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

FORM 10-K

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

For the fiscal year ended December 31, 2001

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

Commission File Number: 1-12074

STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

State of incorporation: Delaware I.R.S. Employer Identification No. 72-1235413

625 E. Kaliste Saloom Road
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (337) 237-0410

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange
Title of each class on which registered
------------------- ---------------------
Common Stock, Par Value $.01 Per Share New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

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

[x] Yes [ ] No

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

The aggregate market value of the voting stock held by non-affiliates of
the registrant was approximately $858,410,004 as of March 15, 2002 (based on the
last reported sale price of such stock on the New York Stock Exchange Composite
Tape).

As of March 15, 2002, the registrant had outstanding 26,271,252 shares of
Common Stock, par value $.01 per share.

Document incorporated by reference: Portions of the Definitive Proxy
Statement of Stone Energy Corporation relating to the Annual Meeting of
Stockholders to be held on May 16, 2002 is incorporated by reference into Part
III of this Form 10-K.
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TABLE OF CONTENTS

Page No.

PART I

Item 1. Business........................................................ 3

Item 2. Properties...................................................... 16

Item 3. Legal Proceedings............................................... 19

Item 4. Submission of Matters to a Vote of Security Holders............. 19

Item 4A. Executive Officers of the Registrant............................ 19

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters......................................... 20

Item 6. Selected Financial Data......................................... 21

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk...... 27

Item 8. Financial Statements and Supplementary Data..................... 29

Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................... 29

PART III

Item 10. Directors and Executive Officers of the Registrant.............. 29

Item 11. Executive Compensation.......................................... 29

Item 12. Security Ownership of Certain Beneficial Owners and Management.. 29

Item 13. Certain Relationships and Related Transactions.................. 29

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K..................................................... 30

Index to Financial Statements................................... F-1

Glossary of Certain Industry Terms.............................. G-1

PART I

Where specifically indicated, throughout this Form 10-K, we show combined
operational and financial information to give effect to our merger with Basin
Exploration, which was consummated on February 1, 2001 and was accounted for as
a pooling-of-interests, as if the two companies were combined at the beginning
of the earliest period presented. These combined results should be used for
information purposes only as they are not necessarily indicative of the results
that would have occurred if the merger had been completed at the beginning of
the earliest period presented.

This section highlights information that is discussed in more detail in the
remainder of the document. Throughout this document we make statements that are
classified as "forward-looking." Please refer to the "Forward-Looking
Statements" section beginning on page 8 of this document for an explanation of
these types of statements. We use the terms "Stone", "Stone Energy", "company",
"we", "us" and "our" to refer to Stone Energy Corporation. We use the terms
"Basin" and "Basin Exploration" to refer to Basin Exploration, Inc. The terms
"merger" and "combined company" are used to refer to the combination of Stone
Energy and Basin Exploration. The term "Conoco acquisition" is used to refer to
the acquisition of oil and gas properties and related assets from Conoco, Inc.
in December 2001. Certain terms relating to the oil and gas industry are defined
in "Glossary of Certain Industry Terms", which begins on page G-1 of this Form
10-K.

ITEM 1. BUSINESS

STRATEGY AND OPERATIONAL OVERVIEW

Stone Energy is a leading, Gulf Coast Basin-focused independent oil and gas
company engaged in the acquisition and subsequent exploration, development,
production and operation of oil and gas properties. The Gulf of Mexico is a
critical supply basin for the United States, accounting for approximately 25% of
the total U.S. oil and gas production in 2000. Properties located in the Gulf of
Mexico are typically on 5,000-acre lease blocks and afford a substantial area to
explore away from and beneath established production. We have been active in the
Gulf Coast Basin since 1973 and have established extensive geological,
geophysical, technical and operational expertise in this area. The application
of these core strengths, combined with our detailed and thorough approach to
evaluating mature fields and our utilization of new drilling, seismic and
completion technologies, has enabled us to successfully exploit and derive
significant value from mature Gulf Coast Basin oil and gas properties. Our
property portfolio consists of 55 active properties and 39 primary term leases
in the Gulf Coast Basin and 32 active properties in the Rocky Mountains.

Our business strategy, which has remained consistent since 1990, is to
increase reserves, production and cash flow through the acquisition,
exploitation and development of mature properties located primarily in the Gulf
Coast Basin. During 2001, we grew proved reserves, production and cash flow from
operations, as compared to our pre-merger 2000 results, by 94%, 39% and 44%,
respectively. Approximately 94% of our estimated proved reserves at December 31,
2001 and 96% of our production during 2001 were associated with our Gulf Coast
Basin properties. As of December 31, 2001, we had estimated proved reserves of
775 billion cubic feet of gas equivalent (Bcfe), 79% of which were classified as
proved developed and 57% of which were natural gas. For the year ended December
31, 2001, we produced an average of 253.1 million cubic feet of gas equivalent
per day (MMcfe/d), 74% of which was natural gas. During 2001, we generated cash
flow from operations before working capital changes of $286.8 million.

We apply the latest production techniques and geophysical interpretation
tools to established fields with significant historical production that have
been under-evaluated in recent years. We have grown our opportunity base through
both the drillbit and selective acquisitions, implementing a conservative
financial strategy that incorporates a combination of internal cash flow, equity
issuance and indebtedness to fund our acquisition and exploitation activities.
While we have acquired substantially all of our properties from third parties,
we have generated significant organic growth in reserves, production and
prospect inventory subsequent to acquisition. We believe significant reserves
remain to be discovered and exploited on properties that satisfy our acquisition
criteria as the focus of oil and gas companies shifts over time. We also believe
that we are well positioned to exploit these reserves by applying our technical
expertise and our thorough, consistent and patient approach in the evaluation
and acquisition of these properties.

We seek to acquire properties that have the following characteristics:

o primarily Gulf Coast Basin location;

o mature properties with an established production history
and infrastructure;

o multiple productive sands and reservoirs;

o low production levels at acquisition with significant identified proven
and potential reserves; and

o opportunity for us to obtain a controlling interest and serve as
operator.

Our approach to evaluating mature fields in the Gulf Coast Basin involves a
combination of techniques designed to generate opportunities and unlock value.
By using the extensive production history and data accumulated on properties in
the Gulf Coast Basin, our highly experienced technical teams construct an
interpretation of a field's unique geology to gain a better understanding of the
potential location of previously untested or unexploited oil and gas
accumulations. Using our interpretations, we are frequently able to combine
development and exploratory targets in a single well to improve the chance of
investment success. Since 1993, excluding Basin's drilling results prior to our
merger; we have achieved a 72% drilling success rate.

Prior to acquiring a property, we perform a thorough geological,
geophysical and engineering analysis of the property to formulate a
comprehensive development plan. To formulate this plan, we utilize the expertise
of our technical team of 17 geologists, 16 geophysicists and 23 engineers. We
also employ our extensive technical database, which includes 3-D seismic data on
all of our current properties and some of the properties that we are evaluating
for acquisition. After acquisition, we seek to increase cash flow from existing
reserves and to establish additional proved reserves through the drilling of new
wells, workovers and recompletions of existing wells and the application of
other techniques designed to increase production.

FINANCIAL OVERVIEW

We completed our initial public offering of common stock in July 1993 and
our shares are listed on the New York Stock Exchange under the ticker symbol
"SGY". Additional offerings of common stock were completed in November 1996 and
July 1999. We have maintained consistent, profitable growth since our initial
public offering in 1993. We have generated net income in all calendar quarters
except the fourth quarter of 1998 and third quarter of 2001, both of which
included non-cash ceiling test write-downs of our oil and gas properties due to
depressed oil and gas prices.

To finance the Conoco acquisition purchase price (See Recent Events below),
in December 2001, we issued $200 million principal amount of 8 1/4% Senior
Subordinated Notes due 2011 and we borrowed approximately $100 million under our
recently increased credit facility. We currently have a loan base under the
amended credit facility of $250 million with availability of an additional
$106.7 million in borrowings as of March 15, 2002. Stone's borrowing base under
the amended credit facility is redetermined periodically based on an amount
established by the bank group for Stone's oil and gas properties. In September
1997, we completed an offering of $100 million principal amount of 8 3/4% Senior
Subordinated Notes due 2007.

RECENT EVENTS

CONOCO ACQUISITION. On December 31, 2001, Stone completed the acquisition
of eight producing oil and gas properties and related assets located in the Gulf
of Mexico from Conoco. The purchase price of approximately $300 million was
financed with net proceeds from the December 2001 offering of $200 million of 8
1/4% Senior Subordinated Notes due 2011 and borrowings under the bank credit
facility. This acquisition was consistent with our strategy of targeting
properties with characteristics fitting our core business strategy. The
properties provide an immediate impact to our operations in terms of reserves,
production and cash flow growth. More importantly, we believe that we will
realize significant future value from these properties in the form of
discoveries from undrilled or bypassed potential.

MERGER WITH BASIN EXPLORATION. On February 1, 2001, the stockholders of
Stone Energy Corporation and Basin Exploration, Inc. voted in favor of, and
thereby consummated, the combination, through pooling-of-interests, of the two
companies in a tax-free, stock-for-stock transaction. In connection with the
approval of the merger, stockholders of Stone Energy also approved a proposal to
increase the authorized shares of Stone's common stock from 25 million to 100
million shares.

OIL AND GAS MARKETING

Our oil, natural gas and natural gas condensate production is sold at
current market prices under short-term contracts providing for variable or
market sensitive prices. We believe that the loss of any of our major purchasers
would not result in a material adverse effect on our ability to market future
oil and gas production. From time to time, we may enter into transactions that
hedge the price of oil, natural gas and natural gas condensate. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk - Commodity Price
Risk."

COMPETITION AND MARKETS

Competition in the Gulf Coast Basin and the Rocky Mountains is intense,
particularly with respect to the acquisition of producing properties and proved
undeveloped acreage. We compete with major oil and gas companies and other
independent producers of varying sizes, all of which are engaged in the
acquisition of properties and the exploration and development of such
properties. Many of our competitors have financial resources and exploration and
development budgets that are substantially greater than ours, which may
adversely affect our ability to compete. See "Risk Factors - Competition within
our industry may adversely affect our operations."

The availability of a ready market for and the price of any hydrocarbons
produced will depend on many factors beyond our control, including but not
limited to the amount of domestic production and imports of foreign oil, the
marketing of competitive fuels, the proximity and capacity of natural gas
pipelines, the availability of transportation and other market facilities, the
demand for hydrocarbons, the effect of federal and state regulation of allowable
rates of production, taxation, the conduct of drilling operations and federal
regulation of natural gas. In addition, the restructuring of the natural gas
pipeline industry virtually eliminated the gas purchasing activity of
traditional interstate gas transmission pipeline buyers. See "Regulation-Federal
Regulation of Sales and Transportation of Natural Gas." Producers of natural gas
have therefore been required to develop new markets among gas marketing
companies, end users of natural gas and local distribution companies. All of
these factors, together with economic factors in the marketing arena, generally
may affect the supply and/or demand for oil and gas and thus the prices
available for sales of oil and gas.

REGULATION

REGULATION OF PRODUCTION. In all areas where we conduct activities, there
are statutory provisions regulating the production of oil and natural gas under
which administrative agencies may enforce rules in connection with the location,
spacing, drilling, operation and production of both oil and gas wells, determine
the reasonable market demand for oil and gas and establish allowable rates of
production. These regulatory orders can limit the number of wells or the
location where wells may be drilled. Regulation can also restrict the rate of
production below the rate that these wells would otherwise produce in the
absence of such regulatory orders. Any of these actions could negatively impact
the amount or timing of revenues.

FEDERAL LEASES. We have oil and gas leases both onshore and in the Gulf of
Mexico, which were granted by the federal government. Operations on onshore
federal leases must be conducted in accordance with permits issued by the
Federal Bureau of Land Management and are subject to a number of other
regulatory restrictions, such as restrictions on activities that might interfere
with wildlife breeding and nesting and drilling limitations imposed by resource
management plans. Moreover, on certain federal leases, prior approval of
drillsite locations must be obtained from the U.S. Environmental Protection
Agency (the "EPA"). On large-scale projects, lessees may be required to perform
Environmental Impact Statements to assess the environmental effects of potential
development, which can delay project implementation or result in the imposition
of environmental restrictions that could have a material impact on the cost or
scope of such project.

Offshore leases are administered by the United States Department of the
Interior Minerals Management Service (the "MMS"). Offshore lessees must obtain
MMS approval of exploration, development and production plans prior to the
commencement of these operations. In addition to permits required from other
agencies (such as the U.S. Coast Guard, the Army Corps of Engineers and the
EPA), lessees must obtain a permit from the MMS prior to the commencement of
drilling. The MMS has enacted regulations requiring offshore production
facilities located on the Outer Continental Shelf ("OCS") to meet stringent
engineering, construction and safety specifications. The MMS also has
regulations restricting the flaring or venting of natural gas, and prohibiting
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has enacted other regulations governing the plugging and
abandoning of wells located offshore and the removal of all production
facilities. Lessees must also comply with detailed MMS regulations governing the
calculation of royalty payments and the valuation of production and permitted
cost deductions for that purpose. In 2000, the MMS issued a final rule modifying
the valuation procedures for the calculation of royalties owed for crude oil
sales. When oil production sales are not in arms-length transactions, the new
royalty calculation will base the valuation of oil production on spot market
prices instead of the posted prices that were previously utilized. We are
currently selling our crude oil under arm's-length transactions in a manner that
we believe to be acceptable to the MMS under its new rule. As such, we believe
that the effect, if any, of this new rule will not have a material adverse
effect on our results of operations.

With respect to any operations conducted on offshore federal leases,
liability may generally be imposed under the Outer Continental Shelf Lands Act
(the "OCSLA") for costs of clean-up and damages caused by pollution resulting
from these operations, other than damages caused by acts of war or the
negligence of third parties. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that these obligations will be met. The cost of bonds or
other surety can be substantial and there is no assurance that bonds or other
surety can be obtained in all cases.

Operators in the OCS waters of the Gulf of Mexico are also required to post
area-wide bonds and individual lease bonds of $3 million and $1 million,
respectively, unless the MMS allows exemptions or reduced amounts. We currently
have an area-wide right-of-way bond for $0.3 million and an area-wide lessee's
and operator's bond totaling $3 million issued in favor of the MMS for our
existing offshore properties. The MMS also has discretionary authority to
require supplemental bonding in addition to the foregoing required bonding
amounts but this authority is only exercised on a case-by-case basis at the time
of filing an assignment of record title interest for MMS approval. Based upon
certain financial parameters, we have been granted exempt status by the MMS,
which exempts us from the supplemental bonding requirements. There is no
assurance, however, that such exemption will be maintained. Under certain
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition and operations.

OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids are not currently regulated and are made at negotiated prices.
Effective January 1, 1995, the Federal Energy Regulatory Commission (the "FERC")
implemented regulations establishing an indexing system for transportation rates
for oil that allowed for an increase in the cost of transporting oil to the
purchaser. The implementation of these regulations has not had a material
adverse effect on our results of operations.

FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938
(the "NGA"), the Natural Gas Policy Act of 1978 (the "NGPA") and regulations
promulgated thereunder by the FERC. In the past, the federal government has
regulated the prices at which gas could be sold. While sales by producers of
natural gas can currently be made at uncontrolled market prices, Congress could
reenact price controls in the future. Deregulation of wellhead natural gas sales
began with the enactment of the NGPA. In 1989, Congress enacted the Natural Gas
Wellhead Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA
and NGPA price and non-price controls affecting wellhead sales of natural gas
effective January 1, 1993.

Commencing in 1992, the FERC issued Order No. 636 and subsequent orders
(collectively, "Order No. 636"), which require interstate pipelines to provide
transportation separate, or "unbundled," from the pipelines' sales of gas. Also,
Order No. 636 requires pipelines to provide open-access transportation on a
basis that is equal for all shippers. Although Order No. 636 does not directly
regulate our activities, the FERC has stated that it intends for Order No. 636
to foster increased competition within all phases of the natural gas industry.
The implementation of these orders has not had a material adverse effect on our
results of operations. The courts have largely affirmed the significant features
of Order No. 636 and numerous related orders pertaining to the individual
pipelines, although certain appeals remain pending and the FERC continues to
review and modify its open access regulations.

In 2000, the FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised the FERC pricing policy by waiving price ceilings for short-term
released capacity for a two-year period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation, pipeline
penalties, rights of first refusal and information reporting. Most major aspects
of Order No. 637 are pending judicial review. We cannot predict whether and to
what extent FERC's market reforms will survive judicial review and, if so,
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 we
will be affected by any action taken materially differently than other natural
gas producers and marketers with which we compete.

