oil or other liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interest
owned in gross acres or wells, as the case may be.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting
geological, geophysical or other data and also preliminary economic analysis
using reasonably anticipated prices and costs, is deemed to have potential for
the discovery of commercial hydrocarbons.
Proved developed non-producing reserves. Proved developed reserves
expected to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.
Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage contains
proved reserves.
Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.
35
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 12, 2004.
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 12, 2004.
By: /s/ Charles T. Goodson Chairman of the Board, Chief Executive Officer and
----------------------
CHARLES T. GOODSON Director (Principal Executive Officer)
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
----------------------
MICHAEL O. ALDRIDGE and Director (Principal Financial and Accounting Officer)
By: /s/ W.J. Gordon, III Director
----------------------
W.J. GORDON, III
By: /s/ Michael L. Finch Director
----------------------
MICHAEL L. FINCH
By: /s/ E. Wayne Nordberg Director
----------------------
E. WAYNE NORDBERG
By: /s/ William W. Rucks, IV Director
----------------------
WILLIAM W. RUCKS, IV
36
INDEX TO FINANCIAL STATEMENTS
Report of Independent Auditors.................................................. F-2
Report of Independent Public Accountants ....................................... F-3
Consolidated Balance Sheets of PetroQuest Energy, Inc. as of
December 31, 2003 and 2002.................................................... F-4
Consolidated Statements of Operations of PetroQuest Energy, Inc.
for the years ended December 31, 2003, 2002 and 2001.......................... F-5
Consolidated Statements of Stockholders' Equity of PetroQuest Energy, Inc.
for the years ended December 31, 2003, 2002 and 2001.......................... F-6
Consolidated Statements of Cash Flows of PetroQuest Energy, Inc.
for the years ended December 31, 2003, 2002 and 2001.......................... F-7
Notes to Consolidated Financial Statements...................................... F-8
F-1
REPORT OF INDEPENDENT AUDITORS
To the Stockholders of
PetroQuest Energy, Inc.:
We have audited the accompanying consolidated balance sheets of PetroQuest
Energy, Inc. (a Delaware corporation) as of December 31, 2003 and 2002, and the
related consolidated statements of operations, stockholders' equity and cash
flows for each of the two years in the period ended December 31, 2003. 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. The financial statements of PetroQuest Energy, Inc. for the year
ended December 31, 2001 were audited by other auditors who have ceased
operations and whose report dated March 7, 2002, expressed an unqualified
opinion on those statements and included an explanatory paragraph that disclosed
the change in the Company's method of accounting for derivative instruments and
hedging activities discussed in Note 2 to these financial statements.
We conducted our 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 2003 and 2002 financial statements referred to above present
fairly, in all material respects, the consolidated financial position of
PetroQuest Energy, Inc. as of December 31, 2003 and 2002, and the consolidated
results of its operations and its cash flow for each of the two years in the
period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States.
As discussed in Note 1 to the consolidated financial statements, effective
January 1, 2003 the Company adopted Statement of Financial Accounting Standards
No. 143, "Accounting for Asset Retirement Obligations."
ERNST&YOUNG LLP
New Orleans, Louisiana
March 9, 2004
F-2
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
PetroQuest Energy, Inc.:
We have audited the accompanying consolidated balance sheets of PetroQuest
Energy, Inc. (a Delaware corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of operations, stockholders'
equity and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of PetroQuest Energy, Inc. and
subsidiaries as of December 31, 2001 and 2000, and the consolidated results of
their operations and their cash flow for each of the three years in the period
ended December 31, 2001, in conformity with accounting principles generally
accepted in the United States.
As discussed in Note 2 to the consolidated financial statements effective
January 1, 2001, the Company adopted SFAS 133, "Accounting for Derivatives
Instruments and Hedging Activities."
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 7, 2002
NOTE: The report of Arthur Andersen LLP presented above is a copy of a
previously issued Arthur Andersen LLP report and said report has not been
reissued by Arthur Andersen LLP nor has Arthur Andersen LLP provided a consent
to the inclusion of its report in this Form 10-K.
F-3
PETROQUEST ENERGY, INC.
Consolidated Balance Sheets
(Amounts in Thousands)
DECEMBER 31, DECEMBER 31,
2003 2002
------------ ------------
ASSETS
Current assets:
Cash and cash equivalents $ 779 $ 1,137
Oil and gas revenue receivable 6,520 6,500
Joint interest billing receivable 2,575 2,165
Other current assets 1,005 310
------------ ------------
Total current assets 10,879 10,112
------------ ------------
Oil and gas properties:
Oil and gas properties, full cost method 282,898 214,543
Unevaluated oil and gas properties 10,813 15,653
Accumulated depreciation, depletion and amortization (133,482) (109,450)
------------ ------------
Oil and gas properties, net 160,229 120,746
------------ ------------
Other assets, net of accumulated depreciation and amortization
of $3,826 and $2,851, respectively 5,276 1,205
------------ ------------
Total Assets $ 176,384 $ 132,063
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 18,126 $ 18,337
Advances from co-owners 2,752 940
Current portion of long-term debt 5,300 6,600
------------ ------------
Total current liabilities 26,178 25,877
Long-term debt 22,200 2,400
Asset retirement obligation 12,476 -
Deferred income taxes 7,803 5,461
Other liabilities - 555
Commitments and contingencies - -
Stockholders' equity:
Common stock, $.001 par value; authorized 75,000
shares; issued and outstanding 44,542 and 42,852
shares, respectively 45 43
Paid-in capital 112,038 106,173
Unearned deferred compensation (69) (337)
Other comprehensive income (1,015) (1,197)
Accumulated deficit (3,272) (6,912)
------------ ------------
Total stockholders' equity 107,727 97,770
------------ ------------
Total liabilities and stockholders' equity $ 176,384 $ 132,063
============ ============
See accompanying Notes to Consolidated Financial Statements.
F-4
PETROQUEST ENERGY, INC.