The OCSLA requires that all pipelines operating on or across the OCS
provide open-access, non-discriminatory service. Commencing in April 2000, the
FERC issued Order Nos. 639 and 639-A (collectively, "Order No. 639"), which
imposed certain reporting requirements applicable to "gas service providers"
operating on the OCS concerning their prices and other terms and conditions of
service. The purpose of Order No. 639 is to provide regulators and other
interested parties with sufficient information to detect and to remedy
discriminatory conduct by such service providers. The FERC has stated that these
reporting rules apply to OCS gatherers and has clarified that they may also
apply to other OCS service providers including platform operators performing
dehydration, compression, processing and related services for third parties. The
U.S. District Court recently overturned the FERC's reporting rules as exceeding
its authority under OSCLA. The FERC has indicated an appeal is likely. We cannot
predict whether and to what extent these regulations might be reinstated, and
what effect, if any, they may have on us. The rules, if reinstated, may increase
the frequency of claims of discriminatory service, may decrease competition
among OCS service providers and may lessen the willingness of OCS gathering
companies to provide service on a discounted basis.

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 heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.

ENVIRONMENTAL REGULATIONS. 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 a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas and impose substantial liabilities for
pollution resulting from our operations. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
fines and penalties and the imposition of injunctive relief. Changes in
environmental laws and regulations occur frequently, and any changes that result
in more stringent and costly waste handling, storage, transport, disposal or
cleanup requirements could materially adversely affect our operations and
financial position, as well as those in the oil and gas industry in general.
While we believe that we are in substantial compliance with current applicable
environmental laws and regulations and that continued compliance with existing
requirements would not have a material adverse impact on us, there is no
assurance that this trend will continue in the future.

The Oil Pollution Act, as amended ("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, including the OCS. A "responsible party" includes the
owner or operator of an onshore facility, pipeline or vessel, or the lessee or
permittee of the area in which an offshore facility is located. OPA assigns
liability to each responsible party for oil cleanup 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. Even if applicable, the liability limits for offshore facilities require
the responsible party to pay all removal costs, plus up to $75 million in other
damages. Few defenses exist to the liability imposed by OPA.

OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and a final rule adopted by the MMS in
August 1998, responsible parties of covered offshore facilities that have a
worst case oil spill of more than 1,000 barrels must demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in OCS waters, with higher amounts of up to $150
million in certain limited circumstances where the MMS believes such a level is
justified by the risks posed by the operations, or if the worst case oil-spill
discharge volume possible at the facility may exceed the applicable threshold
volumes specified under the MMS's final rule. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under OPA and the MMS's regulations.

The Comprehensive Environmental Response, Compensation and Liability Act,
as amended ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that are considered to be responsible for the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of the disposal site or sites where the release occurred and companies
that transported or disposed or arranged for the transport or disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment.

The Resource Conservation and Recovery Act, as amended ("RCRA"), generally
does not regulate most wastes generated by the exploration and production of oil
and gas. RCRA specifically excludes from the definition of hazardous waste
"drilling fluids, produced waters and other wastes associated with the
exploration, development or production of crude oil, natural gas or geothermal
energy." However, legislation has been proposed in Congress from time to time
that would reclassify certain oil and gas exploration and production wastes as
"hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on our operating costs,
as well as the oil and gas industry in general. Moreover, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils,
may be regulated as hazardous waste.

We currently own or lease, and have in the past owned or leased, onshore
properties that for many years have been used for or associated with the
exploration and production of oil and gas. Although we have utilized operating
and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us on or under other locations where such
wastes have been taken for disposal. In addition, most of these properties have
been operated by third parties whose treatment and disposal or release of wastes
was not under our control. These properties and the wastes disposed thereon may
be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could
be required to remove or remediate previously disposed wastes (including waste
disposed of or released by prior owners or operators) or property contamination
(including groundwater contamination by prior owners or operators), or to
perform remedial plugging or closure operations to prevent future contamination.

The Federal Water Pollution Control Act, as amended ("FWPCA"), imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas waste into navigable waters. Permits must be obtained to
discharge pollutants to waters and to conduct construction activities in waters
and wetlands. The FWPCA and similar state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of pollutants and
unauthorized discharges of reportable quantities of oil and other hazardous
substances. Many state discharge regulations and the Federal National Pollutant
Discharge Elimination System general permits issued by the EPA prohibit the
discharge of produced water and sand, drilling fluids, drill cuttings and
certain other substances related to the oil and gas industry into coastal
waters. Although the costs to comply with zero discharge mandates under federal
or state law may be significant, the entire industry is expected to experience
similar costs and we believe that these costs will not have a material adverse
impact on our results of operations or financial position. The EPA has adopted
regulations requiring certain oil and gas exploration and production facilities
to obtain permits for storm water discharges. Costs may be associated with the
treatment of wastewater or developing and implementing storm water pollution
prevention plans.

EMPLOYEES

At March 15, 2002, we had 205 full time employees. We believe that our
relationships with our employees are satisfactory. None of our employees are
covered by a collective bargaining agreement. From time to time we utilize the
services of independent contractors to perform various field and other services.

FORWARD-LOOKING STATEMENTS

The information in this Form 10-K includes "forward-looking statements"
within the meaning of Section 27A of the Securities Act of 1933 and Section 21E
of the Securities Exchange Act of 1934. All statements, other than statements of
historical or present facts, that address activities, events, outcomes and other
matters that we plan, expect, intend, assume, believe, budget, predict,
forecast, project, estimate or anticipate (and other similar expressions) will,
should or may occur in the future are forward-looking statements. These
forward-looking statements are based on management's current belief, based on
currently available information, as to the outcome and timing of future events.
When considering forward-looking statements, you should keep in mind the risk
factors and other cautionary statements in this Form 10-K.

Forward-looking statements appear in a number of places and include
statements with respect to, among other things:

o any expected results or benefits associated with our recent
acquisitions from Conoco;

o estimates of our future natural gas and liquids production, including
estimates of any increases in oil and gas production;

o planned capital expenditures and the availability of capital resources
to fund capital expenditures;

o our outlook on oil and gas prices;

o estimates of our oil and gas reserves;

o any estimates of future earnings growth;

o the impact of political and regulatory developments;

o our future financial condition or results of operations and our future
revenues and expenses; and

o our business strategy and other plans and objectives for future
operations.

We caution you that these forward-looking statements are subject to all of
the risks and uncertainties, many of which are beyond our control, incident to
the exploration for and development, production and sale of oil and gas. These
risks include, but are not limited to, commodity price volatility, third party
interruption of sales to market, inflation, lack of availability of goods and
services, environmental risks, drilling and other operating risks, regulatory
changes, the uncertainty inherent in estimating proved oil and natural gas
reserves and in projecting future rates of production and timing of development
expenditures and the other risks described in this Form 10-K.

Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact way.
The accuracy of any reserve estimate depends on the quality of available data
and the interpretation of that data by geological engineers. As a result,
estimates made by different engineers often vary from one another. In addition,
the results of drilling, testing and production activities may justify revisions
of estimates that were made previously. If significant, these revisions would
change the schedule of any further production and development drilling.
Accordingly, reserve estimates are generally different from the quantities of
oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described above or
elsewhere in this Form 10-K occur, or should underlying assumptions prove
incorrect, our actual results and plans could differ materially from those
expressed in any forward-looking statements. We specifically disclaim all
responsibility to publicly update any information contained in a forward-looking
statement or any forward-looking statement in its entirety and therefore
disclaim any resulting liability for potentially related damages.

All forward-looking statements attributable to us are expressly qualified
in their entirety by this cautionary statement.

RISK FACTORS

Our business is subject to a number of risks including, but not limited to,
those described below:

OIL AND GAS PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR
REVENUES, CASH FLOWS AND PROFITABILITY.

Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Factors
that can cause this fluctuation include:

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

o market uncertainty;

o the level of consumer product demands;

o weather conditions;

o domestic and foreign governmental regulations;

o the price and availability of alternative fuels;

o political and economic conditions in oil producing countries,
particularly those in the Middle East;

o the foreign supply of oil and natural gas;

o the price of oil and gas imports; and

o overall domestic and foreign economic conditions.

We cannot predict future oil and natural gas prices. At various times,
excess domestic and imported supplies have depressed oil and gas prices.
Declines in oil and natural gas prices may adversely affect our financial
condition, liquidity and results of operations. Lower prices may reduce the
amount of oil and natural gas that we can produce economically and may also
create ceiling test write-downs of our oil and gas properties. Substantially all
of our oil and natural gas sales are made in the spot market or pursuant to
contracts based on spot market prices, not long-term fixed price contracts.

In an 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.

We have natural gas swap contracts during 2002 and 2003 with a subsidiary
of Enron Corp. Depending on fluctuations in gas prices, these contracts may
create a receivable owed to us from Enron's subsidiary. Due to Enron Corp's
financial difficulties, there is no assurance that we will receive full or
partial payment of any amount that may become owed to us under these contracts.

THE MARKETABILITY OF OUR PRODUCTION DEPENDS MOSTLY UPON THE AVAILABILITY,
PROXIMITY AND CAPACITY OF GAS GATHERING SYSTEMS, PIPELINES AND PROCESSING
FACILITIES.

The marketability of our production depends upon the availability,
operation and capacity of 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. Federal and state regulation
of oil and gas production and transportation, general economic conditions and
changes in supply and demand could adversely affect our ability to produce and
market our oil and natural gas. If market factors changed dramatically, the
financial impact on us could be substantial. The availability of markets and the
volatility of product prices are beyond our control and represent a significant
risk.

ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.

This Form 10-K contains estimates of our proved oil and gas reserves and
the estimated future net revenues from such reserves. These estimates are based
upon various assumptions, including assumptions required by the Securities and
Exchange Commission (the "SEC") relating to oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating oil and gas reserves is complex. This process requires
significant decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Therefore, these
estimates are inherently imprecise.

Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth in this document and the information incorporated by reference. Our
properties may also be susceptible to hydrocarbon drainage from production by
other operators on adjacent properties. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond our control. Actual production, revenues, taxes, development expenditures
and operating expenses with respect to our reserves will likely vary from the
estimates used. Such variances may be material.

At December 31, 2001, approximately 21% of our estimated proved reserves
were undeveloped. 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 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 Form 10-K is the current fair value of our estimated oil and
gas reserves. In accordance with SEC 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 gas purchasers or in governmental
regulations or taxation will also affect actual future net cash flows. The
timing of both the production and the expenses from the development and
production of oil and 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 SEC to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor for Stone.

LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.

We use the full cost method of accounting for our oil and gas operations.
Accordingly, we capitalize the cost to acquire, explore for and develop oil and
gas properties. Under full cost accounting rules, the net capitalized costs of
oil and 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 value of unproved properties.
If net capitalized costs of oil and 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 net income and stockholders' equity. The risk that we will be
required to write down the carrying value of oil and gas properties increases
when oil and gas prices are low or volatile. In addition, write-downs may occur
if we experience substantial downward adjustments to our estimated proved
reserves. Due to low oil and gas prices at the end of 1998, in December 1998 we
recorded an after-tax write-down of $74.3 million ($114.3 million pre-tax). We
also recorded an after-tax write-down of $154.5 million ($237.7 million pre-tax)
at the end of the third quarter of 2001 due to low natural gas prices on the
last day of that quarter. There was no loss of proved reserve volumes associated
with either ceiling test write-down. We cannot assure you that we will not
experience ceiling test write-downs in the future.

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 bank credit facilities, the issuance of debt and equity securities and
the use of cash flow provided by operating activities. We continue to examine
the following alternative sources of long-term capital:

o bank borrowings or the issuance of debt securities;

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

o joint venture financing; and

o production payments.

The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and natural gas prices and our
market value and operating performance. We may be unable to execute our
operating strategy if we cannot obtain capital from these sources.

WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.

We spend and will continue to spend a substantial amount of capital for the
acquisition, exploration, development and production of oil and gas reserves.
Our capital expenditures were $641.3 million during 2001, $269.1 million during
2000 and $194.5 million during 1999. We have budgeted total capital expenditures
in 2002, excluding property acquisitions, capitalized salaries, general and
administrative costs and interest, of approximately $200 million. If low oil and
natural gas prices, operating difficulties or other factors, many of which are
beyond our control, cause our revenues and cash flows from operations to
decrease, we may be limited in our ability to spend the capital necessary to
complete our drilling program. In addition, if our borrowing base under our
credit facility is redetermined to a lower amount, this could adversely affect
our ability to fund our planned capital expenditures. After utilizing our
available sources of financing, 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 flow provided by operations will be available
to meet these requirements.

WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.

In general, the volume of production from oil and gas properties declines
as reserves are depleted. The decline rates depend on reservoir characteristics.
Gulf of Mexico reservoirs tend to experience steep declines, while declines in
other regions tend to be relatively slow. During 2001, 96% of our production and
94% of our proved reserves were derived from Gulf of Mexico reservoirs. Our
reserves will decline as they are produced unless we acquire properties with
proved reserves or conduct successful development and exploration activities.
Our future natural gas and oil production is highly dependent upon our level of
success in finding or acquiring additional reserves.

Our recent growth, including our merger and our recent acquisitions from
Conoco, is due in large part to acquisitions of producing properties. The
successful acquisition of producing properties requires an assessment of a
number of factors, many of which are beyond our control. These factors include
recoverable reserves, future oil and gas prices, operating costs and potential
environmental and other liabilities, title issues and other factors. Such
assessments are inexact and their accuracy is inherently uncertain. In
connection with such assessments, we perform a review of the subject properties,
which we believe is generally consistent with industry practices. However, such
a review will not reveal all existing or potential problems. In addition, the
review will not permit a buyer to become sufficiently familiar with the
properties to fully assess their deficiencies and capabilities. We cannot assure
you that we will be able to acquire properties at acceptable prices because the
competition for producing oil and gas properties is intense and many of our
competitors have financial and other resources, which are substantially greater
than those available to us.

Our strategy includes increasing our production and reserves by the
implementation of a carefully designed field-wide development plan. These
development plans are formulated both prior to and after the acquisition of a
property. However, we cannot assure you that our future development and
exploration activities on the properties we acquire will result in additional
proved reserves or that we will be able to drill productive wells at acceptable
costs.

THERE ARE UNCERTAINTIES IN SUCCESSFULLY INTEGRATING OUR ACQUISITIONS, INCLUDING
OUR MERGER WITH BASIN AND OUR RECENT ACQUISITIONS FROM CONOCO.

Integrating acquired businesses and properties, including those acquired in
connection with our merger and our recent acquisitions from Conoco, involves a
number of special risks. These risks include the possibility that management may
be distracted from regular business concerns by the need to integrate operations
and that unforeseen difficulties can arise in integrating operations and systems
and in retaining and assimilating employees. Any of these or other similar risks
could lead to potential adverse short-term or long-term effects on our operating
results.

OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND
PRODUCTION ACTIVITIES.

Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or natural gas
reservoirs will be found. The cost of drilling and completing wells is often
uncertain. Oil and gas drilling and production activities may be shortened,
delayed or canceled as a result of a variety of factors, many of which are
beyond our control. These factors include:

o unexpected drilling conditions;

o pressure or irregularities in formations;

o equipment failures or accidents;

o weather conditions;

o shortages in experienced labor; and

o shortages or delays in the delivery of equipment.

The prevailing prices of oil and natural gas also affect the cost of and
the demand for drilling rigs, production equipment and related services.

We cannot assure you that the new wells we drill will be productive or that
we will recover all or any portion of our investment. Drilling for oil and
natural gas may be unprofitable. Drilling activities can result in dry wells and
wells that are productive but do not produce sufficient net revenues after
operating and other costs to recoup drilling costs.

OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS.

The exploration, development and operation of oil and gas properties
involves a variety of operating risks including the risk of fire, explosions,
blowouts, pipe failure, abnormally pressured formations and environmental
hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures
or discharges of toxic gases. If any of these industry-operating risks occur, we
could have substantial losses. Substantial losses may be caused by injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, our offshore operations are subject to the additional hazards of
marine operations, such as capsizing, collision and adverse weather and sea
conditions. In accordance with industry practice, we maintain insurance against
some, but not all, of the risks described above.

We currently maintain loss of production insurance to protect against
uncontrollable disruptions in production operations. The policy covers the
majority of our anticipated production volumes from selected offshore properties
on an individual facility basis. The value of lost production would be
calculated using the average of the last 45 days' revenue from the facility
prior to the loss. We currently maintain coverage of up to $100 million per
occurrence that becomes effective after 30 consecutive days of lost production.

We also maintain additional insurance of various types to cover our
operations, including maritime employer's liability and comprehensive general
liability. Coverage amounts are provided by primary and excess umbrella
liability policies with ultimate limits of $100 million. In addition, we
maintain up to $100 million in operator's extra expense insurance, which
provides coverage for the care, custody and control of wells drilled and/or
completed plus redrill and pollution coverage. The exact amount of coverage for
each well is dependent upon its depth and location.

We cannot assure you that our insurance will be adequate to cover losses or
liabilities. Also, we cannot predict the continued availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event,
not fully insured or indemnified against, could materially and adversely affect
our financial condition and operations.

A PORTION OF OUR PRODUCTION, REVENUES AND CASH FLOWS ARE DERIVED FROM ASSETS
THAT ARE CONCENTRATED IN A GEOGRAPHIC AREA.

Production from South Pelto Block 23 and Eugene Island Block 243 each
accounted for approximately 16% of our total oil and gas production volumes
during 2001. Accordingly, if the level of production from either of these fields
substantially declines, it could have a material adverse effect on our overall
production levels and our revenues.

OUR DEBT LEVEL AND THE COVENANTS IN THE AGREEMENTS GOVERNING OUR DEBT COULD
NEGATIVELY IMPACT OUR FINANCIAL CONDITION, RESULTS OF OPERATIONS AND BUSINESS
PROSPECTS.

As of December 31, 2001, we had $426 million in outstanding indebtedness.
During December 2001, we increased our bank credit facility to $350 million. We
currently have a loan base under the amended credit facility of $250 million
with availability of an additional $106.7 million in borrowings as of March 15,
2002.

The terms of the agreements governing our debt impose significant
restrictions on our ability and the ability of our subsidiaries to take a number
of actions that we may otherwise desire to take, including:

o incurring additional debt;

o paying dividends on stock, redeeming stock or redeeming subordinated
debt;

o making investments;

o creating liens on our assets;

o selling assets;

o guaranteeing other indebtedness;

o entering into agreements that restrict dividends from our subsidiaries
to us;

o merging, consolidating or transferring all or substantially all of our
assets; and

o entering into transactions with affiliates.

Our level of indebtedness, and the covenants contained in the agreements
governing our debt, could have important consequences on our operations,
including:

o making it more difficult for us to satisfy our obligations under the
indentures or other debt and increasing the risk that we may default
on our debt obligations;

o requiring us to dedicate a substantial portion of our cash flow from
operations to required payments on debt, thereby reducing the
availability of cash flow for working capital, capital expenditures
and other general business activities;

o limiting our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions and general
corporate and other activities;

o limiting our flexibility in planning for, or reacting to, changes in
our business and the industry in which we operate;

o detracting from our ability to successfully withstand a downturn in
our business or the economy generally;

o placing us at a competitive disadvantage against other less leveraged
competitors; and

o making us vulnerable to increases in interest rates, because debt
under our credit facility will be at variable rates.

We may be required to repay all or a portion of our debt on an accelerated
basis in certain circumstances. If we fail to comply with the covenants and
other restrictions in the agreements governing our debt, it could lead to an
event of default and the acceleration of our repayment of outstanding debt. Our
ability to comply with these covenants and other restrictions may be affected by
events beyond our control, including prevailing economic and financial
conditions. Moreover, the borrowing base limitation on our credit facility is
periodically redetermined based on an evaluation of our reserves. Upon a
redetermination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our bank debt.

We may not have sufficient funds to make such repayments. If we are unable
to repay our debt out of cash on hand, we could attempt to refinance such debt,
sell assets or repay such debt with the proceeds from 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, equity financings or
proceeds from the sale of assets will be available to pay or refinance such
debt. The terms of our debt, including our credit facility and our indentures,
may also prohibit us from taking such actions. Factors that will affect our
ability to raise cash through an offering of our capital stock, a refinancing of
our debt or a sale of assets include financial market conditions and our market
value and operating performance at the time of such offering or other financing.
We cannot assure you that any such offering, refinancing or sale of assets can
be successfully completed.

COMPETITION WITHIN OUR INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.

OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE AND LOCAL
GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.

Our oil and gas operations are subject to various U.S. federal, state and
local laws and regulations. These laws and regulations may be changed in
response to economic or political conditions. Regulated matters include permits
for exploration, development and production operations, such as permits for
discharges of wastewaters and other substances generated in connection with
drilling operations, bonds or other financial responsibility requirements to
cover drilling contingencies and well plugging and abandonment costs, reports
concerning operations, the spacing of wells and unitization and pooling of
properties and taxation. At various times, regulatory agencies have imposed
price controls and limitations on oil and gas production. In order to conserve
supplies of oil and gas, these agencies have restricted the rates of flow of oil
and gas wells below actual production capacity. In addition, the federal Oil
Pollution Act, as amended, requires operators of offshore facilities such as us
to prove that they have the financial capability to respond to costs that may be
incurred in connection with potential oil spills. Under OPA and other federal
and state environmental statutes, including the CERCLA, as amended, and the
RCRA, as amended, owners and operators of certain defined onshore and offshore
facilities are strictly liable for spills of oil and other regulated substances,
subject to certain limitations. Consequently, a substantial spill from one of
our facilities subject to laws such as OPA, CERCLA and RCRA could have a
material adverse effect on our results of operations, competitive position or
financial condition. Federal, state and local laws regulate production,
handling, storage, transportation and disposal of oil and gas, by-products from
oil and gas and other substances, and materials produced or used in connection
with oil and gas operations. We cannot predict the ultimate cost of compliance
with these requirements or their effect on our 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. We do not have
employment contracts with any of these individuals. The unexpected loss of the
services of one or more of these individuals could have a detrimental effect on
us.

HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.

In order to manage our exposure to price risks in the marketing of our oil
and gas, we periodically enter into oil and gas price hedging arrangements with
respect to a portion of our expected production. Our hedging policy provides
that, without prior approval of our board of directors, generally not more than
50% of our production quantities may be hedged. These arrangements may include
futures contracts on the New York Mercantile Exchange. While intended to reduce
the effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:

o our production is less than expected;

o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge
arrangement;

o the counterparties to our futures contracts fail to perform the
contracts; or

o a sudden, unexpected event materially impacts oil or gas prices.

OWNERSHIP OF WORKING INTERESTS, NET PROFITS INTERESTS AND OVERRIDING ROYALTY
INTERESTS IN CERTAIN OF OUR PROPERTIES BY CERTAIN OF OUR OFFICERS AND DIRECTORS
MAY CREATE CONFLICTS OF INTEREST.

James H. Stone and Joe R. Klutts, both directors of Stone, collectively own
9% of the working interest in certain wells drilled on Section 19 on the east
flank of Weeks Island Field. These interests were acquired at the same time that
our predecessor company acquired its interests in Weeks Island Field. In their
capacity as working interest owners, they are required to pay their proportional
share of all costs and are entitled to receive their proportional share of
revenues.

Two of our officers were granted net profits interests in some of our oil
and gas properties acquired prior to 1993. The recipients of net profits
interests are not required to pay capital costs incurred on the properties
burdened by such interests.

We received certain fees as a result of our function as managing partner of
certain partnerships. These partnerships were dissolved on December 31, 1999.
All participants in the partnerships, including four of our directors, James H.
Stone, Joe R. Klutts, Raymond B. Gary and Robert A. Bernhard, received
overriding royalty interests in the related properties in exchange for their
partnership interests. For the years ended December 31, 1999, management fees
and overhead reimbursements from partnerships totaled $224,000, the majority of
which was treated as a reduction of our investment in oil and gas properties.

As a result of these transactions, a conflict of interest may exist between
us and such directors and officers with respect to the drilling of additional
wells or other development operations.

WE DO NOT PAY DIVIDENDS.

We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the near future. The restrictions on our present
or future ability to pay dividends are included in the provisions of the
Delaware General Corporation Law and in certain restrictive provisions in the
indentures executed in connection with our 8 3/4% Senior Subordinated Notes due
2007 and 8 1/4% Senior Subordinated Notes due 2011. In addition, we have entered
into a credit facility that contains provisions that may have the effect of
limiting or prohibiting the payment of dividends.

OUR CERTIFICATE OF INCORPORATION AND BYLAWS HAVE PROVISIONS THAT DISCOURAGE
CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON
THEIR INVESTMENT.

Certain provisions of our Certificate of Incorporation, Bylaws and
shareholders' rights plan and the provisions of the Delaware General Corporation
Law may encourage persons considering unsolicited tender offers or other
unilateral takeover proposals to negotiate with our board of directors rather
than pursue non-negotiated takeover attempts. Our Bylaws provide for a
classified board of directors. Also, our Certificate of Incorporation authorizes
our board of directors to issue preferred stock without stockholder approval and
to set the rights, preferences and other designations, including voting rights
of those shares, as the board may determine. Additional provisions include
restrictions on business combinations and the availability of authorized but
unissued common stock. These provisions, alone or in combination with each other
and with the rights plan described below, may discourage transactions involving
actual or potential changes of control, including transactions that otherwise
could involve payment of a premium over prevailing market prices to stockholders
for their common stock.

During 1998, our board of directors adopted a shareholder rights agreement,
pursuant to which uncertificated 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 October 26, 1998. The rights plan is designed to enhance the
board's ability to prevent an acquirer from depriving stockholders of the
long-term value of their investment and to protect stockholders against attempts
to acquire us by means of unfair or abusive takeover tactics. However, the
existence of the rights plan may impede a takeover not supported by our board,
including a takeover that may be desired by a majority of our stockholders or
involving a premium over the prevailing stock price.

ITEM 2. PROPERTIES

We have grown principally through the acquisition and subsequent
development and exploitation of properties purchased from major and independent
oil and gas companies. In December 2001, we acquired interests in eight
producing properties in the Gulf of Mexico from Conoco. Our current property
portfolio consists of 55 active properties and 39 primary term leases in the
Gulf Coast Basin and 32 active properties in the Rocky Mountains.

As of January 1, 2002, we served as operator on 62% of our active
properties, including a 69% operating percentage on our Gulf Coast Basin
properties. The properties that we operate accounted for 82% of our year-end
2001 estimated proved reserves. This high operating percentage allows us to
better control the timing, selection and costs of our drilling and production
activities.

OIL AND GAS RESERVES

The following table sets forth our estimated net proved oil and gas
reserves and the present value of estimated future net cash flows before taxes
related to such reserves as of December 31, 2001. The proved natural gas
reserves at December 31, 2001 excluded 1.3 Bcf of gas dedicated to a production
payment. Also excluded are the related estimated future net cash flows and the
present value of estimated future net cash flows of $3.8 million and $3.7
million, respectively.

The information in this Form 10-K relating to Stone's estimated oil and gas
reserves and the estimated future net cash flows attributable thereto is based
upon the reserve reports (the "Reserve Reports") prepared as of December 31,
2001 by Atwater Consultants, Ltd., Ryder Scott Company, and Cawley, Gillespie &
Associates, Inc., all independent petroleum engineers. All product pricing and
cost estimates used in the Reserve Reports are in accordance with the rules and
regulations of the SEC, and, except as otherwise indicated, the reported amounts
give no effect to federal or state income taxes otherwise attributable to
estimated future cash flows from the sale of oil and gas. The present value of
estimated future net cash flows has been calculated using a discount factor of
10%.

You should not assume that the estimated future net cash flows or the
present value of estimated future net cash flows, referred to in the table
below, represent the fair value of our estimated oil and gas reserves. As
required by the SEC, we determine estimated future net cash flows using
period-end market prices for oil and gas without considering hedge contracts in
place at the end of the period. Using the information contained in the Reserve
Reports, the average 2001 year-end product prices for all of our properties were
$18.64 per barrel of oil and $2.79 per Mcf of gas.

PERCENT
PROVED PROVED TOTAL PROVED
DEVELOPED UNDEVELOPED PROVED DEVELOPED
------------- ---------------- -------------- ------------

Oil (MBbls)................................ 43,094 12,297 55,391 77.8%

Gas (MMcf)................................. 351,269 91,400 442,669 79.4%

Total oil and gas (MMcfe).................. 609,833 165,182 775,015 78.7%

Estimated future net cash flows before
income taxes (in thousands)............. $1,238,584 $268,639 $1,507,223 82.2%

Present value of estimated future net
cash flows before income taxes (in
thousands).............................. $887,811 $150,986 $1,038,797 85.5%

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein only represents estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the existence of
development plans. As a result, estimates of reserves made by different
engineers for the same property will often vary. Results of drilling, testing
and production subsequent to the date of an estimate may justify a revision of
such estimates. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately produced. Further, the estimated
future net revenues from proved reserves and the present value thereof are based
upon certain assumptions, including geological success, prices, future
production levels and costs that may not prove to be correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
meaningfulness of these estimates depends on the accuracy of the assumptions
upon which they are based.

As an operator of domestic oil and gas properties, we have filed Department
of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by
Public Law 93-275. There are differences between the reserves as reported on
Form EIA-23 and as reported herein. The differences are attributable to the fact
that Form EIA-23 requires that an operator report the total reserves
attributable to wells that it operates, without regard to percentage ownership
(i.e., reserves are reported on a gross operated basis, rather than on a net
interest basis) or non-operated wells in which it owns an interest.

ACQUISITION, PRODUCTION AND DRILLING ACTIVITY

ACQUISITION AND DEVELOPMENT COSTS. The following table sets forth certain
information regarding the costs incurred in our acquisition, development and
exploratory activities during the periods indicated.

YEAR ENDED DECEMBER 31,
----------------------------------------------
2001 2000 1999
---------- ---------- ----------
(In thousands)

Acquisition costs.................................. $328,778 $15,086 $27,316
Development costs.................................. 119,426 98,004 86,218
Exploratory costs.................................. 176,679 138,420 66,848
---------- ---------- ----------
Subtotal......................................... 624,883 251,510 180,382
Capitalized general and administrative costs and
interest, net of fees and reimbursements........ 16,394 17,634 14,102
---------- ---------- ----------
Total additions to oil and gas properties (1)...... $641,277 $269,144 $194,484
========== ========== ==========

(1) Total additions to oil and gas properties during 1999 included
non-cash additions of $20.3 million related to acquisitions made
through production payments.

PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain
statistics regarding the number of productive wells and developed and
undeveloped acreage as of December 31, 2001.

GROSS NET
------------ ------------
Productive Wells:
Oil (1):
Gulf Coast Basin........... 173.00 100.80
Rocky Mountain Basin....... 189.00 152.44
------------ ------------
362.00 253.24
------------ ------------
Gas (2):
Gulf Coast Basin........... 165.00 109.39
Rocky Mountain Basin....... 36.00 18.60
------------ ------------
201.00 127.99
------------ ------------
Total...................... 563.00 381.23
============ ============

Developed Acres:
Gulf Coast Basin............. 47,321.00 29,164.19
Rocky Mountain Basin......... 47,805.00 27,723.00
------------ ------------
Total...................... 95,126.00 56,887.19
============ ============

Undeveloped Acres (3):
Gulf Coast Basin.............. 461,572.00 330,690.29
Rocky Mountain Basin.......... 210,567.00 127,676.75
------------ ------------
Total..................... 672,139.00 458,367.04
============ ============

(1) 11 gross wells each have dual completions.
(2) 8 gross wells each have dual completions.
(3) Leases covering approximately 4% of our undeveloped gross acreage will
expire in 2002, 8% in 2003, 5% in 2004, 8% in 2005 and 2% in 2006.
Leases covering the remainder of our undeveloped gross acreage (73%)
are held by production.

DRILLING ACTIVITY. The following table sets forth our drilling activity for
the periods indicated.

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
2001 2000 1999
---------------------- --------------------- ---------------------
Gross Net Gross Net Gross Net
--------- --------- --------- --------- --------- ---------

Exploratory Wells:
Productive.................. 22.00 13.84 31.00 17.82 19.00 9.86
Nonproductive............... 20.00 15.81 20.00 10.65 10.00 5.31

Development Wells:
Productive.................. 20.00 12.03 24.00 16.68 10.00 7.59
Nonproductive............... 1.00 0.51 1.00 0.82 - -

TITLE TO PROPERTIES

We believe that we have satisfactory title to substantially all of our
active properties in accordance with standards generally accepted in the oil and
gas industry. Our properties are subject to customary royalty interests, liens
for current taxes and other burdens, which we believe do not materially
interfere with the use of or affect the value of such properties. Prior to
acquiring undeveloped properties, we perform a title investigation that is
thorough but less vigorous than that conducted prior to drilling, which is
consistent with standard practice in the oil and gas industry. Before we
commence drilling operations, we conduct a thorough title examination and
perform curative work with respect to significant defects before proceeding with
operations. We have performed a thorough title examination with respect to
substantially all of our active properties.

ITEM 3. LEGAL PROCEEDINGS

We are named as a defendant in certain lawsuits and are a party to certain
regulatory proceedings arising in the ordinary course of business. We do not
expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.

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

No matters were submitted for a vote of our stockholders during the fourth
quarter of 2001.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth information regarding the names, ages (as of
March 15, 2002) and positions held by each of our executive officers. Our
executive officers serve at the discretion of the Board of Directors.