Consolidated Statements of Operations
(Amounts in Thousands, Except Per Share Data)
YEAR ENDED DECEMBER 31,
---------------------------
2003 2002 2001
------- ------- -------
Revenues:
Oil and gas sales $47,910 $48,141 $54,967
Interest and other income 778 97 375
------- ------- -------
48,688 48,238 55,342
------- ------- -------
Expenses:
Lease operating expenses 9,449 9,988 7,172
Production taxes 884 614 1,096
Depreciation, depletion and amortization 27,098 28,196 23,094
General and administrative 4,444 5,009 4,752
Accretion of asset retirement obligation 682 - -
Interest expense 579 278 2,111
Derivative expense 1,071 558 61
------- ------- -------
44,207 44,643 38,286
------- ------- -------
Income from operations 4,481 3,595 17,056
Income tax expense 1,690 1,288 5,411
------- ------- -------
Income before cumulative effect of
change in accounting principle $ 2,791 $ 2,307 $11,645
Cumulative effect of change in accounting principle 849 - -
------- ------- -------
Net income $ 3,640 $ 2,307 $11,645
======= ======= =======
Earnings per common share:
Basic
Income before cumulative effect of
change in accounting principle $ 0.06 $ 0.06 $ 0.37
Cumulative effect of change in
accounting principle 0.02 - -
Net income $ 0.08 $ 0.06 $ 0.37
======= ======= =======
Diluted
Income before cumulative effect of
change in accounting principle $ 0.06 $ 0.06 $ 0.34
Cumulative effect of change in
accounting principle 0.02 - -
Net income $ 0.08 $ 0.06 $ 0.34
======= ======= =======
Weighted average number of common shares:
Basic 43,661 37,871 31,818
Diluted 44,181 39,997 34,271
See accompanying Notes to Consolidated Financial Statements.
F-5
PETROQUEST ENERGY, INC.
Consolidated Statements of Stockholders' Equity
(Amounts in Thousands, Except Share Data)
UNEARNED OTHER TOTAL
COMMON PAID-IN DEFERRED COMPREHENSIVE ACCUMULATED STOCKHOLDERS'
STOCK CAPITAL COMPENSATION INCOME DEFICIT EQUITY
------ --------- ------------ ------------- ----------- -------------
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
------ --------- ---------- ------- ----------- ----------
Options and warrants exercised - 178 - - - 178
Sale of common stock 10 42,040 - - - 42,050
Amortization of deferred compensation - - 345 - - 345
Tax effect of deferred compensation - (128) - - - (128)
Derivative fair value adjustment - - - 1,197) - (1,197)
Net income - - - - 2,307 2,307
------ --------- ---------- ------- ----------- ----------
December 31, 2002 $ 43 $ 106,173 $ (337) $ (1,197) $ (6,912) $ 97,770
------ --------- ---------- ------- ----------- ----------
Options and warrants exercised 2 2,110 - - - 2,112
Sale of common stock - (6) - - - (6)
Amortization of deferred compensation - - 268 - - 268
Tax effect of deferred compensation - 16 - - - 16
Warrant fair value adjustment - 3,745 - - - 3,745
Derivative fair value adjustment - - - 182 - 182
Net income - - - - 3,640 3,640
------ --------- ---------- ------- ----------- ----------
December 31, 2003 $ 45 $ 112,038 $ (69) $ (1,015) $ (3,272) $ 107,727
------ --------- ---------- ------- ----------- ----------
See accompanying Notes to Consolidated Financial Statements.
F-6
PETROQUEST ENERGY, INC.
Consolidated Statements of Cash Flows
(Amounts in Thousands)
YEAR ENDED DECEMBER 31,
--------------------------------
2003 2002 2001
-------- -------- --------
Cash flows from operating activities:
Net income $ 3,640 $ 2,307 $ 11,645
Adjustments to reconcile net income to net cash
provided by operating activities:
Deferred tax expense 1,690 1,288 5,411
Amortization of debt issuance costs 531 261 1,369
Compensation expense 381 345 765
Depreciation, depletion and amortization 27,098 28,196 23,094
Derivative mark to market (258) 416 61
Cumulative effect of change in accounting principle (849) - -
Accretion of asset retirement obligation 682 - -
Plugging and abandonment costs - - (28)
Changes in working capital accounts:
Accounts receivable (20) (918) (434)
Joint interest billing receivable (409) 2,443 5,542
Accounts payable and accrued liabilities 1,416 (3,862) (61)
Other assets (1,300) (725) (1,011)
Advances from co-owners 1,811 (1,376) (5,253)
Plugging and abandonment escrow - 1,034 (539)
Other (1,250) (231) 308
-------- -------- --------
Net cash provided by operating activities 33,163 29,178 40,869
-------- -------- --------
Cash flows from investing activities:
Investment in oil and gas properties (54,126) (64,324) (66,678)
Sale of oil and gas properties, net - 17,321 -
-------- -------- --------
Net cash used in investing activities (54,126) (47,003) (66,678)
-------- -------- --------
Cash flows from financing activities:
Exercise of options and warrants 2,111 178 671
Proceeds from borrowing 39,600 23,000 28,000
Repayment of debt (21,100) (47,329) (9,348)
Issuance of common stock, net of expenses (6) 42,050 -
-------- -------- --------
Net cash provided by financing activities 20,605 17,899 19,323
-------- -------- --------
Net increase (decrease) in cash and cash equivalents (358) 74 (6,486)
Cash and cash equivalents balance beginning of period 1,137 1,063 7,549
-------- -------- --------
Cash and cash equivalents balance end of period $ 779 $ 1,137 $ 1,063
======== ======== ========
Supplentmental disclosure of cash flow information
Cash paid during the period from:
Interest $ 435 $ 736 $ 1,464
======== ======== ========
Income taxes $ - $ - $ -
======== ======== ========
See accompanying Notes to Consolidated Financial Statements.
F-7
PETROQUEST ENERGY, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PetroQuest Energy, Inc. (a Delaware Corporation) ("PetroQuest" or the
"Company") is an independent oil and gas company headquartered in Lafayette,
Louisiana with 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.
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.
Certain reclassifications of amounts previously reported have been made to
conform to current year presentations.
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). The Company has adopted a SEC accepted method of
calculating the full cost ceiling test whereby the liability recognized under
SFAS 143 is netted against property cost and the future abandonment obligations
are included in estimated future net cash flows. Transactions involving sales of
reserves in place, unless significant, are recorded as adjustments to
accumulated depreciation, depletion and amortization.