NAME AGE POSITION
---- --- --------

D. Peter Canty................................ 55 President, Chief Executive Officer and Director
Andrew L. Gates, III.......................... 54 Vice President, Secretary and General Counsel
Craig L. Glassinger........................... 54 Vice President - Resources
E. J. Louviere................................ 53 Vice President - Land
J. Kent Pierret............................... 46 Vice President - Controller and Chief Accounting Officer
James H. Prince............................... 59 Vice President, Chief Financial Officer and Treasurer

The following biographies describe the business experience of our executive
officers for at least the past five years. Stone Energy Corporation was formed
in March 1993 to become a holding company for The Stone Petroleum Corporation
("TSPC") and its subsidiaries. In 1997, TSPC was dissolved after the majority of
its assets were transferred to Stone Energy Corporation.

D. Peter Canty was named Chief Executive Officer on January 1, 2001 and
President in March 1994. He has also served as Chief Operating Officer and as a
Director since March 1993. Mr. Canty was President of TSPC from 1994 to 1997.

Andrew L. Gates, III has served as Vice President, Secretary and General
Counsel since August 1995.

Craig L. Glassinger was named Vice President - Resources in February 2001.
From December 1995 to February 2001 he served as Vice President - Acquisitions.

E. J. Louviere has served as Vice President - Land since June 1995.

J. Kent Pierret was named Vice President - Controller and Chief Accounting
Officer in June 1999. Prior to rejoining us, he was a partner in the firm of
Pierret, Veazey & Co., CPAs (and its predecessors) from May 1988 to May 1999,
which performed a substantial amount of our financial reporting, tax compliance
and financial advisory services.

James H. Prince was named Chief Financial Officer in August 1999 and
Treasurer in June 1999. He previously served as Chief Accounting Officer and
Controller from 1993 to June 1999.

PART II

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

Since July 9, 1993, our common stock has been listed on the New York Stock
Exchange under the symbol "SGY." The following table sets forth, for the periods
indicated, the high and low closing prices per share of our common stock.

HIGH LOW
------------- ------------
2000
First Quarter............................ $50.375 $32.250
Second Quarter........................... 61.813 44.875
Third Quarter............................ 60.938 47.063
Fourth Quarter........................... 67.380 50.190

2001
First Quarter............................ $63.750 $47.750
Second Quarter........................... 57.900 41.400
Third Quarter............................ 47.110 30.000
Fourth Quarter........................... 40.120 31.850

2002
First Quarter (through March 15, 2002)... $38.270 $32.400

On March 15, 2002, the last reported sales price on the New York Stock
Exchange Composite Tape was $37.15 per share. As of that date, there were
approximately 241 holders of record of our common stock.

DIVIDEND RESTRICTIONS

In the past, we have not paid cash dividends on our common stock, and we do
not intend to pay cash dividends on our common stock in the foreseeable future.
We currently intend to retain earnings, if any, for the future operation and
development of our business. The restrictions on our present or future ability
to pay dividends are included in the provisions of the Delaware General
Corporation Law and in certain restrictive provisions in the indentures executed
in connection with our 8 3/4% Senior Subordinated Notes due 2007 and our 8 1/4%
Senior Subordinated Notes due 2011. In addition, we have entered into a credit
facility that contains provisions that may have the effect of limiting or
prohibiting the payment of dividends.

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected historical financial
information for each of the years in the five-year period ended December 31,
2001. This information is derived from our Financial Statements and the notes
thereto. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data."

YEAR ENDED DECEMBER 31,
------------------------------------------------------------
2001 2000 1999 1998 1997
------ ------ ------ ------ ------
(In thousands, except per share amounts)

STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil production revenue.......................... $103,053 $118,628 $70,025 $48,262 $40,926
Gas production revenue ......................... 292,446 263,310 148,390 114,955 52,554
Other revenue................................... 2,997 4,228 2,349 2,102 2,227
--------- --------- --------- --------- ---------
Total operating revenues...................... 398,496 386,166 220,764 165,319 95,707
--------- --------- --------- --------- ---------
Expenses:
Normal lease operating expenses.................. 47,564 41,474 33,372 26,318 14,723
Major maintenance expenses....................... 6,508 6,538 1,115 1,278 1,844
Production taxes................................. 6,408 7,607 2,933 2,853 3,475
Depreciation, depletion and amortization......... 158,893 110,859 101,105 98,457 40,038
Write-down of oil and gas properties............. 237,741 - - 114,341 -
Interest expense................................. 4,895 9,395 15,186 15,017 5,768
Bad debt expense (1)............................. 2,343 - - - -
Merger expenses.................................. 25,785 1,297 - - -
Non-cash derivative expense...................... 2,604 - - - -
Salaries, general and administrative costs....... 13,004 12,725 10,764 8,636 7,509
Incentive compensation plan...................... 523 1,722 1,510 763 833
--------- --------- --------- --------- ---------
Total expenses................................. 506,268 191,617 165,985 267,663 74,190
--------- --------- --------- --------- ---------
Net income (loss) before income taxes.............. (107,772) 194,549 54,779 (102,344) 21,517
--------- --------- --------- --------- ---------
Income tax provision (benefit):
Current.......................................... (489) 450 25 23 (471)
Deferred......................................... (35,908) 67,642 17,688 (35,843) 8,053
--------- --------- --------- --------- ---------
Total income tax provision (benefit)........... (36,397) 68,092 17,713 (35,820) 7,582
--------- --------- --------- --------- ---------
Net income (loss).................................. ($71,375) $126,457 $37,066 ($66,524) $13,935
========= ========= ========== ========= =========

Earnings and dividends per common share:
Basic net income (loss) per common share ........ ($2.73) $4.90 $1.61 ($3.23) $0.72
===== ===== ===== ===== =====
Diluted net income (loss) per common share ...... ($2.73) $4.80 $1.58 ($3.23) $0.71
===== ===== ===== ===== =====
Cash dividends declared.......................... - - - - -

CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes)...... $286,758 $300,097 $154,152 $110,869 $62,450
Net cash provided by operating activities.......... 315,617 302,082 123,010 118,014 43,606

BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit) ......................... ($18,097) $53,065 $12,509 ($3,340) ($1,708)
Oil and gas properties, net........................ 993,906 747,574 587,661 492,349 437,832
Total assets ...................................... 1,101,783 944,104 706,958 581,134 515,426
Long-term debt, less current portion............... 426,000 148,000 134,000 289,936 143,077
Stockholders' equity .............................. 530,025 587,577 452,870 213,131 277,975

(1) Relates to 100% allowance for production receivable due from Enron
Corp recorded during the fourth quarter of 2001.

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

The following discussion is intended to assist in understanding our
financial position and results of operations for each of the years in the
three-year period ended December 31, 2001. Our Financial Statements and the
notes thereto, which are found elsewhere in this Form 10-K, contain detailed
information that should be referred to in conjunction with the following
discussion. See "Item 8. Financial Statements and Supplementary Data."

OVERVIEW

We are an independent oil and gas company engaged in the acquisition,
exploration, development and operation of oil and gas properties onshore and in
shallow waters of the Gulf of Mexico and in several basins in the Rocky
Mountains. We have been active in the Gulf Coast Basin since 1973, which gives
us extensive geophysical, technical and operational expertise in this area.

Our revenue, profitability and future rate of growth are dependent upon the
prices of oil and natural gas. Over the last few years, the prices of oil and
gas have been highly volatile. The increased volatility was attributable to a
variety of factors impacting supply and demand, including seasonal, political
and economic events we can neither control nor predict.

Oil and gas prices generally peaked at the beginning of 2001 and generally
declined throughout the remainder of the year. Our realized gas-equivalent price
for the fourth quarter of 2001 was 51% less than our realized gas-equivalent
price in the first quarter of 2001. Historically, the cost to acquire oil and
gas properties moves in relation to the prices of oil and gas. When prices began
to fall in early 2001, we set out to acquire a package of properties that fit
our strategic characteristics.

Over the last several years, we have financed our capital expenditures
primarily with cash flow from operations. By not burdening our capital structure
with a high percentage of debt, we were able to access the credit markets to
quickly complete the $300 million Conoco property acquisition on December 31,
2001.

Our 2002 capital expenditures budget is currently approximately $200
million, or 36% less than 2001's capital expenditures, excluding acquisitions.
The decline in estimated capital investment is due to our outlook on 2002 oil
and gas prices and our intent to once again finance our capital expenditures
primarily with cash flow from operations. The decline in drilling and operating
costs and services should enable us to evaluate wells at a much lower cost than
in 2001.

To the extent that 2002 cash flow from operations exceed our estimated 2002
capital expenditures, we plan to pay down a portion of our existing debt. In the
event that cash flow from operations during 2002 is not sufficient to fund
estimated 2002 capital expenditures, we believe that our bank credit facility,
under which we have $106.7 million of available borrowings at March 15, 2002,
will provide us with adequate liquidity.

RESULTS OF OPERATIONS

The following table sets forth certain operating information with respect
to our oil and gas operations and summary information with respect to our
estimated proved oil and gas reserves. See "Item 2. Properties - Oil and Gas
Reserves."

YEAR ENDED DECEMBER 31,
------------------------------------------------
2001 2000 1999
------------- ------------ -------------

PRODUCTION:
Oil (MBbls).................................................. 4,023 4,449 4,324
Gas (MMcf) .................................................. 68,236 72,239 65,513
Oil and gas (MMcfe) ......................................... 92,374 98,933 91,457
AVERAGE SALES PRICES: (1)
Oil (per Bbl)................................................ $25.62 $26.66 $16.19
Gas (per Mcf) ............................................... 4.29 3.64 2.27
Oil and gas (per Mcfe) ...................................... 4.28 3.86 2.39
AVERAGE COSTS (Per Mcfe):
Normal operating costs (2)................................... $0.51 $0.42 $0.36
Salaries, general and administrative costs................... 0.14 0.13 0.12
DD&A on oil and gas properties............................... 1.70 1.10 1.08
RESERVES AT DECEMBER 31:
Oil (MBbls).................................................. 55,391 33,625 35,213
Gas (MMcf)................................................... 442,669 398,524 385,667
Oil and gas (MMcfe).......................................... 775,015 600,274 596,945
Present value of estimated future net cash flows before
income taxes (in thousands)............................... $1,038,797 $2,941,790 $830,606
Standardized measure of discounted future net cash flows
(in thousands)............................................ $908,576 $1,982,749 $691,481

(1) Includes the effects of hedging.
(2) Excludes major maintenance expenses.

2001 COMPARED TO 2000. For the year 2001, we reported a net loss totaling
$71.4 million, or $2.73 per share, compared to net income for the year ended
December 31, 2000 of $126.5 million, or $4.80 per share. The variance in annual
results was due to the following components:

PRODUCTION. During 2001, production volumes totaled 92.4 Bcfe compared to
98.9 Bcfe produced during 2000. Natural gas production during 2001 decreased 6%
to approximately 68.2 billion cubic feet compared to 2000 gas production of 72.2
billion cubic feet, while oil production during 2001 totaled approximately 4.0
million barrels compared to 4.4 million barrels produced during 2000.

The decrease in 2001 production rates, compared to 2000, was the combined
result of our 2001 drilling program providing less than expected production
growth and normal production declines.

PRICES. Prices realized during 2001 averaged $25.62 per barrel of oil and
$4.29 per Mcf of gas compared to 2000 average realized prices of $26.66 per
barrel of oil and $3.64 per Mcf of gas. All unit pricing amounts include the
cash effects of hedging.

From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. Hedging
transactions increased the average price we received during 2001 for oil by
$0.37 per barrel and decreased the average price received for natural gas by
$0.04 per Mcf, compared to net decreases of $3.55 per barrel and $0.46 per Mcf
realized during 2000.

OIL AND GAS REVENUE. As a result of higher realized prices on a Mcfe basis,
oil and gas revenues increased 4% to $395.5 million in 2001 from $381.9 million
during 2000.

EXPENSES. Normal operating costs during 2001 increased to $47.6 million,
compared to $41.5 million during 2000. On a unit of production basis, 2001
operating costs were $0.51 per Mcfe as compared to $0.42 per Mcfe for 2000. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.

Production tax expense for 2001 decreased to $6.4 million from $7.6 million
in 2000 primarily due to decreased production volumes from onshore properties.

Depreciation, depletion and amortization (DD&A) expense on our oil and gas
properties totaled $157.2 million, or $1.70 per Mcfe, compared to $109.2
million, or $1.10 per Mcfe, for 2000. Higher drilling costs, higher unit reserve
replacement costs and declining oil and gas prices used in computing
amortization under the future gross revenue method contributed to the increased
DD&A expense during 2001.

We follow the full cost method of accounting for oil and gas properties.
Based upon low oil and gas prices at the end of the third quarter of 2001, we
recognized a ceiling test write-down of our oil and gas properties totaling
$237.7 million, or $154.5 million after taxes. This expense did not impact our
cash flow from operations but did reduce net income and stockholders' equity.

As a result of having no outstanding obligations on our bank debt for a
majority of 2001 and an increase in capitalized interest on unevaluated
properties, interest expense for 2001 decreased to $4.9 million, compared to
$9.4 million during 2000.

Due to Enron Corp's financial difficulties, during the fourth quarter of
2001, we recorded a 100% allowance for a production accounts receivable due from
Enron Corp. This allowance resulted in a 2001 charge of approximately $2.3
million to bad debt expense.

Our merger with Basin was completed on February 1, 2001. In connection with
the completion of the merger, we incurred expenses during 2001 totaling $25.8
million. Merger expenses incurred by Basin during 2000 totaled $1.3 million.

RESERVES. At December 31, 2001, our estimated proved oil and gas reserves
totaled 775.0 Bcfe, compared to December 31, 2000 reserves of 600.3 Bcfe.
Estimated proved gas reserves grew to 442.7 Bcf at the end of 2001 from 398.5
Bcf at year-end 2000, and estimated proved oil reserves grew to 55.4 MMBbls at
the end of 2001 from 33.6 MMBbls at the beginning of the year.

The increases in our 2001 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions during the year. The reserve
estimates were prepared by independent petroleum consultants in accordance with
guidelines established by the SEC. Adherence to these guidelines limited us in
booking reserves on successfully drilled wells to the extent of the base of
known productive sands. Actual limits of the productive sands will ultimately be
determined through production or additional drilling.

Our present values of estimated future net cash flows before income taxes
were $1.0 billion and $2.9 billion at December 31, 2001 and 2000, respectively.
You should not assume that the present values of estimated future net cash flows
represent the fair value of our estimated oil and gas reserves. As required by
the SEC, we determine the present value of estimated future net cash flows using
market prices for oil and gas on the last day of the fiscal period. The average
year-end oil and gas prices on all of our properties used in determining these
amounts, excluding the effects of hedges in place at year-end, were $18.64 per
barrel and $2.79 per Mcf for 2001 and $27.30 per barrel and $9.97 per Mcf for
2000.

2000 COMPARED TO 1999. For the year 2000, we reported record net income
totaling $126.5 million, or $4.80 per share, compared to net income for the year
ended December 31, 1999 of $37.1 million, or $1.58 per share. The favorable
results in net income were due to improvements in the following components:

PRODUCTION. During 2000, production volumes reached a record high totaling
98.9 Bcfe compared to 91.5 Bcfe produced during 1999. Natural gas production
during 2000 increased 10% to approximately 72.2 billion cubic feet compared to
1999 gas production of 65.5 billion cubic feet, while oil production during 2000
increased to approximately 4.4 million barrels compared to 4.3 million barrels
produced during 1999.

The increase in 2000 production rates, compared to 1999, was due to
drilling results at several of our fields, the most significant of which were
Eugene Island Block 243 and East Cameron Block 64.

PRICES. Prices realized during 2000 averaged $26.66 per barrel of oil and
$3.64 per Mcf of gas. This represents a 62% increase, on a Mcfe basis, over 1999
average realized prices of $16.19 per barrel of oil and $2.27 per Mcf of gas.
All unit pricing amounts include the effects of hedging.

Due to increases in commodity prices throughout 2000, hedging transactions
reduced the average price we received during the year for oil by $3.55 per
barrel and for gas by $0.46 per Mcf, compared to net decreases of $1.72 per
barrel and $0.06 per Mcf realized during 1999.

OIL AND GAS REVENUE. As a result of higher production rates and realized
prices, oil and gas revenue increased 75% to $381.9 million, compared to 1999
oil and gas revenue of $218.4 million.

EXPENSES. Normal operating costs during 2000 increased to $41.5 million,
compared to $33.4 million during 1999. On a unit of production basis, 2000
operating costs were $0.42 per Mcfe compared to $0.36 per Mcfe for 1999. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.

During 2000, we performed significant workover operations on nine wells at
three fields. As a result, major maintenance expenses for the year totaled $6.5
million compared to $1.1 million for 1999.

Due to increased 2000 onshore production volumes combined with higher oil
and gas prices, production revenue from onshore properties increased 100%. As a
result, production tax expense increased to $7.6 million from $2.9 million in
1999. Included in the 1999 amount was a $1 million production tax refund related
to the abatement of severance taxes for certain wells under Louisiana state law.

Depreciation, depletion and amortization expense on our oil and gas
properties totaled $109.2 million, or $1.10 per Mcfe, compared to $99.2 million,
or $1.08 per Mcfe, for 1999. The higher DD&A rate was partially attributable to
the rising costs of oil and gas exploration and development activities during
2000.

Salaries, general and administrative expenses for 2000 increased in total
to $12.7 million, or $0.13 per Mcfe, from $10.8 million, or $0.12 per Mcfe,
during 1999. Due to our operational and financial results and our stock price
performance during the year, incentive compensation expense for 2000 increased
to $1.7 million compared to $1.5 million in 1999.

Interest expense for 2000 decreased to $9.4 million, compared to $15.2
million during 1999, due primarily to the repayment of approximately $120
million of borrowings under Stone's bank credit facility in August 1999.

RESERVES. At December 31, 2000, our estimated proved oil and gas reserves
totaled 600.3 Bcfe, compared to December 31, 1999 reserves of 596.9 Bcfe.
Estimated proved gas reserves grew to 398.5 Bcf at the end of 2000 from 385.7
Bcf at year-end 1999, while estimated proved oil reserves declined to 33.6
MMBbls at the end of 2000 from 35.2 MMBbls at the beginning of the year.

Our reserve estimates at December 31, 2000 were prepared by independent
petroleum consultants in accordance with guidelines established by the SEC.
Adherence to these guidelines limits our recognition of proved reserves on
successfully drilled wells to the extent of the base of known productive sands.
Actual limits of the productive sands will ultimately be determined through
production or additional drilling.

Our present values of estimated future net cash flows before income taxes
were $2.9 billion and $830.6 million at December 31, 2000 and 1999,
respectively. You should not assume that the present values of estimated future
net cash flows represent the fair value of our estimated proved oil and gas
reserves. As required by the SEC, we determine the present value of estimated
future net cash flows using market prices for oil and gas on the last day of the
fiscal period. The average year-end oil and gas prices on all of our properties
used in determining these amounts, excluding the effects of hedges in place at
year-end, were $27.30 per barrel and $9.97 per Mcf for 2000 and $24.83 per
barrel and $2.42 per Mcf for 1999.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOW AND WORKING CAPITAL. Net cash flow from operations before working
capital changes for 2001 was $286.8 million, or $10.98 per share, compared to
$300.1 million, or $11.40 per share, reported for 2000. Working capital at
December 31, 2001 totaled ($18.1) million. Our working capital balance is not a
good indication of our liquidity because it fluctuates as a result of borrowings
or repayments under our credit facility and the timing of capital expenditures.

CAPITAL EXPENDITURES. Capital expenditures during 2001 totaled $641.3
million and included $10.4 million of capitalized general and administrative
costs, net of reimbursements, and $6.0 million of capitalized interest. These
investments were financed by borrowings under our bank credit facility, net
proceeds from the December 2001 bond offering, cash flows from operations and
working capital.

To the extent 2002 cash flow from operations exceed our estimated 2002
capital expenditures, we plan to pay down a portion of our existing debt. In the
event that cash flow from operations during 2002 is not sufficient to fund
estimated 2002 capital expenditures, we believe that our bank credit facility
will provide us with adequate liquidity.

We do not budget acquisitions; however, we are currently evaluating several
opportunities that fit our specific acquisition profile. One or a combination of
certain of these possible transactions could fully utilize our existing sources
of capital. Although we have no plans to access the public markets for purposes
of capital, if the opportunity arose, we would consider such funding sources to
provide capital in excess of what is currently available to us.

BANK CREDIT FACILITY. At December 31, 2001, we had $126 million of
borrowings outstanding under our credit facility and letters of credit totaling
$7.3 million had been issued pursuant to the facility. During December 2001, we
increased our credit facility to $350 million. We currently have a loan base
under the amended credit facility of $250 million with availability of an
additional $106.7 million in borrowings as of March 15, 2002. Stone's borrowing
base under the amended credit facility, which is redetermined periodically, is
based on an amount established by the bank group for Stone's oil and gas
properties.

Our credit facility provides for certain covenants, including restrictions
or requirements with respect to debt to EBITDA ratio, net worth, disposition of
properties, incurrence of additional debt, change of ownership and reporting
responsibilities. These covenants may limit or prohibit us from paying cash
dividends.

HEDGING. See "Item 7A. Quantitative and Qualitative Disclosure About Market
Risk - Commodity Price Risk."

NEW ACCOUNTING STANDARDS. In July 2001, the Financial Accounting Standards
Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 141,
"Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible
Assets." SFAS No. 141 prohibits the use of the pooling-of-interest method of
accounting for all business combinations initiated after June 30, 2001. SFAS No.
142 requires that goodwill not be amortized in any circumstances and also
requires goodwill to be tested for impairment annually or when events or
circumstances occur between annual tests indicating that goodwill for a
reporting unit might be impaired. The standard establishes a new method for
testing goodwill for impairment based on a fair value concept and is effective
for fiscal years beginning after December 15, 2001. The adoption of SFAS Nos.
141 and 142 is not expected to have a material impact on our financial
statements, because we do not have any goodwill recorded.

In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations," effective for fiscal years beginning after June 15,
2002. This statement will require us to record the fair value of liabilities
related to future asset retirement obligations in the period the obligation is
incurred. We expect to adopt SFAS No. 143 on January 1, 2003. Upon adoption, we
will be required to recognize cumulative transition amounts for existing asset
retirement obligation liabilities, asset retirement costs and accumulated
depreciation. We have not yet determined the transition amounts.

FORWARD-LOOKING STATEMENTS

Certain of the statements set forth under this item and elsewhere in this
Form 10-K are forward-looking and are based upon assumptions and anticipated
results that are subject to numerous risks and uncertainties. See "Item 1.
Business -- Forward-Looking Statements" and " -- Risk Factors."

ACCOUNTING MATTERS AND CRITICAL ACCOUNTING POLICIES

BASIS OF PRESENTATION. The financial statements include our accounts, the
accounts of our wholly owned subsidiaries and our proportionate share of certain
partnerships. On December 31, 1999, these partnerships were dissolved after
their assets were transferred to us. All intercompany balances and transactions
that existed prior to these dissolutions have been eliminated.

FULL COST METHOD. We use the full cost method of accounting for our oil and
gas properties. Under this method, all acquisition and development costs,
including certain related employee costs and general and administrative costs
(less any reimbursements for such costs), incurred for the purpose of acquiring
and finding oil and gas are capitalized.

We amortize our investment in oil and gas properties through DD&A using the
future gross revenue method. Under this method, the annual provision for DD&A is
computed by dividing revenue earned during the period by future gross revenues
at the beginning of the period, and applying the resulting rate to the cost of
oil and gas properties, including estimated future development, restoration,
dismantlement and abandonment costs.

We capitalize a portion of the interest costs incurred on our debt.
Capitalized interest is calculated using the amount of our unevaluated property
and our effective borrowing rate. We also capitalize the portion of employee,
general and administrative costs that are attributable to our acquisition,
exploration and development activities.

Under the full cost method of accounting, we are required to periodically
compare the present value of estimated future net cash flows from proved
reserves (based on period-end commodity prices) to the net capitalized costs of
proved oil and gas properties. We refer to this comparison as a "ceiling test."
If the net capitalized costs of proved oil and gas properties exceed the
estimated discounted future net cash flows from proved reserves, we are required
to write-down the value of our oil and gas properties to the value of the
discounted cash flows.

RESERVES. Estimates of our oil and gas reserves are prepared by our
independent petroleum and geological engineers. Proved reserves and the cash
flow related to these reserves are estimated based upon a combination of
historical data and estimates of future activity. Reserve estimates are used in
calculating DD&A and in preparation of the full cost ceiling test.

USE OF ESTIMATES. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires us
to make estimates and assumptions that affect the reported amounts of assets and
liabilities, the 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.
Estimates are used primarily when accounting for depreciation, depletion and
amortization, unevaluated property costs, estimated future net cash flows,
taxes, reserves of accounts receivable, capitalized employee, general and
administrative costs, fair value of financial instruments, the purchase price
allocation on properties acquired and contingencies.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES. Under SFAS No. 133, as
amended, the nature of a derivative instrument must be evaluated to determine if
it qualifies for hedge accounting treatment. We do not use derivative
instruments for trading purposes. Instruments qualifying for hedge accounting
treatment are recorded as an asset or liability measured at fair value and
subsequent changes in fair value are recognized in equity through other
comprehensive income, net of related taxes, to the extent the hedge is
effective. Instruments not qualifying for hedge accounting treatment are
recorded in the balance sheet and changes in fair value are recognized in
earnings.

DEFERRED INCOME TAXES. Deferred income taxes have been determined in
accordance with SFAS No. 109, "Accounting for Income Taxes." As of December 31,
2001, we had deferred taxes of $35.6 million which was calculated based on our
assumption that it is more likely than not that we will have sufficient taxable
income in future years to utilize certain tax attribute carryforwards.

For a more complete discussion of our accounting policies see our Notes to
Consolidated Financial Statements on page F-7.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

COMMODITY PRICE RISK

Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Oil and
gas price declines and volatility could adversely affect our revenues, cash
flows and profitability. In order to manage our exposure to oil and gas price
declines, we occasionally enter into oil and gas price hedging arrangements to
secure a price for a portion of our expected future production. We do not enter
into hedging transactions for trading purposes. While intended to reduce the
effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:

o our production is less than expected;

o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge
arrangement;

o the counterparties to our hedging contracts fail to perform the
contracts; or

o a sudden, unexpected event materially impacts oil or gas prices.

Our hedging policy provides that not more than one-half of our production
quantities can be hedged without the consent of the Board of Directors.

HEDGING. During 2001, we realized a net reduction in revenue from our
hedging transactions of $1.8 million. Our contracts totaled 1,278 MBbls of oil
and 29,300 BBtus of gas, which represented approximately 32% and 43%,
respectively, of our oil and gas production for the year. During 2000, we
realized a net reduction in revenue from our hedging transactions of $47.9
million. Our contracts totaled 1,868 MBbls of oil and 29,303 BBtus of gas, which
represented approximately 42% and 41%, respectively, of our oil and gas
production for that year. The net reduction in revenue from hedging transactions
for 1999 was $11.3 million. Our contracts totaled 2,094 MBbls of oil and 44,949
BBtus of gas, which represented approximately 48% and 69%, respectively, of our
oil and gas production for that year.

Our oil put contracts are with Bank of America, N.A. and our gas put
contracts are with J. Aron & Co. Put contracts are purchased at a rate per unit
of hedged production that fluctuates with the commodity futures market. The
historical cost of the put contracts represents our maximum cash exposure. We
are not obligated to make any further payments under the put contracts
regardless of future commodity price fluctuations. Under put contracts, monthly
payments are made to us if prices fall below the agreed upon floor price, while
allowing us to fully participate in commodity prices above that floor.

During 2001, we recognized $3.1 million of hedge premium expenses, which
represents amortization of the historical cost associated with oil and gas put
contracts that settled during the year.

Fixed price swaps typically provide for monthly payments by us if NYMEX
prices rise above the fixed swap price or to us if NYMEX prices fall below the
fixed swap price.

Since over 90% of our production has historically been derived from the
Gulf Coast Basin, we believe that fluctuations in prices will closely match
changes in the market prices we receive for our production. Oil contracts
typically settle using the average of the daily closing prices for a calendar
month. Natural gas contracts typically settle using the average closing prices
for near month NYMEX futures contracts for the three days prior to the
settlement date.

The following tables show our hedging positions as of January 1, 2002:

PUTS
----------------------------------------------------------------------------------------------
GAS OIL
-------------------------------------------- ---------------------------------------------
VOLUME COST VOLUME COST
(BBTUS) FLOOR (MILLIONS) (BBLS) FLOOR (MILLIONS)
----------- ----------- ------------ ----------- ------------- -------------

2002..................... 21,900 $3.50 $5.2 1,277,500 $24.00 $3.2

FIXED PRICE GAS SWAPS
------------------------------
VOLUME
(BBTUS) PRICE
------------- -------------
2002.................... 3,650 $2.15
2003.................... 3,650 2.15

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

At December 31, 2000, our oil put contracts were reflected as assets at a
historical cost of $5 million and, in accordance with generally accepted
accounting principles in effect at year-end 2000, our fixed price gas swap
contracts were not reflected in the financial statements since they were
costless. Our gas put contracts were purchased in January 2001 and therefore
were not reflected in the December 31, 2000 balance sheet. At December 31, 2000,
the fair values of our oil put contracts and fixed price gas swaps were $7.7
million and ($42.8) million, respectively.

We adopted SFAS No. 133 effective January 1, 2001. Upon adoption of SFAS
No. 133, as amended, the after-tax increase in fair value over historical cost
of our oil put contracts of $1.7 million was a transition adjustment that was
recorded as a gain in equity through other comprehensive income. In addition,
the fair market value of the fixed price gas swaps was recorded as a liability
and the corresponding after-tax loss of $27.8 million was recorded in equity
through other comprehensive income. Our put contracts at December 31, 2001 were
considered effective cash flow hedges and changes in fair value of these
contracts are reflected in other comprehensive income, net of related taxes.

Our natural gas swap contracts are with a subsidiary of Enron Corp. Due to
Enron's financial difficulties, there is no assurance that we will receive full
or partial payment of any amounts that may become owed to us under these
contracts. Accordingly, these swaps no longer qualify as effective hedges under
SFAS No. 133. As a result, the changes in fair value for each period will now be
recorded through earnings and amounts previously recorded in other comprehensive
income will be amortized through earnings over the remaining life of the swaps.
At December 31, 2001, other comprehensive income included $4.1 million related
to the ineffective gas swaps that will be amortized over the remaining life of
the swaps. Included in the 2001 non-cash derivative expense is a $0.2 million
gain from amortization of other comprehensive income and a $0.3 million gain
related to the change in fair value of the swaps.

Stone uses sensitivity analysis techniques to evaluate the hypothetical
effect that changes in the market prices of oil and gas may have on the fair
value of our commodity hedging instruments. Stone had open oil and gas put
positions at December 31, 2001 with a positive fair value of $26.2 million. As
of March 1, 2002, a 10% increase in the underlying price of oil would have
reduced the fair value of the oil puts by approximately $2.3 million. A 10%
increase in the underlying price of natural gas as of March 1, 2002, would have
reduced the fair value of our gas puts by approximately $3.3 million. At
December 31, 2001, we also had open natural gas swap positions with a negative
fair value of $5.8 million. As of March 1, 2002, a 10% increase in the
underlying price of natural gas would have increased the negative fair value of
the swaps by approximately $1.9 million. The fair value of our derivative
instruments was based upon quotes obtained from the counterparties to the hedge
agreements.

INTEREST RATE RISK

At December 31, 2001, Stone had long-term debt outstanding of $426 million.
Of this amount, $300 million, or 70%, bears interest at fixed rates averaging
8.4%. The remaining $126 million of debt outstanding at the end of 2001 bears
interest at a floating rate. Because the majority of our long-term debt at
December 31, 2001 were at fixed rates, we consider our interest rate exposure at
such date to be minimal. At December 31, 2001, we had no open interest rate
hedge positions to reduce our exposure to changes in interest rates.

FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of cash and cash equivalents, net accounts receivable,
accounts payable and bank debt approximated book value at December 31, 2001. At
December 31, 2001, the fair value of the 8 3/4% Senior Subordinated Notes due
2007 totaled $101.7 million and the fair value of the 8 1/4% Senior Subordinated
Notes due 2011 totaled $201.9 million. The fair values of the Notes have been
estimated based on quotes from brokers.

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.

PART III

For information concerning Item 10. Directors and Executive Officers of the
Registrant, Item 11. Executive Compensation, Item 12. Security Ownership of
Certain Beneficial Owners and Management and Item 13. Certain Relationships and
Related Transactions, see the definitive Proxy Statement of Stone Energy
Corporation relating to the Annual Meeting of Stockholders to be held on May 16,
2002, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference. For information concerning Item 10, see also
"Part I - Item 4A. Executive Officers of the Registrant," set forth above in
this Form 10-K.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) 1. FINANCIAL STATEMENTS:

The following financial statements and the Report of Independent Public
Accountants thereon are included on pages F-1 through F-22 of this Form 10-K.