Upon the acquisition or discovery of oil and gas properties, management
estimates the future net costs to be incurred to dismantle, abandon and restore
the property using geological, engineering and regulatory data available. Such
cost estimates are periodically updated for changes in conditions and
requirements. Such estimated amounts are considered 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.
In June 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 141, "Business Combinations," which requires the use of the purchase
method of accounting for business combinations initiated after June 30, 2001 and
eliminates the pooling-of-interests method. In July 2001, the FASB also issued
SFAS No. 142, "Goodwill and Other Intangible Assets," which discontinues the
practice of amortizing goodwill and indefinite lived intangible assets and
initiates an annual review of impairment. The new standard also requires that,
at a minimum, all intangible assets be aggregated and presented as a separate
line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no
impact on the Company's financial
F-8
position or results of operations. A reporting issue has arisen regarding the
application of certain provisions of SFAS No. 141 and 142 to companies in the
extractive industries, including oil and gas companies. The issue is whether
SFAS No. 142 requires registrants to classify the costs of mineral rights
associated with extracting oil and gas as intangible assets in the balance
sheet, apart from other capitalized oil and gas property costs, and provide
specific footnote disclosures. Historically, the Company has included the costs
of mineral rights associated with extracting oil and gas as a component of oil
and gas properties. These costs include those to acquire contract based drilling
and mineral use rights such as delay rentals, lease bonuses, commissions and
brokerage fees, and other leasehold costs. If it is ultimately determined that
SFAS No. 142 requires oil and gas companies to classify these costs as a
separate item on the balance sheet, the Company would be required to reclassify
approximately $27.5-$28.5 million at December 31, 2003 and approximately $5-$6
million at December 31, 2002. The Company's cash flows and results of operations
would not be affected since such intangible assets would continue to be depleted
and assessed for impairment in accordance with full cost accounting rules, as
allowed by SFAS No. 142. Further, the Company believes the classification of the
costs of mineral rights associated with extracting oil and gas as intangible
assets would have an impact on the Company's compliance with the minimum
tangible net worth covenant under its bank credit facility.
PetroQuest will continue to classify its oil and gas leasehold costs as
tangible oil and gas properties until further guidance is provided. The Company
anticipates there will be no effect on its results of operations or cash flows.
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, 2003, 2002 and 2001
were not significant.
Certain Concentrations
During 2003, 84% of the Company's oil and gas production was sold to
five customers. During 2002, 66% of the Company's oil and gas production was
sold to three customers. During 2001, 66% of the Company's oil and gas
production was sold to four customers. Based on the availability of other
customers, the Company does not believe the loss of any of these customers would
have a significant financially disruptive effect on its business or financial
condition.
F-9
Fair Value of Financial Instruments
The fair value of accounts receivable and accounts payable approximate
book value at December 31, 2003 and 2002 due to the short-term nature of these
accounts. The fair value of the credit facilities approximate 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.
The Company recognized ($4,462,000), ($861,000) and $1,630,000 in oil
and gas revenues during the years ended December 31, 2003, 2002 and 2001,
respectively as a result of the settlement of derivatives. The Company
recognized $1,071,000, $558,000 and $61,000 in derivative expense during the
years ended December 31, 2003, 2002 and 2001, respectively as a result of the
settlement of derivatives. As of December 31, 2003, the Company had entered into
the following oil and gas contracts accounted for as cash flow hedges:
INSTRUMENT WEIGHTED
PRODUCTION PERIOD TYPE DAILY VOLUMES AVERAGE PRICE
- ------------------- --------------- ------------- --------------
NATURAL GAS:
2004 Costless Collar 3,700 Mmbtu $ 4.16 - 6.73
First Quarter 2004 Costless Collar 6,800 Mmbtu $ 4.50 - 7.10
Second Quarter 2004 Costless Collar 4,800 Mmbtu $ 4.50 - 5.53
Third Quarter 2004 Costless Collar 2,300 Mmbtu $ 4.50 - 5.49
2005 Swap 750 Mmbtu $ 4.55
2005 Costless Collar 1,500 Mmbtu $ 4.50 - 5.19
2006 Swap 1,500 Mmbtu $ 4.53
CRUDE OIL:
2004 Costless Collar 750 Bbl $25.67 - 29.14
2005 Costless Collar 500 Bbl $23.00 - 26.20
2006 Costless Collar 200 Bbl $23.00 - 26.40
At December 31, 2003, the Company recognized a liability of $1,561,000
related to these derivative instruments.
As of March 5, 2003, we had entered into the following additional oil
and gas contracts accounted for as cash flow hedges:
NATURAL GAS:
March 2004 Costless Collar 4,000 Mmbtu $4.50 - 5.71
Second Quarter 2004 Costless Collar 3,500 Mmbtu $4.50 - 5.73
July - December 2004 Costless Collar 3,000 Mmbtu $4.50 - 6.26
First Quarter 2005 Costless Collar 3,500 Mmbtu $4.50 - 7.05
Second Quarter 2005 Costless Collar 2,500 Mmbtu $4.50 - 5.33
CRUDE OIL:
March-December 2004 Costless Collar 250 Bbl $26.00 - 33.50
The Company currently has an interest rate swap covering $5 million of
our floating rate debt. The swap which expires in 2004 has a fixed interest rate
of 5.665%. The swap is stated at its fair value and is marked-to-market through
derivative expense on the Company's income statement. As of December 31, 2003,
the fair value of the open interest rate swap was a liability of $218,000.
F-10
New Accounting Standards
In June 2001, the Financial Accounting Standards Board issued SFAS 143,
"Accounting for Asset Retirement Obligations," which requires recording the fair
value of an asset retirement obligation associated with tangible long-lived
assets in the period incurred. Retirement obligations associated with long-lived
assets included within the scope of SFAS 143 are those for which there is a
legal obligation to settle under existing or enacted law, statute, written or
oral contract or by legal construction under the doctrine of promissory
estoppel.
The Company adopted SFAS 143 effective January 1, 2003. The net
difference between the Company's previously recorded abandonment liability and
the amounts estimated under SFAS 143, after taxes, totaled a gain of $849,000,
which has been recognized as a cumulative effect of a change in accounting
principle. The gain is due to the effect on the historical depletion as a result
of the retirement obligation being recorded at fair value. On a pro forma basis,
the impact for the year ended December 31, 2002 would have increased net income
by $360,000.