Report of Independent Public Accountants

Consolidated Balance Sheet as of December 31, 2001 and 2000

Consolidated Statement of Operations for the three years in the period
ended December 31, 2001

Consolidated Statement of Cash Flows for the three years in the period
ended December 31, 2001

Consolidated Statement of Changes in Stockholders' Equity for the three
years in the period ended December 31, 2001

Notes to the 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:

3.1 -- Certificate of Incorporation of the Registrant, as
amended (incorporated by reference to Exhibit 3.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).

3.2 -- Restated Bylaws of the Registrant (incorporated by reference
to Exhibit 3.2 to the Registrant's Registration Statement on
Form S-1 (Registration No. 33-62362)).

3.3 -- Certificate of Amendment of the Certificate of Incorporation
of Stone Energy Corporation, dated February 1, 2001
(incorporated by Reference to Exhibit 4.1 to the Registrant's
Form 8-K, dated February 7, 2001).

4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as
of October 15, 1998, between Stone Energy Corporation and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form 8-A (File No. 001-12074)).

4.2 -- Indenture between Stone Energy Corporation and Texas Commerce
Bank, National Association dated as of September 19, 1997
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form S-4 dated October 22, 1997 (File
No. 333-38425)).

4.3 -- Amendment No. 1, dated as of October 28, 2000, to Rights
Agreement dated as of October 15, 1998, between Stone Energy
Corporation and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent (incorporated by reference to Exhibit 4.4 to the
Registrant's Registration Statement on Form S-4 (Registration No.
333-51968)).

4.4 -- Indenture between Stone Energy Corporation and JPMorgan Chase
Bank dated December 10, 2001 (incorporated by reference to
Exhibit 4.4 to the Registrant's Registration Statement on Form
S-4 (Registration No. 333-81380)).

+10.1 -- Stone Energy Corporation 1993 Nonemployee Directors' Stock
Option Plan (incorporated by reference to Exhibit 10.1 to the
Registrant's Registration Statement on Form S-1 (Registration No.
33-62362)).

+10.2 -- Deferred Compensation and Disability Agreements between TSPC
and D. Peter Canty dated July 16, 1981, and between TSPC and Joe
R. Klutts and James H. Prince dated August 23, 1981 and September
20, 1981, respectively (incorporated by reference to Exhibit 10.8
to the Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).

+10.3 -- Conveyances of Net Profits Interests in certain properties to
D. Peter Canty and James H. Prince (incorporated by reference to
Exhibit 10.9 to the Registrant's Registration Statement on Form
S-1 (Registration No. 33-62362)).

+10.4 -- Deferred Compensation and Disability Agreement between TSPC
and E. J. Louviere dated July 16, 1981 (incorporated by reference
to Exhibit 10.10 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1995 (File No. 001-12074)).

+10.5 -- Stone Energy Corporation 2000 Amended and Restated Stock
Option Plan (incorporated by reference to Appendix A to the
Registrant's Definitive Proxy Statement on Schedule 14A for
Stone's 2000 Annual Meeting of Stockholders (File No.
001-12074)).

+10.6 -- Stone Energy Corporation Annual Incentive Compensation Plan
(incorporated by reference to Exhibit 10.14 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1993
(File No. 001-12074)).

+10.7 -- Stone Energy Corporation Amendment to the Annual Incentive
Compensation Plan dated January 15, 1997 (incorporated by
reference to Exhibit 10.9 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 2000 (File No.
001-12074)).

10.8 -- Fourth Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and Bank of
America, N.A., as administrative agent, dated as of December 20,
2001. (incorporated by reference to Exhibit 10.3 to the
Registrant's Registration Statement on Form S-4 (Registration No.
333-81380)).

+10.9 -- Stone Energy Corporation 2001 Amended and Restated Stock
Option Plan (incorporated by reference to Exhibit 4.1 to the
Registrant's Registration Statement on Form S-8 (Registration No.
333-64448)).

*21.1 -- Subsidiaries of the Registrant.

*23.1 -- Consent of Arthur Andersen LLP.

*23.2 -- Consent of Atwater Consultants, Ltd.

*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.

*23.4 -- Consent of Ryder Scott Company.
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.

(b) REPORTS ON FORM 8-K

Stone filed the following report on Form 8-K during the fourth quarter
of 2001:

Form 8-K filed by the Registrant on November 28, 2001 (press release
dated November 26, 2001 announcing updated agreement to acquire
properties from Conoco Inc.).

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act, as amended,
the Registrant has duly caused this Form 10-K to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Lafayette, State of
Louisiana, on the 19th day of March 2002.

STONE ENERGY CORPORATION

By: /s/ D. PETER CANTY
-------------------
D. Peter Canty
President and
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act, this Form 10-K
has been signed by the following persons in the capacities and on the dates
indicated.

SIGNATURE TITLE DATE
--------- ----- ----

/s/ James H. Stone Chairman of the Board March 19, 2002
- ---------------------------------------
James H. Stone

/s/ Joe R. Klutts Vice Chairman of the Board March 19, 2002
- ---------------------------------------
Joe R. Klutts

/s/ D. Peter Canty President, Chief Executive Officer March 19, 2002
- --------------------------------------- and Director
D. Peter Canty (principal executive officer)

/s/ James H. Prince Vice President - Chief Financial March 19, 2002
- --------------------------------------- Officer and Treasurer
James H. Prince (principal financial officer)

/s/ J. Kent Pierret Vice President - Controller March 19, 2002
- --------------------------------------- and Chief Accounting Officer
J. Kent Pierret (principal accounting officer)

/s/ Peter K. Barker Director March 19, 2002
- ---------------------------------------
Peter K. Barker

/s/ Robert A. Bernhard Director March 19, 2002
- ---------------------------------------
Robert A. Bernhard

/s/ B.J. Duplantis Director March 19, 2002
- ---------------------------------------
B.J. Duplantis

/s/ Raymond B. Gary Director March 19, 2002
- ---------------------------------------
Raymond B. Gary

/s/ John P. Laborde Director March 19, 2002
- ---------------------------------------
John P. Laborde

/s/ Richard A. Pattarozzi Director March 19, 2002
- ---------------------------------------
Richard A. Pattarozzi

/s/ David R. Voelker Director March 19, 2002
- ---------------------------------------
David R. Voelker

INDEX TO FINANCIAL STATEMENTS

Report of Independent Public Accountants.............................. F-2

Consolidated Balance Sheet of Stone Energy Corporation as of
December 31, 2001 and 2000......................................... F-3

Consolidated Statement of Operations of Stone Energy Corporation for
the years ended December 31, 2001, 2000 and 1999................... F-4

Consolidated Statement of Cash Flows of Stone Energy Corporation
for the years ended December 31, 2001, 2000 and 1999............... F-5

Consolidated Statement of Changes in Stockholders' Equity of Stone
Energy Corporation for the years ended
December 31, 2001, 2000 and 1999.................................. F-6

Notes to Consolidated Financial Statements........................... F-7

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Stockholders of
Stone Energy Corporation:

We have audited the accompanying consolidated balance sheets of Stone Energy
Corporation (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 Stone Energy Corporation and
subsidiaries as of December 31, 2001 and 2000, and the consolidated results of
their operations and their cash flows 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 1 to the consolidated financial statements, effective
January 1, 2001, the Company adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities."

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
February 21, 2002

STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)

DECEMBER 31,
---------------------------------
ASSETS 2001 2000
------ -------------- -------------

Current assets:
Cash and cash equivalents................................................... $13,155 $78,557
Marketable securities, at market............................................ - 300
Accounts receivable......................................................... 46,987 95,722
Other current assets........................................................ 1,832 2,916
Put contracts............................................................... 26,207 1,847
-------------- -------------
Total current assets...................................................... 88,181 179,342
-------------- -------------
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $1,015,455 and $620,510, respectively..................... 880,534 691,883
Unevaluated................................................................. 113,372 55,691
Building and land, net of accumulated depreciation of $598 and
$465, respectively........................................................ 5,352 4,914
Fixed assets, net of accumulated depreciation of $9,387 and $8,059,
respectively.............................................................. 4,883 4,441
Other assets, net of accumulated depreciation and amortization
of $1,932 and $1,499, respectively........................................ 9,461 4,681
Put contracts................................................................... - 3,152
-------------- -------------
Total assets.............................................................. $1,101,783 $944,104
============== =============

LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------

Current liabilities:
Accounts payable to vendors................................................. $69,197 $83,423
Undistributed oil and gas proceeds.......................................... 23,741 32,858
Deferred taxes.............................................................. 5,312 -
Fair value of swap contracts................................................ 2,194 -
Other accrued liabilities................................................... 5,834 9,996
-------------- -------------
Total current liabilities................................................. 106,278 126,277

Long-term debt.................................................................. 426,000 148,000
Production payments............................................................. 4,323 10,906
Deferred taxes.................................................................. 30,244 68,926
Fair value of swap contracts.................................................... 3,619 -
Other long-term liabilities..................................................... 1,294 2,418
-------------- -------------
Total liabilities......................................................... 571,758 356,527
-------------- -------------

Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 26,190,270 and 25,981,000 shares, respectively....... 262 260
Treasury stock (39,650 shares at cost).......................................... (2,057) -
Additional paid-in capital...................................................... 449,111 440,729
Retained earnings............................................................... 75,213 146,588
Other comprehensive income...................................................... 7,496 -
-------------- -------------
Total stockholders' equity................................................ 530,025 587,577
-------------- -------------
Total liabilities and stockholders' equity................................ $1,101,783 $944,104
============== =============

The accompanying notes are an integral part of this balance sheet.

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)

YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
2001 2000 1999
----------------- ----------------- -----------------

Revenues:
Oil and gas production........................................ $395,499 $381,938 $218,415
Other revenue................................................. 2,997 4,228 2,349
----------------- ----------------- -----------------
Total revenues.............................................. 398,496 386,166 220,764
----------------- ----------------- -----------------

Expenses:
Normal lease operating expenses............................... 47,564 41,474 33,372
Major maintenance expenses.................................... 6,508 6,538 1,115
Production taxes.............................................. 6,408 7,607 2,933
Depreciation, depletion and amortization...................... 158,893 110,859 101,105
Write-down of oil and gas properties.......................... 237,741 - -
Interest...................................................... 4,895 9,395 15,186
Salaries, general and administrative costs.................... 13,004 12,725 10,764
Incentive compensation plan................................... 523 1,722 1,510
Non-cash derivative expense................................... 2,604 - -
Merger expenses............................................... 25,785 1,297 -
Bad debt expense.............................................. 2,343 - -
----------------- ----------------- -----------------
Total expenses.............................................. 506,268 191,617 165,985
----------------- ----------------- -----------------
Net income (loss) before income taxes ............................ (107,772) 194,549 54,779
----------------- ----------------- -----------------
Income tax provision (benefit):
Current....................................................... (489) 450 25
Deferred...................................................... (35,908) 67,642 17,688
----------------- ----------------- -----------------
Total income taxes.......................................... (36,397) 68,092 17,713
----------------- ----------------- -----------------
Net income (loss)................................................. ($71,375) $126,457 $37,066
================= ================= =================
Earnings (loss) per common share:

Basic earnings (loss) per share............................... ($2.73) $4.90 $1.61
================= ================= =================
Diluted earnings (loss) per share ............................ ($2.73) $4.80 $1.58
================= ================= =================
Average shares outstanding.................................... 26,111 25,804 22,954
================= ================= =================
Average shares outstanding assuming dilution.................. 26,111 26,335 23,416
================= ================= =================

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)

YEAR ENDED DECEMBER 31,
-------------------------------------------------------
2001 2000 1999
--------------- ---------------- ---------------

Cash flows from operating activities:
Net income (loss)............................................... ($71,375) $126,457 $37,066
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization................... 158,893 110,859 101,105
Deferred income tax provision (benefit).................... (35,908) 67,642 17,688
Non-cash effect of production payments..................... (6,199) (5,784) (2,981)
Write-down of oil and gas properties....................... 237,741 - -
Other non-cash expenses.................................... 3,606 923 1,274
--------------- ---------------- ---------------
286,758 300,097 154,152

(Increase) decrease in marketable securities................ 300 34,606 (18,053)
(Increase) decrease in accounts receivable.................. 48,735 (45,661) (13,223)
(Increase) decrease in other current assets................. 733 2,040 (1,663)
Increase (decrease) in other accrued liabilities........... (13,279) 15,258 6,285
Investment in put contracts................................ (6,466) (4,999) -
Other...................................................... (1,164) 741 (4,488)
--------------- ---------------- ---------------
Net cash provided by operating activities........................... 315,617 302,082 123,010
--------------- ---------------- ---------------
Cash flows from investing activities:
Investment in oil and gas properties............................ (657,327) (259,074) (165,664)
Sale of unevaluated properties.................................. 1,366 4,302 10,630
Building additions and renovations.............................. - (1,160) (405)
Increase in other assets........................................ (886) (2,705) (3,128)
--------------- ---------------- ---------------
Net cash used in investing activities............................... (656,847) (258,637) (158,567)
--------------- ---------------- ---------------

Cash flows from financing activities:
Proceeds from borrowings........................................ 131,000 59,500 67,500
Repayment of debt............................................... (53,000) (45,500) (223,782)
Proceeds from issuance of 8 1/4% notes.......................... 200,000 - -
Deferred financing costs........................................ (6,794) (200) (538)
Proceeds from common stock offerings............................ - - 198,242
Expenses from common stock offerings............................ - - (844)
Proceeds from exercise of stock options......................... 4,822 4,404 2,048
Purchase of treasury stock...................................... (200) (743) (299)
--------------- ---------------- ---------------

Net cash provided by financing activities........................... 275,828 17,461 42,327
--------------- ---------------- ---------------

Net increase (decrease) in cash and cash equivalents................ (65,402) 60,906 6,770
Cash and cash equivalents beginning of year......................... 78,557 17,651 10,881
--------------- ---------------- ---------------

Cash and cash equivalents end of year............................... $13,155 $78,557 $17,651
=============== ================ ===============

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)........................ $3,992 $8,793 $15,648
Income taxes................................................ - 450 25

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(Dollar amounts in thousands)

ADDITIONAL RETAINED OTHER TOTAL
COMMON TREASURY PAID-IN EARNINGS COMPREHENSIVE STOCKHOLDERS'
STOCK STOCK CAPITAL (DEFICIT) INCOME EQUITY
----------- ---------- -------------- ----------- --------------- --------------

Balance, December 31, 1998........... $207 ($2,571) $232,430 ($16,935) - $213,131
Net income ........................ - - - 37,066 - 37,066
Sale of common stock............... 49 - 198,193 - - 198,242
Expenses from common
stock offerings............... - - (844) - - (844)
Exercise of stock options.......... 1 - 2,047 - - 2,048
Stock compensation plans........... - - 370 - - 370
Tax benefit from stock
option exercises.............. - - 1,467 - - 1,467
Exercise of warrants for
common stock.................. - (1,716) 1,716 - - -
Purchase of treasury stock......... - (669) - - - (669)
Issuance and vesting of
restricted stock.............. 1 - 2,058 - - 2,059
Retirement of treasury stock....... (1) 4,956 (4,955) - - -
----------- ---------- -------------- ----------- --------------- --------------
Balance, December 31, 1999........... 257 - 432,482 20,131 - 452,870
Net income......................... - - - 126,457 - 126,457
Exercise of stock options.......... 3 - 4,401 - - 4,404
Stock compensation plans........... 1 - 2,442 - - 2,443
Tax benefit from stock option
exercises..................... - - 3,657 - - 3,657
Purchase of treasury stock......... - (3,185) - - - (3,185)
Issuance and vesting of
restricted stock.............. - - 931 - - 931
Retirement of treasury stock....... (1) 3,185 (3,184) - - -
----------- ---------- -------------- ----------- --------------- --------------
Balance, December 31, 2000........... 260 - 440,729 146,588 - 587,577
Net loss........................... - - - (71,375) - (71,375)
Cumulative effect of accounting
change for derivatives........ - - - - (26,114) (26,114)
Net change in fair value of
derivatives................... - - - - 33,720 33,720
Effect of change in accounting
treatment for swaps........... - - - - (110) (110)
--------------
Total comprehensive loss........... (63,879)

Exercise of stock options.......... 2 - 6,677 - - 6,679
Tax benefit from stock option - - 1,499 - - 1,499
exercises....................
Purchase of treasury stock......... - (2,057) - - - (2,057)
Issuance and vesting of
restricted stock.............. - - 206 - - 206
----------- ---------- -------------- ----------- --------------- --------------
Balance, December 31, 2001........... $262 ($2,057) $449,111 $75,213 $7,496 $530,025
=========== ========== ============== =========== =============== ==============

The accompanying notes are an integral part of this statement.