The Company has legal obligations to plug, abandon and dismantle
existing wells and facilities that it has acquired and constructed during its
existence. As of January 1, 2003, the Company recognized a $9,467,000 liability
for its asset retirement obligations and recorded the related additional assets
that will be depreciated using the unit-of-production method. The following
table describes all changes to the Company's asset retirement obligation
liability:
YEAR ENDED
DECEMBER 31, 2003
-----------------
Asset retirement obligation at beginning of year $ -
Liability recognized in transition 9,467,000
Liabilities incurred during 2003 663,000
Liabilities settled during 2003 (389,000)
Accretion expense 682,000
Revisions in estimated cash flows 2,053,000
------------
Asset retirement obligation at end of period $ 12,476,000
============
In January 2003, the Financial Accounting Standards Board issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which requires companies to evaluate variable interest entities to determine
whether to apply the consolidation provisions of FIN 46 to those entities. The
consolidation provisions of FIN 46, if applicable, would apply to variable
interest entities created after January 31, 2003 immediately, and to variable
interest entities created before February 1, 2003 in the Company's interim
period beginning October 1, 2003. The Company believes that it has no interests
in these types of entities.
Earnings per Common Share Amounts
Basic earnings 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 per common share is determined on a weighted average
basis using common shares issued and outstanding adjusted for the effect of
stock options considered common stock equivalents computed using the treasury
stock method.
Options and warrants to purchase 3,385,334 shares of common stock at
$2.29 to $7.65 per share were outstanding during 2003 but were not included in
the computation of diluted earnings per share because the options' and warrants'
exercise prices were greater than the average market price of the common shares.
Options to purchase 273,667 shares of common stock at $5.56 to $7.65 per share
were outstanding during 2002 but were not included in the computation of diluted
earnings per share because the options' exercise prices were greater than the
average market price of the common shares. Options to purchase
F-11
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.
Stock-based Compensation
The Company accounts for its stock-based compensation plans under the
principles prescribed by the Accounting Principles Board's Opinion No. 25,
"Accounting for Stock Issued to Employees." No stock option compensation cost is
reflected in net income, as all options granted under the plan had an exercise
price equal to the market value of the underlying common stock on the date of
grant. The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of SFAS
No. 123, "Accounting for Stock Based Compensation" pursuant to the disclosure
requirements of SFAS No. 148, "Accounting for Stock-Based Compensation -
Transition and Disclosure" (in thousands, except per share data):
YEAR ENDED DECEMBER 31,
------------------------------
2003 2002 2001
------- ------- --------
Net income $ 3,640 $ 2,307 $ 11,645
Stock-based compensation:
Add: expense included in reported results, net of tax 248 224 497
Deduct: fair value based method, net of tax (541) (904) (1,260)
------- ------- --------
Pro forma net income $ 3,347 $ 1,627 $ 10,882
Earnings per common share
Basic - as reported $ 0.08 $ 0.06 $ 0.37
Basic - pro forma $ 0.08 $ 0.04 $ 0.34
Diluted - as reported $ 0.08 $ 0.06 $ 0.34
Diluted - pro forma $ 0.08 $ 0.04 $ 0.32
See Note 10 for the Company's additional disclosures of stock-based
compensation under SFAS No. 148.
NOTE 2 - ACQUISITION AND DISPOSITION OF ASSETS
On December 23, 2003, the Company acquired an interest in the Southeast
Carthage Field in East Texas for approximately $23.4 million. The Company
allocated approximately $1.2 million of the purchase price to unevaluated
acreage. At December 31, 2003, the Company's independent reservoir engineering
firm attributed 29 Bcfe of proved reserves net to the Company's interest in this
field.
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. Consistent with the full cost method of accounting, the
Company did not recognize any gain or loss as a result of this sale. The
proceeds were treated as a reduction of the full cost pool through an increase
in accumulated depreciation, depletion and amortization.
F-12
NOTE 3 - EQUITY
Other Comprehensive Income
The following table presents a recap of the Company's comprehensive
income for years ended December 31, 2003 and 2002 (in thousands):
YEAR ENDED DECEMBER 31,
-----------------------
2003 2002
------ --------
Net income $3,640 $ 2,307
Change in fair value of derivative instrument,
accounted for as hedges, net of taxes 182 (1,197)
------ -------
Comprehensive income $3,822 $ 1,110
The Company accounts for derivatives in accordance with Statement of Financial
Accounting Standards No. 133, as amended (SFAS 133). When the conditions
specified in SFAS 133 are met, the Company may designate these derivatives as
hedges. At December 31, 2003 and 2002, the effect of derivative financial
instruments is net of deferred income tax benefit of $546,000 and $644,000,
respectively.
Unearned Deferred Compensation
In April 2001, the Original Owners of American Explorer L.L.C. entered
into an agreement with an officer of the Company whereby the Original Owners
granted to the officer an option to acquire, at a fixed price, certain of the
original shares the Original Owners were issued in the Merger. As the fixed
price of the April grant was below the market price as of the date of grant, the
Company is recognizing non-cash compensation expense over the three-year vesting
period of the option. In addition, the Original Owners granted to the officer an
interest in a portion of the Common Stock issuable pursuant to the Contingent
Stock Issue Rights ("CSIRs"), if any, that might be issued. This agreement is
similar to agreements previously entered into with two other officers of the
Company. Non-cash compensation expense is being recognized for the Common Stock
issuable pursuant to the CSIRs granted to the three officers over the three-year
vesting period based on the fair value of the Common Stock issuable pursuant to
the CSIRs in May 2001, when the Common Stock issuable pursuant to the CSIRs was
issued to the Original Owners. The Company has recorded the effects of the
transactions as deferred compensation until fully amortized. We recognized
$381,000, $345,000 and $765,000, respectively of non-cash compensation expense
during the years ended December 31, 2003, 2002 and 2001.
Common Stock Issue Rights
Pursuant to a Company merger, the Company issued to the original owners
of American Explorer L.L.C. and their respective affiliates, certain of whom
currently serve as officers and directors of the Company, 7,335,001 shares of
the Company's common stock, par value $.001 per share (the "Common Stock"), and
1,667,001 CSIRs. The CSIRs entitled the holders to receive an additional
1,667,001 shares of Common Stock at such time within three years of the
anniversary date of the issuance of the CSIRs if the trading price for the
Common Stock closed at $5.00 or higher for 20 consecutive trading days. On May
3, 2001 the Common Stock closed higher than $5.00 for the twentieth consecutive
trading day, and 1,667,001 shares of Common Stock were issued under the terms of
the CSIRs.
NOTE 4 - DEBT
The Company entered into a bank credit facility on May 14, 2003.
Pursuant to the new credit facility agreement, PetroQuest and our subsidiary
PetroQuest Energy, L.L.C. (the "Borrower") have a $75 million revolving credit
facility which permits the Borrower to borrow amounts from time to time based on
its available borrowing base as determined in the bank credit facility. The bank
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 the bank credit facility is based upon the valuation as of
April 1 and October 1 of each year of the Borrower's mortgaged properties,
projected oil and gas prices, and any other factors deemed relevant by the
lenders. The Company or the lenders may also request additional borrowing base
redeterminations. As of December 31, 2003, the borrowing base under the bank
credit facility was $20.2 million and is subject to monthly reductions of $1
million commencing March 1, 2004. The Company has recently completed a borrowing
base redetermination as of March 1, 2004, and the
F-13
borrowing base is $21.2 million and subject to monthly reductions of $1.25
million commencing on July 1, 2004. The banks will determine future monthly
reductions in connection with each borrowing base redetermination.
Outstanding balances on the revolving credit facility bear interest at
either the bank's prime rate plus a margin (based on a sliding scale of 0.75% to
1.25% based on borrowing base usage but never less than the Federal Funds
Effective Rate plus 0.5%) or the Eurodollar rate plus a margin (based on a
sliding scale of 2.0% to 2.5% depending on borrowing base usage). The bank
credit facility also allows the Company to use up to $5 million of the borrowing
base for letters of credit for fees equal to the applicable margin rate for
Eurodollar advances. At March 5, 2004, the Company had $15.5 million of
borrowings and no letters of credit issued pursuant to the bank credit facility.
The Company is subject to certain restrictive financial and
non-financial covenants under the bank credit facility, including a minimum
current ratio of 1.0 to 1.0, all as defined in the credit facility agreement.
The bank credit facility also requires the Borrower to establish and maintain
commodity hedges covering at least 50% of its proved developed producing
reserves on a rolling twelve-month basis. As of December 31, 2003, the Company
was in compliance with all of the covenants in the bank credit facility. The
bank credit facility matures on May 14, 2006.
On November 6, 2003, the Company obtained a $20 million subordinated
term credit facility from Macquarie Americas Corp. ("Macquarie"). The sub-debt
facility carries an interest rate of prime plus 5.5%, is secured by a second
mortgage on substantially all of our oil and gas properties and matures November
30, 2006. The sub-debt facility is available for advances at any time until
December 31, 2004 subject to the restrictive covenants of the sub-debt facility
and Macquarie approval. At closing, Macquarie received warrants to purchase
1,250,000 shares of our common stock at an exercise price of $2.30 per share.
When cumulative advances under the facility exceeded $5 million, $10 million and
$15 million, Macquarie was to receive warrants to purchase an additional 250,000
shares, 500,000 shares and 250,000 shares of our common stock, respectively, at
the same exercise price per share. In conjunction with the December 23, 2003
property acquisition, the sub-debt facility was amended and the original warrant
was cancelled and reissued at which time all 2,250,000 warrants were issued to
Macquarie. The warrants are exercisable at any time through the earlier of 36
months following the repayment in full of the sub-debt facility or 30 days after
daily volume weighted average price of our common stock as published by Nasdaq
is equal to or greater than, for a period of 30 days, the exercise price
multiplied by three. In addition, the Company granted Macquarie piggy-back
registration rights with respect to the shares of common stock issuable upon
exercise of the warrants.
As of December 31, 2003, the Company had $12 million borrowed under the
sub-debt facility which was primarily used to fund the acquisition of properties
in the Southeast Carthage Field. The sub-debt facility, as amended, contains
certain restrictive financial and non-financial covenants, including a minimum
current ratio of 1.0 to 1.0, a total debt threshold of $45 million and a
cumulative minimum production and net operating cash flow threshold, all as
defined in the sub-debt facility. The sub-debt facility also requires the
Company to establish and maintain commodity hedges covering at least 65% of its
proved developed producing reserves through November 2006. As of December 31,
2003, the Company was in compliance with all of the covenants in the sub-debt
facility.
During January 2004, the sub-debt facility, including the note, liens,
warrants and all other rights of Macquarie thereunder, was assigned to Macquarie
Bank Limited, an affiliate of Macquarie Americas Corp.
NOTE 5 - RELATED PARTY TRANSACTIONS
Charles T. Goodson, Ralph J. Daigle, Stephen H. Green, or their
affiliates, are working interest owners and overriding interest owners and E.
Wayne Nordberg is a working interest owner in particular properties operated by
us or in which we also hold a working interest. As working interest owners, they
are required to pay their proportionate share of all costs and are entitled to
receive their proportionate share of revenues in the normal course of business.
As overriding royalty interest owners they are entitled to receive their
proportionate share of revenues in the normal course of business. During the
year ended December 31, 2003, in their capacities as working interest owners or
overriding royalty interest owners, revenues, net of costs were disbursed to
Messrs. Goodson, Daigle, and Green, or their affiliates, in the approximate
amounts of $841,350, $481,276, and $107,367, respectively, and with respect to
the working interests of Mr. Nordberg, costs exceeded revenues by approximately
$89,225. With respect to Messrs. Goodson and Daigle, or their affiliates, gross
revenues attributable to interests, properties or participation rights held by
them prior to Messrs. Goodson and Daigle joining us as officers and directors on
September 1, 1998 represent approximately 94% and 90%, respectively, of the
gross revenues received by them in 2003.
F-14
NOTE 6 - COMMON STOCK
During October and November 2002, the Company completed the offering of
5,000,000 shares of its common stock. The shares were sold to the public for
$4.25 per share. After underwriting discounts, the Company realized proceeds of
approximately $20.4 million.