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands except per share and price amounts)

NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploration, development and operation of oil and gas
properties in the Gulf Coast Basin and Rocky Mountains.

Our business strategy is to increase production, cash flow and reserves
through the acquisition and development of mature properties. Currently, our
property base consists of 87 active properties, 55 in the Gulf Coast Basin and
32 in the Rocky Mountains, and 39 primary term leases. We serve as operator on
56 of our active properties, which enables us to better control the timing and
cost of rejuvenation activities. We believe that there will continue to be
opportunities to acquire properties in the Gulf Coast Basin due to the increased
focus by major and large independent companies on projects away from the onshore
and shallow water shelf regions of the Gulf of Mexico.

We are headquartered in Lafayette, Louisiana, with additional offices in
New Orleans, Louisiana, Houston, Texas and Denver, Colorado.

A summary of significant accounting policies followed in the preparation of
the accompanying consolidated financial statements is set forth below:

MERGER WITH BASIN EXPLORATION:

On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination of
the two companies in a tax-free, stock-for-stock transaction accounted for under
the pooling-of-interests method. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25,000,000 to 100,000,000 shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. Stone issued 7,436,652
shares of common stock. In addition, Stone assumed, and subsequently retired
with cash on hand, $48,000 of Basin bank debt. The expenses incurred in relation
to the merger totaled $25,785 in 2001. Merger expenses incurred by Basin in 2000
totaled $1,297.

The following table reconciles certain of Stone's pre-merger operating
results with results reflecting the restatement of our financial statements
under the pooling-of-interest method of accounting:

2000 1999
-------------------------------------------- -----------------------------------------------
EFFECTS OF EFFECTS OF
STONE POOLING AS REPORTED STONE POOLING AS REPORTED
------------ ------------ ------------ -------------- ------------ -------------

Revenue............... $260,379 $125,787 $386,166 $149,134 $71,630 $220,764
Net income............ 84,945 41,512 126,457 26,490 10,576 37,066

The financial information above does not purport to be indicative of the
results of operations that would have occurred had the merger taken place at the
beginning of the earliest period presented or future results of operations.

BASIS OF PRESENTATION:

In accordance with the pooling-of-interests method of accounting for
business combinations, the financial position and results of operations were
combined to give effect to the combination of Stone and Basin as if the merger
occurred at the beginning of the earliest period presented. Prior to the merger,
Basin accounted for depreciation, depletion and amortization (DD&A) of oil and
gas properties using the units of production method. In connection with the
restatement of our financial statements on a pooling-of-interests basis, Basin's
historical provision for DD&A was restated to conform to the future gross
revenue method used by Stone. This restatement included related adjustments to
Basin's historical reduction in carrying value of oil and gas properties
recorded at the end of 1998 and their historical provision for income taxes. All
periods presented reflect the effects of these adjustments.

We reclassified certain amounts in Basin's historical financial statements
to conform to Stone's presentation.

The financial statements include our accounts, the accounts of our wholly
owned subsidiaries and our proportionate interest in certain partnerships. These
partnerships were dissolved on December 31, 1999. All intercompany balances have
been eliminated. Certain prior year amounts have been reclassified to conform to
current year presentation.

USE OF ESTIMATES:

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates
and assumptions that affect the reported amounts of assets and liabilities, the
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. Estimates
are used primarily when accounting for depreciation, depletion and amortization,
unevaluated property costs, estimated future net cash flows, taxes, reserves of
accounts receivable, capitalized employee, general and administrative costs,
fair value of financial instruments, the purchase price allocation on properties
acquired and contingencies.

FAIR VALUE OF FINANCIAL INSTRUMENTS:

The fair value of cash and cash equivalents, accounts receivable, accounts
payable to vendors and our variable-rate bank debt approximated book value at
December 31, 2001 and 2000. The following table presents the carrying amounts
and estimated fair values of our financial instruments at December 31, 2001 and
2000.

2001 2000
------------------------------ -------------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
------------- ------------- ------------- --------------

8 1/4% Senior Subordinated Notes due 2011... $200,000 $201,880 $ - $ -
8 3/4% Senior Subordinated Notes due 2007... 100,000 101,690 100,000 102,000
Put contracts............................... 26,207 26,207 4,999 7,669
Swap contracts.............................. (5,813) (5,813) - (42,846)

The following methods and assumptions were used to estimate the fair value
of the financial instruments detailed above. The carrying amount of the bank
debt approximated fair value because the interest rate is variable and
reflective of market rates. The fair value of the Notes has been estimated based
on quotes obtained from brokers. The fair value of the oil and gas price hedges
are based upon quotes obtained from the counterparties to the hedge agreements.

CASH AND CASH EQUIVALENTS:

We consider all highly liquid investments in overnight securities through
our commercial bank accounts, which result in available funds on the next
business day, to be cash and cash equivalents.

OIL AND GAS PROPERTIES:

We follow the full cost method of accounting for oil and gas properties.
Under this method, all acquisition, exploration and development costs, including
certain related employee and general and administrative costs (less any
reimbursements for such costs) and interest incurred for the purpose of finding
oil and gas is capitalized. Such amounts include the cost of drilling and
equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals and other costs related to such activities. Employee, general and
administrative costs that are capitalized include salaries and all related
fringe benefits paid to employees directly engaged in the acquisition,
exploration and development of oil and gas properties, as well as all other
directly identifiable general and administrative costs associated with such
activities, such as rentals, utilities and insurance. Fees received from managed
partnerships for providing such services are accounted for as a reduction of
capitalized costs. Employee, general and administrative costs associated with
production operations and general corporate activities are expensed in the
period incurred.

Our investment in oil and gas properties is amortized through DD&A using
the future gross revenue method whereby the annual provision is computed by
dividing revenue earned during the period by future gross revenues at the
beginning of the period, and applying the resulting rate to the cost of oil and
gas properties, including estimated future development, restoration,
dismantlement and abandonment costs. Transactions involving sales of unevaluated
properties are recorded as adjustments to oil and gas properties and sales of
reserves in place, unless extraordinarily large portions of reserves are
involved, are recorded as adjustments to accumulated depreciation, depletion and
amortization.

Oil and gas properties included $113,372 and $55,691 of unevaluated
property and related costs that were not being amortized at December 31, 2001
and 2000, respectively. The remainder of the unevaluated costs were associated
with the acquisition and evaluation of unproved properties and major development
projects expected to entail significant costs to ascertain quantities of proved
reserves. We believe that a majority of unevaluated properties at December 31,
2001 will be evaluated within one to 24 months. The excluded costs and related
reserve volumes will be included in the amortization base as the properties are
evaluated and proved reserves are established or impairment is determined.
Interest capitalized on unevaluated properties during the years ended December
31, 2001 and 2000 was $6,000 and $4,027, respectively.

On December 31, 2001, Stone completed the acquisition of eight producing
oil and gas properties and related assets located in the Gulf of Mexico from
Conoco. The purchase price of approximately $300,000 was financed with net
proceeds from the December 2001 offering of $200,000 8 1/4% Senior Subordinated
Notes due 2011 and borrowings under the bank credit facility. This acquisition
was accounted for under the purchase method of accounting. At December 31, 2001,
$53,117 of the acquisition cost was allocated to unevaluated properties based on
our analysis of the acquired properties.

The following unaudited pro forma information details estimated operating
results for 2001 and 2000 assuming the acquisition occurred on January 1, 2000:

YEAR ENDED DECEMBER 31,
-------------------------------------
2001 2000
---------------- -----------------

Revenues......................................... $513,266 $542,545
Net income....................................... 17,879 177,208
Diluted net income per share..................... $0.68 $6.73

The pro forma financial information does not purport to be indicative of
the results of operations that would have occurred had the acquisition taken
place at the beginning of the earliest period presented or future results of
operations.

BUILDING AND LAND:

Building and land are recorded at cost. Our Lafayette office building is
being depreciated on the straight-line method over its estimated useful life of
39 years.

FIXED ASSETS:

Fixed assets at December 31, 2001 and 2000 included approximately $2,593
and $2,764, respectively, of computer hardware and software costs, net of
accumulated depreciation. These costs are being depreciated on the straight-line
method over an estimated useful life of five years.

OTHER ASSETS:

Other assets at December 31, 2001 and 2000 included approximately $9,291
and $2,637, respectively, of deferred financing costs, net of accumulated
amortization, related to the issuance of the 8 3/4% and 8 1/4% Notes and the
amendment of the credit facility (see Note 7). The costs associated with the
Notes are being amortized over the life of the Notes using the effective
interest method. The costs associated with the credit facility are being
amortized on the straight-line method over the term of the facility.

EARNINGS PER COMMON SHARE:

Basic net income per share of common stock was calculated by dividing net
income applicable to common stock by the weighted-average number of common
shares outstanding during the year. Diluted net income per share of common stock
was calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the year plus the
weighted-average number of outstanding dilutive stock options granted to outside
directors, officers and employees. There were approximately, 531,000 and 462,000
weighted-average dilutive shares for the years ending December 31, 2000 and 1999
respectively. In 2001, all stock options were considered antidilutive because of
the net loss incurred during the year. Options that were considered antidilutive
because the exercise price of the stock exceeded the average price for the
applicable period totaled approximately 279,000 shares and 71,000 shares during
2000 and 1999, respectively.

GAS PRODUCTION REVENUE:

We record as revenue only that portion of gas production sold and allocable
to our ownership interest in the related well. Any gas production proceeds
received in excess of our ownership interest are reflected as a liability in the
accompanying balance sheet.

Revenues relating to net undelivered gas production to which we are
entitled but for which we have not received payment are not recorded in the
financial statements until such amounts are received. These amounts at December
31, 2001, 2000 and 1999 were immaterial.

INCOME TAXES:

Income taxes are accounted for in accordance with Statement of Financial
Accounting Standard (SFAS) No. 109, "Accounting for Income Taxes." 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 related to evaluated
projects are capitalized and depreciated, depleted and amortized on the future
gross revenue 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, we follow certain provisions
of the Internal Revenue Code that allow capitalization of intangible drilling
costs where management deems appropriate. Other financial and income tax
reporting differences occur as a result of statutory depletion, different
reporting methods for sales of oil and gas reserves in place, and different
reporting methods used in the capitalization of employee, general and
administrative and interest expenses.

NEW ACCOUNTING STANDARDS:

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other
Intangible Assets." SFAS No. 141 prohibits the use of the pooling-of-interest
method of accounting for all business combinations initiated after June 30,
2001. SFAS No. 142 requires that goodwill not be amortized in any circumstances
and also requires goodwill to be tested for impairment annually or when events
or circumstances occur between annual tests indicating that goodwill for a
reporting unit might be impaired. The standard establishes a new method for
testing goodwill for impairment based on a fair value concept and is effective
for fiscal years beginning after December 15, 2001. The adoption of SFAS Nos.
141 and 142 is not expected to have a material impact on our financial
statements, because we do not have any goodwill recorded.

DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:

Under SFAS No. 133, as amended, the nature of a derivative instrument must
be evaluated to determine if it qualifies for hedge accounting treatment.
Instruments qualifying for hedge accounting treatment are recorded as an asset
or liability measured at fair value and subsequent changes in fair value are
recognized in equity through other comprehensive income, net of related taxes,
to the extent the hedge is effective. Instruments not qualifying for hedge
accounting treatment are recorded in the balance sheet and changes in fair value
are recognized in earnings. At December 31, 2001, our put contracts were
considered effective cash flow hedges, while our gas swap contracts, with a
subsidiary of Enron, were not considered effective due to Enron's financial
difficulties. (See Note 9)

NOTE 2 -- ACCOUNTS RECEIVABLE:

In our capacity as operator for our co-venturers, we incur drilling and
other costs that we bill to the respective parties based on their working
interests. We also receive payments for these billings and, in some cases, for
billings in advance of incurring costs. Our accounts receivable are comprised of
the following amounts:

DECEMBER 31,
-------------------------------------
2001 2000
----------------- ----------------

Accounts Receivable:
Other co-venturers.............................................. $11,211 $12,697
Trade........................................................... 35,371 75,670
Officers and employees.......................................... 4 22
Unbilled accounts receivable.................................... 401 7,333
----------------- ----------------
$46,987 $95,722
================= ================

NOTE 3 -- CONCENTRATIONS:

SALES TO MAJOR CUSTOMERS

Our production is sold without collateral on month-to-month contracts at
prevailing prices. The following table identifies customers from whom we derived
10% or more of our total oil and gas revenue during the following years ended:

DECEMBER 31,
------------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------

Adams Resources Energy, Inc................. (a) (a) 10%
Columbia Energy Services.................... (a) (a) 16%
Duke Energy Corporation .................... (a) 11% (a)
Dynegy, Incorporated ....................... (a) (a) 11%
El Paso Merchant Energy, LP................. 26% 13% (a)
Enron North America Corporation............. 19% 10% (a)
Northridge Energy Marketing................. (a) (a) 12%

(a) less than 10 percent

We believe that the loss of any of these purchasers would not result in a
material adverse effect on our ability to market future oil and gas production.

During the fourth quarter of 2001, we recorded a $2,343 bad debt expense to
reserve 100% of production accounts receivable from Enron Corp.

PRODUCTION VOLUMES

Production from South Pelto Block 23 and Eugene Island Block 243 each
accounted for approximately 16% of our total oil and gas production volumes
during 2001.

CASH DEPOSITS

Substantially all of our cash balances are in excess of federally insured
limits.

NOTE 4 -- INVESTMENT IN OIL AND GAS PROPERTIES:

The following table discloses certain financial data relative to our oil
and gas producing activities, which are located onshore and offshore the
continental United States:

YEAR ENDED DECEMBER 31,
--------------------------------------------------------
2001 2000 1999
---------------- ---------------- ----------------

Oil and gas properties--
Balance, beginning of year..................................... $1,368,084 $1,098,940 $904,456
Costs incurred during year:
Capitalized--
Acquisition costs, net of sales of unevaluated properties . 328,778 15,086 27,316
Exploratory drilling....................................... 176,679 138,420 66,848
Development drilling....................................... 119,426 98,004 86,218
Employee, general and administrative costs and interest.... 16,720 19,234 15,440
Less: overhead reimbursements.............................. (326) (1,600) (1,338)
---------------- ---------------- ----------------

Total costs incurred during year........................... 641,277 269,144 194,484
---------------- ---------------- ----------------

Balance, end of year........................................... $2,009,361 $1,368,084 $1,098,940
================ ================ ================

Charged to expense--
Operating costs:
Normal lease operating expenses............................ $47,564 $41,474 $33,372
Major maintenance expenses................................. 6,508 6,538 1,115
---------------- ---------------- ----------------
Total operating costs...................................... 54,072 48,012 34,487
Production taxes........................................... 6,408 7,607 2,933
---------------- ---------------- ----------------
$60,480 $55,619 $37,420
================ ================ ================
Unevaluated oil and gas properties--
Costs incurred during year:
Acquisition costs.......................................... $77,311 $22,760 $22,381
Exploration costs.......................................... - 6,229 806
---------------- ---------------- ----------------
$77,311 $28,989 $23,187
================ ================ ================
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year................................. ($620,510) ($511,279) ($412,107)
Provision for depreciation, depletion and amortization..... (157,204) (109,231) (99,172)
Write-down of oil and gas properties....................... (237,741) - -
---------------- ---------------- ----------------
Balance, end of year........................................... (1,015,455) (620,510) (511,279)
================ ================= ================
Net capitalized costs (proved and unevaluated)..................... $993,906 $747,574 $587,661
================ ================= ================
DD&A per Mcfe...................................................... $1.70 $1.10 $1.08
================ ================= ================

At December 31, 2001 and 2000, unevaluated oil and gas properties of
$113,372 and $55,691, respectively, were not subject to depletion. Of the
$113,372 in unevaluated costs at December 31, 2001, $77,311 was incurred in 2001
and $36,061 was incurred in prior years. We believe that a majority of
unevaluated properties will be evaluated within one to 24 months.

NOTE 5 -- INCOME TAXES:

An analysis of our deferred taxes follows:

AS OF DECEMBER 31,
--------------------------------
2001 2000
--------------- ---------------

Net operating loss carryforward............................ $9,795 $8,056
Statutory depletion carryforward........................... 4,787 4,527
Contribution carryforward.................................. 158 112
Capital loss carryforward.................................. 43 43
Alternative minimum tax credit carryforward................ 812 1,142
Temporary differences:
Oil and gas properties-- full cost................... (48,617) (83,773)
Hedges............................................... (4,214) -
Other................................................ 1,838 967
Valuation allowance....................................... (158) -
--------------- ---------------
($35,556) ($68,926)
=============== ===============

For tax reporting purposes, operating loss carryforwards totaled
approximately $27,984 at December 31, 2001. If not utilized, such carryforwards
would begin expiring in 2009 and would completely expire by the year 2021. In
addition, we had approximately $14,195 in statutory depletion deductions
available for tax reporting purposes that may be carried forward indefinitely.
Recognition of a deferred tax asset associated with these carryforwards is
dependent upon our evaluation that it is more likely than not that the asset
will ultimately be realized.