During February and March 2002, the Company completed the offering of
5,193,600 shares of its common stock. The shares were sold to the public for
$4.40 per share. After underwriting discounts, the Company realized proceeds of
approximately $21.9 million.
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,
2003 2002 2001
------- ------- -------
Acquisition costs:
Proved $22,679 $ 1,023 $11,928
Unproved 1,769 6,052 1,250
Exploration costs 5,170 16,183 7,280
Development costs 21,685 37,247 43,424
Cumulative effect of change in accounting principle costs 8,150 - -
Other costs 4,062 4,283 3,652
------- ------- -------
Total costs incurred $63,515 $64,788 $67,534
======= ======= =======
Proved acquisition costs, Development costs and Cumulative effect of
change in accounting principle costs for the year ended December 31, 2003
include $362,000, $1,966,000 and $8,150,000, respectively of non-cash property
costs related to the adoption of SFAS 143 effective January 1, 2003. See Note 2
for a further discussion of the adoption of this accounting standard.
Other costs for the year ended December 31, 2003 include $3,611,000 and
$451,000 of capitalized general and administrative costs and interest costs,
respectively. Other costs for the year ended December 31, 2002 include
$3,664,000 and $619,000 of capitalized general and administrative costs and
interest costs, respectively. Other costs for the year ended December 31, 2001
include $2,651,000 and $1,001,000 of capitalized general and administrative
costs and interest costs, respectively.
At December 31, 2003 and 2002, unevaluated oil and gas properties with
capitalized costs of $10,813,000 and $15,653,000, respectively, were not subject
to depletion. Of the $10,813,000 of unevaluated oil and gas property costs at
December 31, 2003, not subject to depletion, $2,372,000 was incurred in 2003,
$4,091,000 was incurred in 2002 and $4,350,000 was incurred in prior years. Of
the $15,653,000 of unevaluated oil and gas property costs at December 31, 2002,
not subject to depletion, $6,730,000 was incurred in 2002, $3,932,000 was
incurred in 2001 and $4,991,000 was incurred in prior years. Management expects
that these properties will be evaluated over the next one to three years.
F-15
NOTE 8 - INCOME TAXES
The Company follows the provisions of SFAS No. 109, "Accounting For
Income Taxes," which provides for recognition of a deferred tax asset for
deductible temporary timing differences, operating loss carryforwards, statutory
depletion carryforwards and tax credit carryforwards net of a "valuation
allowance." An analysis of the Company's deferred taxes follows (amounts in
thousands):
DECEMBER 31,
--------------------
2003 2002
-------- --------
Net operating loss carryforwards $ 7,659 $ 13,829
Percentage depletion carryforward 1,341 1,291
Alternative minimum tax credit 4 4
Deferred Compensation (355) (258)
Temporary differences:
Oil and gas properties - full cost (17,151) (21,126)
Derivative mark to market 546 644
Compensation expense 153 153
-------- --------
$ (7,803) $ (5,463)
======== ========
For tax reporting purposes, the Company had operating loss
carryforwards of $20,590,000 and $37,376,000 at December 31, 2003 and 2002,
respectively. If not utilized, such carryforwards would begin expiring in 2009
and would completely expire by the year 2023. The Company had available for tax
reporting purposes $3,832,000 in statutory depletion deductions that may be
carried forward indefinitely.
Income tax expense for each of the years ended December 31, 2003, 2002
and 2001 (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,
-------------------------------
2003 2002 2001
------- ------- -------
Amount computed using the statutory rate $ 1,568 $ 1,258 $ 5,970
Increase (reduction) in taxes resulting from:
State & local taxes 99 79 341
Percentage depletion carryforward (50) (129) (720)
Other 73 80 (180)
------- ------- -------
Income tax expense $ 1,690 $ 1,288 $ 5,411
======= ======= =======
NOTE 9 - COMMITMENTS AND CONTINGENCIES
On December 10, 2003, our wholly owned subsidiary, PetroQuest Energy,
L.L.C. ("PetroQuest Energy") entered into a settlement agreement with The
Meridian Resource & Exploration LLC relating to the litigation "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" and "The Meridian Resource & Exploration Company v.
PetroQuest Energy, Inc., bearing Docket No. 996192A of the 15th Judicial
District Court in and for Lafayette Parish, Louisiana" which related to our
Southwest Holmwood property in Calcasieu Parish, Louisiana.
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.
F-16
LEASE COMMITMENTS
The Company has operating leases for office space, which expire on
various dates through 2010.
Future minimum lease commitments as of December 31, 2003 under these
operating leases are as follows (in thousands):
2004 ........... $ 741
2005 ........... 806
2006 ........... 744
2007 ........... 703
2008 ........... 699
Thereafter ..... 1,362
------
5,055
Total rent expense under operating leases was approximately $639,000,
$577,000 and $411,000 in 2003, 2002 and 2001, 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, 2003, 2002
and 2001 and changes during the years ended on those dates is presented below:
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------
2003 2002 2001
----------------------- ------------------------ -----------------------
NUMBER OF WGTD. AVG. NUMBER OF WGTD. AVG. NUMBER OF WGTD. AVG.
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
----------- ---------- ----------- ---------- ----------- ----------
Outstanding at beginning of year 2,197,353 $ 3.14 2,238,766 $ 2.94 1,861,900 $ 1.92
Granted 150,000 1.94 112,000 6.17 622,500 5.32
Expired/cancelled/forfeitures (235,253) 3.76 (66,910) 3.75 (14,500) 6.17
Exercised (42,466) 1.23 (86,503) 1.44 (231,134) 0.89
----------- ---------- ----------- ---------- ----------- ----------
Outstanding at end of year 2,069,634 3.03 2,197,353 3.14 2,238,766 2.94
Options exercisable at year-end 1,690,371 2.77 1,453,166 2.36 1,030,608 1.64
Options available for future grant 1,359,069 770,208 268,081
Weighted average fair value of
options granted during the year $ 1.18 $ 3.93 $ 3.18
The fair value of each option granted during the periods presented is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions: (a) divided yield of 0% (b) expected volatility
ranges of 69.90%-73.90%, 74.50%-74.90% and 65.14% - 67.87% in 2003, 2002 and
2001, respectively (c) risk-free interest rate ranges of 2.93% - 3.39%, 4.17% -
4.54% and 4.03% - 5.10% in 2003, 2002 and 2001, respectively, and (d) expected
life of 5 years for all grants.
F-17
The following table summarizes information regarding stock options
outstanding at December 31, 2003:
RANGE OF OPTIONS WGTD. AVG. WGTD. AVG. OPTIONS WGTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICE AT 12/31/03 CONTRACTUAL LIFE PRICE AT 12/31/03 PRICE
- ------------- ----------- ---------------- ---------- ----------- ----------
$0.85 - $0.94 384,300 5 years $ 0.89 384,300 $ 0.89
$1.44 - $2.29 575,000 7.52 years $ 1.73 425,000 $ 1.66
$3.13 - $3.75 562,500 7.11 years $ 3.19 542,502 $ 3.17
$4.25 - $7.65 547,834 8.15 years $ 5.71 338,569 $ 5.64
--------- ---------
2,069,634 7.11 years $ 3.03 1,690,371 $ 2.77
NOTE 11 - OIL AND GAS RESERVE INFORMATION - UNAUDITED
The Company's net proved oil and gas reserves at December 31, 2003 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-18
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 GAS
IN AND NGL IN
MBBLS MMCFE
------ -----------
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
Revisions of previous estimates (1,204) (8,955)
Extensions, discoveries and other additions 1,438 19,453
Purchase of producing properties - -
Sale of producing properties (260) (10,540)
Production (929) (7,765)
------ ------
Proved reserves as of December 31, 2002 5,258 37,137
Revisions of previous estimates (369) (7,935)
Extensions, discoveries and other additions 83 6,830
Purchase of producing properties 217 28,410
Sale of producing properties (200) (1,456)
Production (744) (5,193)
------ ------
Proved reserves as of December 31, 2003 4,245 57,793
====== ======
Proved developed reserves
As of December 31, 2001 3,104 26,847
====== ======
As of December 31, 2002 4,201 17,409
====== ======
As of December 31, 2003 3,446 34,655
====== ======
F-19
The following tables (amounts in thousands) present the standardized
measure of future net cash flows related to proved oil and gas reserves together
with changes therein, as defined by the FASB. Future production and development
costs are based on current costs with no escalations. Estimated future cash
flows have been discounted to their present values based on a 10% annual
discount rate.
DECEMBER 31,
-----------------------------------
2003 2002 2001
--------- --------- ---------
STANDARD MEASURE
Future cash flows $ 460,073 $ 337,776 $ 234,736
Future production and development costs (166,724) (120,842) (118,700)
Future income taxes (53,514) (36,687) (18,226)
--------- --------- ---------
Future net cash flows 239,835 180,247 97,810
10% annual discount (64,609) (40,831) (22,763)
--------- --------- ---------
Standardized measure of discounted future net cash flows $ 175,226 $ 139,416 $ 75,047
========= ========= =========
YEAR ENDED DECEMBER 31,
----------------------------------=
2003 2002 2001
--------- --------- ---------
CHANGES IN STANDARDIZED MEASURE
Standarized measure at beginning of year $ 139,416 $ 75,047 $ 178,323
Sales and transfers of oil and gas produced,
net of production costs (37,577) (38,400) (45,068)
Changes in price, net of future production costs 23,007 78,648 (188,513)
Extensions and discoveries, net of future
production and development costs 38,883 83,005 33,067
Changes in estimated future development costs,
net of development costs incurred during this period 10,577 19,059 16,333
Revisions of quantity estimates (35,796) (56,166) (7,742)
Accretion of discount 16,605 8,823 25,687
Net change in income taxes (12,507) (13,448) 65,361
Purchase of reserves in place 40,605 - 12,730
Sale of reserves in place (3,802) (12,899) (864)
Changes in production rates (timing) and other (4,185) (4,253) (14,267)
--------- --------- ---------
Standardized measure at end of year $ 175,226 $ 139,416 $ 75,047
========= ========= =========
The weighted average prices of oil and gas used with the above tables
at December 31, 2003, 2002 and 2001 were $32.24, $30.44 and $18.49,
respectively, per barrel and $6.02, $4.79 and $2.69, respectively, per Mcf. The
Company's cash flow amounts include a reduction for estimated plugging and
abandonment costs that will also be reflected as a liability on PetroQuest's
balance sheet at December 31, 2003, in accordance with SFAS No. 143.
F-20
NOTE 12 - 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
-------- -------- ------------ -----------
2003:
Revenues $ 16,164 $ 9,101 $ 9,857 $ 13,566
Expenses 14,020 10,799 9,628 11,450
-------- -------- -------- --------
Income before cumulative effect of change in
accounting principle $ 2,144 $ (1,698) $ 229 $ 2,116
Net income (loss) $ 2,993 $ (1,698) $ 229 $ 2,116
======== ======== ======== ========
Earnings per common share:
Basic
Income before cumulative effect of
change in accounting principle $ 0.05 $ (0.04) $ 0.01 $ 0.05
Net income $ 0.07 $ (0.04) $ 0.01 $ 0.05
Diluted
Income before cumulative effect of
change in accounting principle $ 0.05 $ (0.04) $ 0.01 $ 0.05
Net income $ 0.07 $ (0.04) $ 0.01 $ 0.05
2002:
Revenues $ 10,497 $ 11,102 $ 11,024 $ 15,057
Expenses 10,861 10,847 10,074 13,591
-------- -------- -------- --------
Net income (loss) $ (364) $ 255 $ 950 $ 1,466
======== ======== ======== ========
Earnings (loss) per share:
Basic $ (0.01) $ 0.01 $ 0.03 $ 0.04
Diluted $ (0.01) $ 0.01 $ 0.02 $ 0.03
- ----------
(1) The above quarterly earnings per share may not total to the full year
per share amount, as the weighted average number of shares outstanding
for each quarter fluctuated as a result of the assumed exercise of
stock options.
F-21
EXHIBIT INDEX
2.1 Plan and Agreement of Merger by and among Optima Petroleum Corporation,
Optima Energy (U.S.) Corporation, its wholly-owned subsidiary, and
Goodson Exploration Company, NAB Financial L.L.C., Dexco Energy, Inc.,
American Explorer, L.L.C. (incorporated herein by reference to Appendix
G of the Proxy Statement on Schedule 14A filed July 22, 1998).
3.1 Certificate of Incorporation of the Company (incorporated herein by
reference to Exhibit 4.1 to Form 8-K dated September 16, 1998)
3.2 Bylaws of the Company (incorporated herein by reference to Exhibit 4.2
to Form 8-K dated September 16, 1998).
3.3 Certificate of Domestication of Optima Petroleum Corporation
(incorporated herein by reference to Exhibit 4.4 to Form 8-K dated
September 16, 1998).
3.4 Certificate of Designations, Preferences, Limitations And Relative
Rights of The Series a Junior Participating Preferred Stock of
PetroQuest Energy, Inc. (incorporated herein by reference to Exhibit A
of the Rights Agreement attached as Exhibit 1 to Form 8-A filed
November 9, 2001).
4.1 Warrant to Purchase Common Shares of PetroQuest Energy, Inc.
(incorporated by reference to Exhibit 4.1 to Form 8-K filed December
29, 2003
4.2 Rights Agreement dated as of November 7, 2001 between PetroQuest
Energy, Inc. and American Stock Transfer & Trust Company, as Rights
Agent, including exhibits thereto (incorporated herein by reference to
Exhibit 1 to Form 8-A filed November 9, 2001).
4.3 Form of Rights Certificate (incorporated herein by reference to Exhibit
C of the Rights Agreement attached as Exhibit 1 to Form 8-A filed
November 9, 2001).
10.1 PetroQuest Energy, Inc. 1998 Incentive Plan, as amended and restated
effective December 1, 2000 (incorporated herein by reference to
Appendix A to Proxy Statement on Schedule 14A filed April 20, 2001).
10.2 Amended and Restated Credit Agreement, dated as of May 14, 2003, by and
between PetroQuest Energy, LLC, PetroQuest Energy, Inc., Bank One, NA,
Banc One Capital Markets, Inc., and certain other Lenders (incorporated
herein by reference to Exhibit 10.1 to Form 10-Q filed August 13,
2003).
10.3 Guaranty dated May 14, 2003, between PetroQuest Energy, Inc. and Bank
One, NA, as Agent for the Lenders (incorporated herein by reference to
Exhibit 10.2 to Form 10-Q filed August 13, 2003).
10.4 First Amendment to Amended and Restated Credit Agreement dated as of
November 6, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc.; Bank One, N.A., and Union Bank of California, N.A.
(incorporated herein by reference to Exhibit 10.4 to Form 10-Q filed
November 13, 2003).
10.5 Second Amendment to Amended and Restated Credit Agreement dated as of
December 23, 2003, by and among PetroQuest Energy, L.L.C., PetroQuest
Energy, Inc., and Bank One, N.A. (incorporated herein by reference to
Exhibit 10.2 to Form 8-K filed December 29, 2003).
10.6 Senior Second Lien Secured Credit Agreement dated November 6, 2003,
between PetroQuest Energy, L.L.C., PetroQuest Energy, Inc., each of the
Lenders from time to time party thereto; and Macquarie Americas Corp.,
as administrative agent for the Lenders (incorporated herein by
reference to Exhibit 10.1 to Form 10-Q filed November 13, 2003).
10.7 Unconditional Guaranty Agreement dated November 6, 2003, by PetroQuest
Energy, Inc. to Macquarie Americas Corp., as administrative agent for
the benefit of the Lenders under the Credit Agreement (incorporated
herein by reference to Exhibit 10.2 to Form 10-Q filed November 13,
2003).
10.8 First Amendment To Second Lien Secured Credit Agreement dated December
23, 2003, among PetroQuest Energy, L.L.C., PetroQuest Energy, Inc.,
each of the Lenders from time to time party thereto, and Macquarie
Americas Corp., as administrative agent for the Lenders (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed December 29,
2003).
10.9 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).
10.10 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).
10.11 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)
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 Employment Agreement dated April 20, 2001 between PetroQuest Energy,
Inc. and Dalton F. Smith III (incorporated herein by reference to
Exhibit 10.21 to Form 10-K filed March 13, 2002).
10.17 Employment agreement dated July 28, 2003, between PetroQuest Energy,
Inc. and Stephen H. Green (incorporated herein by reference to Exhibit
10.3 to Form 10-Q filed November 13, 2003).
10.18 Form of Termination Agreement Between PetroQuest Energy, Inc. and each
of its executive officers, including Charles T. Goodson, Ralph J.
Daigle, Michael O. Aldridge, Arthur M. Mixon, III, Daniel G. Fournerat,
Dalton F. Smith III and Stephen H. Green (incorporated herein by
reference to Exhibit 10.20 to Form 10-K filed March 13, 2002).
10.19 Form of Indemnification Agreement between PetroQuest Energy, Inc. and
each of its directors and executive officers, including Charles T.
Goodson, Ralph J. Daigle, Daniel G. Fournerat, E. Wayne Nordberg,
William W. Rucks, IV, Michael O. Aldridge, Arthur M. Mixon, III, Dalton
F. Smith III, Michael L. Finch, W.J. Gordon, III and Stephen H. Green
(incorporated herein by reference to Exhibit 10.21 to Form 10-K filed
March 13, 2002).
*14.1 Business Ethics Policy
21.1 Subsidiaries of the Company (incorporated herein by reference to
Exhibit 21.1 to Form 10-K filed March 30, 2001).
*23.1 Consent of Independent Auditors.
23.2 Consent of Arthur Andersen LLP (omitted pursuant to Rule 437a under
the Securities Act of 1933, as amended).
*23.3 Consent of Ryder Scott Company, L.P.
*31.1 Certification of Chief Executive Officer pursuant to Rule 13-a-14(a) /
Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934,
as amended.
*31.2 Certification of Chief Financial Officer pursuant to Rule 13-a-14(a) /
Rule 15d-14(a), promulgated under the Securities Exchange Act of 1934,
as amended.
*32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Executive
Officer.
*32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, of Chief Financial
Officer.
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* Filed herewith.