During 1999, our provision for income taxes was net of a $1,460 reduction
in deferred taxes related to estimates of tax basis that were resolved during
1999. In order to conform Stone and Basin's accounting methods, we recognized
the $5,729 tax benefit related to Basin's 1998 write-down of oil and gas
properties by reversing the valuation allowance that Basin recorded in 1998.
This resulted in additional deferred tax benefit for the year ended December 31,
1998 and deferred tax expense for the years ended December 31, 1999 and 2000.
During 1999 and 2000, Basin had previously reduced its effective tax rate
through the reversal of the valuation allowance recorded in 1998.
Reconciliations between the statutory federal income tax rate and our effective
income tax rate as a percentage of income before income taxes follow:

YEAR ENDED DECEMBER 31,
----------------------------------------
2001 2000 1999
------------- ----------- ------------

Income tax expense (benefit) computed at the statutory
federal income tax rate.................................... (35%) 35% 35%
Non-deductible portion of merger expenses...................... 2% - -
Other.......................................................... (1%) - (3%)
------------- ----------- ------------
Effective income tax rate...................................... (34%) 35% 32%
============= =========== ============

Income tax expense allocated to other comprehensive income amounted to
$4,036 for 2001.

NOTE 6-- PRODUCTION PAYMENTS:

In June 1999, we acquired a 100% working interest in the Lafitte Field by
executing an agreement that included a dollar-denominated production payment to
be satisfied through the sale of production from the purchased property. At that
time, we recorded a production payment of $4,600 representing the estimated
discounted present value of production payments to be made. As provided for in a
separate agreement, on September 23, 1999, Goodrich Petroleum Company, L.L.C.
exercised its option to participate for a 49% working interest in the Lafitte
Field resulting in a reduction of the production payment to $2,346 at September
30, 1999. At December 31, 2001, the production payment associated with this
transaction totaled $1,335.

In July 1999, we acquired an additional working interest in East Cameron
Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a
volumetric production payment. This agreement requires that 7.3 MMcf of gas per
day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have
been distributed. At the transaction date, we recorded a volumetric production
payment of $17,926 representing the estimated discounted cash flows associated
with the specific production volumes to be delivered. We amortize the volumetric
production payment as specified deliveries of gas are made to the seller and
recognize non-cash revenue in the form of gas production revenue. At December
31, 2001, the volumetric production payment was $2,988 and gas revenues of
$5,975 were recognized during 2001.

NOTE 7 -- LONG-TERM DEBT:

Long-term debt consisted of the following at:

DECEMBER 31,
------------------------------
2001 2000
-------------- -------------

8 1/4% Senior subordinated notes due 2011................................... $200,000 $ -
8 3/4% Senior subordinated notes due 2007................................... 100,000 100,000
Bank debt................................................................ 126,000 48,000
-------------- -------------
Total long-term debt..................................................... $426,000 $148,000
============== =============

On December 5, 2001, we issued $200,000 8 1/4% Senior Subordinated Notes
due 2011. The Notes were sold at par value and we received net proceeds of
$195,500. There are no sinking fund requirements and the Notes are redeemable at
our option, in whole but not in part, at any time before December 15, 2006 at a
Make-Whole amount. Beginning December 15, 2006, the Notes are redeemable at our
option, in whole or in part, at 104.125% of their principal amount and
thereafter at prices declining annually to 100% on and after December 15, 2009.
In addition, before December 15, 2004, we may redeem up to 35% of the aggregate
principal amount of the Notes issued with net proceeds from an equity offering
at 108.25%. The Notes provide for certain covenants which include, without
limitation, restrictions on liens, indebtedness, asset sales, dividend payments
and other restricted payments. At December 31, 2001, $723 had been accrued in
connection with the June 15, 2002 interest payment.

At December 31, 2001 and 2000, long-term debt included of $100,000 8 3/4%
Senior Subordinated Notes due 2007 and there were no minimum principal payments
due for the next five years. At December 31, 2001, $2,601 had been accrued in
connection with the March 15, 2002 interest payment. The Notes were sold at a
discount for an aggregate price of $99,283. There are no sinking fund
requirements on the Notes and they are redeemable at our option, in whole or in
part, at 104.375% of their principal amount beginning September 15, 2002, and
thereafter at prices declining annually to 100% on and after September 15, 2005.
The Notes provide for certain covenants which include, without limitation,
restrictions on liens, indebtedness, asset sales, dividend payments and other
restricted payments.

At December 31, 2001, we had $126,000 of borrowings outstanding under our
bank credit facility and letters of credit totaling $7,347 had been issued
pursuant to the facility. During December 2001, we increased our credit facility
to $350,000. The amended credit facility matures on December 20, 2004. At
December 31, 2001, Stone had $116,653 of borrowings available under the amended
credit facility. The weighted average interest rate under the amended credit
facility was approximately 3.4% at December 31, 2001. Interest rates are tied to
LIBOR rates plus a margin that fluctuates based upon the ratio of aggregate
outstanding borrowings and letters of credit exposure to the total borrowing
base. Commitment fees are computed and payable quarterly at the rate of 50 basis
points of borrowing availability. The borrowing base limitation is re-determined
periodically and is based on a borrowing base amount established by the banks
for our oil and gas properties. Our credit facility provides for certain
covenants, including restrictions or requirements with respect to debt to EBITDA
ratio, tangible net worth, disposition of properties, incurrence of additional
debt, change of ownership and reporting responsibilities. These covenants may
limit or prohibit us from paying cash dividends.

Concurrent with closing the merger on February 1, 2001, borrowings of
$48,000 outstanding under Basin Exploration's bank credit facility were repaid
with cash on hand and the credit facility was terminated.

NOTE 8 -- TRANSACTIONS WITH RELATED PARTIES:

James H. Stone and Joe R. Klutts, both directors of Stone Energy,
collectively own 9% of the working interest in certain wells drilled on Section
19 on the east flank of Weeks Island Field. These interests were acquired at the
same time that our predecessor company acquired its interests in Weeks Island
Field. In their capacity as working interest owners, they are required to pay
their proportional share of all costs and are entitled to receive their
proportional share of revenues.

Our interests in certain oil and gas properties are burdened by various net
profit interests granted at the time of acquisition to certain of our officers
and other employees. Such net profit interest owners do not receive any cash
distributions until we have recovered all acquisition, development, financing
and operating costs. We believe the estimated value of these interests at the
time of acquisition is not material to our financial position or results of
operations. Effective January 1, 2001, we acquired the net profit interests from
our employees through a final settlement payment and discontinued this benefit
program. Two of our officers remain net profit interest owners. Amounts paid to
officers under the remaining net profits arrangement amounted to $1,777, $1,085
and $79 in 2001, 2000 and 1999, respectively.

We received certain fees as a result of our function as managing partner of
certain partnerships. These partnerships were dissolved on December 31, 1999.
All participants in the partnerships, including four of our directors, James H.
Stone, Joe R. Klutts, Raymond B. Gary and Robert A. Bernhard, received
overriding royalty interests in the related properties in exchange for their
partnership interests. For the year ended December 31, 1999, management fees and
overhead reimbursements from partnerships totaled $224, the majority of which
was treated as a reduction of our investment in oil and gas properties. Until
their dissolution, we collected and distributed production revenue as managing
partner for the partnerships' interests in oil and gas properties.

In June 2000, we purchased property that adjoins our Lafayette office, from
StoneWall Associates for an independently appraised value of approximately $540.
Two of our directors, James H. Stone and Joe R. Klutts, are partners of
StoneWall Associates.

Joe R. Klutts received $56 and $41 during 2001 and 2000, respectively, in
consulting fees after retiring, February 1, 2000, as an employee of Stone.

Laborde Marine Lifts, Inc., of which John P. Laborde, one of our Directors
and Audit Committee members, is Chairman, provided services to us during 2000.
The value of these services was approximately $75. Additionally, Laborde Marine
LLC, in which Mr. Laborde's son has an interest, provided services to us during
2001 in the amount of $255.

The law firm of Gordon, Arata, McCollam, Duplantis and Eagan, of which B.J.
Duplantis, one of our Directors and Audit Committee members, is a Senior
Partner, provided legal services for us during 2001 and 2000. The value of these
services totaled approximately $20 and $9 during 2001 and 2000, respectively.

NOTE 9 -- HEDGING ACTIVITIES:

We enter into hedging transactions to secure a price for a portion of
future production that is acceptable at the time at which the transaction is
entered. The primary objective of these activities is to reduce our exposure to
the possibility of declining oil and gas prices during the term of the hedge.
These hedges are designated as cash flow hedges when entered into. We do not
enter into hedging transactions for trading purposes. Monthly settlements of
these contracts are reflected in revenue from oil and gas production. Under
generally accepted accounting principles beginning January 1, 2001, in order to
consider these futures contracts as hedges, (i) we must designate the futures
contract as a hedge of future production and (ii) the contract must be effective
at reducing our exposure to the risk of changes in prices. Changes in the market
values of futures contracts treated as hedges are not recognized in income until
the hedged item is also recognized in income. If the above criteria are not met,
we will record the market value of the contract at the end of each month and
recognize a related increase or decrease in oil and gas revenue. Any amount
received or paid related to terminated contracts are amortized over the original
contract period and reflected in revenue from oil and gas production.

At December 31, 2000, our oil put contracts were reflected as assets at a
historical cost of $4,999 and, in accordance with generally accepted accounting
principles in effect at year-end 2000, our fixed price gas swap contracts were
not reflected in the financial statements since they were costless. Our gas put
contracts were purchased subsequent to year-end and therefore were not reflected
in the December 31, 2000 balance sheet.

We adopted SFAS No. 133 effective January 1, 2001. Upon adoption of SFAS
No. 133, as amended, the after-tax increase in fair value over historical cost
of our oil put contracts of $1,736 was a transition adjustment that was recorded
as a gain in equity through other comprehensive income. In addition, the fair
market value of the fixed price gas swaps was recorded as a liability and the
corresponding after-tax loss of $27,850 was recorded in equity through other
comprehensive income.

At December 31, 2001, our oil and gas puts were reflected as assets at a
fair value of $26,207. Our oil put contracts are with Bank of America, N.A. and
our gas put contracts are with J. Aron & Co. Put contracts are purchased at a
rate per unit of hedged production that fluctuates with the commodity futures
market. The historical cost of the put contracts represents our maximum cash
exposure. We are not obligated to make any further payments under the put
contracts regardless of future commodity price fluctuations. Under put
contracts, monthly payments are made to us if NYMEX prices fall below the agreed
upon floor price, while allowing us to fully participate in commodity prices
above that floor. Our put contracts are considered effective hedges under SFAS
No. 133 and all changes in fair value are recorded, net of taxes, in other
comprehensive income.

In addition to put contracts, we utilized fixed price swaps to hedge a
portion of our future gas production. Fixed price swaps typically provide for
monthly payments by us if NYMEX prices rise above the fixed swap price or to us
if NYMEX prices fall below the fixed swap price. At December 31, 2001,our swap
contracts were reflected as liabilities at fair value of $5,813.

Our natural gas swap contracts are with a subsidiary of Enron Corp. Due to
Enron's financial difficulties, there is no assurance that we will receive full
or partial payment of any amounts that may become owed to us under these
contracts. Accordingly, these swaps no longer qualify as effective hedges under
SFAS No. 133. As a result, the changes in fair value for each period will now be
recorded through earnings and amounts previously recorded in other comprehensive
income will be amortized through earnings over the remaining life of the swaps.
At December 31, 2001, other comprehensive income included $4,109 related to the
natural gas swaps that will be amortized over the remaining life of the swap
contracts. Included in the 2001 non-cash derivative expense is a $169 gain from
amortization of other comprehensive income and a $340 gain related to the
changes in the fair value of the swaps.

Since over 90% of our production has historically been derived from the
Gulf Coast Basin, we believe that fluctuations in NYMEX prices will closely
match changes in the market prices we receive for our production. Oil contracts
typically settle using the average of the daily closing prices for a calendar
month. Natural gas contracts typically settle using the average closing prices
for near month NYMEX futures contracts for the three days prior to the
settlement date.

The following table shows our hedging positions as of January 1, 2002.

PUTS
---------------------------------------------------------------------------------------------
GAS OIL
-------------------------------------------- ---------------------------------------------
VOLUME VOLUME
(BBTUS) FLOOR COST (BBLS) FLOOR COST
----------- ----------- ------------ ----------- ------------- -------------

2002..................... 21,900 $3.50 $5,201 1,277,500 $24.00 $3,152

FIXED PRICE GAS SWAPS
---------------------------------------
VOLUME (BBTUS) PRICE
------------------- ---------------
2002..................... 3,650 $2.15
2003..................... 3,650 $2.15

For the years ended December 31, 2001, 2000 and 1999, we realized net
decreases in oil and gas revenue related to hedging transactions of $1,819,
$47,899, and $11,295, respectively.

NOTE 10 -- COMMON STOCK:

On February 1, 2001, our stockholders approved a proposal to amend our
certificate of incorporation, in connection with the Basin merger, increasing
the number of authorized shares of our common stock from 25,000,000 to
100,000,000.

On July 28, 1999, Stone Energy completed an offering of 3,162,500 shares of
its common stock at a price to the public of $43.75 per share. After payment of
the underwriting discount and related expenses, Stone received net proceeds of
$130,760.

On June 23, 1999, Basin Exploration completed an offering of 4,312,500
shares (approximately 1,713,788 shares post merger) of its common stock at a
price to the public of $16.50 per share (approximately $41.52 per share post
merger). After payment of the underwriting discount and related expenses, Basin
received net proceeds of $66,638.

NOTE 11 -- COMMITMENTS AND CONTINGENCIES:

We lease office facilities in New Orleans, Louisiana, Denver, Colorado and
at two locations in Houston, Texas under the terms of long-term, non-cancelable
leases expiring on April 4, 2003, March 15, 2005 and December 31, 2004 and March
31, 2006, respectively. We also lease automobiles under the terms of
non-cancelable leases expiring at various dates through 2004. The minimum net
annual commitments under all leases, subleases and contracts noted above at
December 31, 2001 were as follows:

2002................................ $1,075
2003................................ 1,046
2004................................ 1,045
2005................................ 508
2006................................ 98
Thereafter.......................... -

Payments related to our lease obligations for the years ended December 31,
2001, 2000 and 1999 were approximately $1,280, $1,146 and $859, respectively. We
sublease office space to third parties, and for the years ended 2001, 2000 and
1999 we recorded related receipts of $285, $181 and $186, respectively. Minimum
lease rentals to be received from the sublease of office space is $239 for each
of the years ended December 31, 2002, 2003 and 2004.

Until December 31, 1999, we were the managing general partner of eight
partnerships and are contingently liable for any recourse debts and other
liabilities that may result from their operations until dissolution. We are not
aware of the existence of any such liabilities that would have a material impact
on future operations.

We are contingently liable to surety insurance companies in the aggregate
amount of $41,304 relative to bonds issued on our behalf to the MMS, federal and
state agencies and certain third parties from which we purchased oil and gas
working interests. The bonds represent guarantees by the surety insurance
companies that we will operate in accordance with applicable rules and
regulations and perform certain plugging and abandonment obligations as
specified by applicable working interest purchase and sale agreements.

We are also named as a defendant in certain lawsuits and are a party to
certain regulatory proceedings arising in the ordinary course of business. We do
not expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.

NOTE 12 -- EMPLOYEE BENEFIT PLANS:

We have entered into deferred compensation and disability agreements with
certain of our officers whereby we have purchased split-dollar life insurance
policies to provide certain retirement and death benefits for certain of our
officers and death benefits payable to us. The aggregate death benefit of the
policies was $3,139 at December 31, 2001, of which $1,975 was payable to certain
officers or their beneficiaries and $1,164 was payable to us. Total cash
surrender value of the policies, net of related surrender charges at December
31, 2001, was approximately $994. Additionally, the benefits under the deferred
compensation agreements vest after certain periods of employment, and at
December 31, 2001, the liability for such vested benefits was approximately
$842. The difference between the actuarial determined liability for retirement
benefits or the vested amounts, where applicable, and the net cash surrender
value has been recorded as an other long-term asset.

We have adopted a series of incentive compensation plans designed to align
the interests of our directors and employees with those of our stockholders. The
following is a brief description of each of the plans:

i. The Annual Incentive Compensation Program provides for an annual cash
incentive bonus that ties incentives to the annual return on our common
stock, to a comparison of the price performance of our common stock to the
average quarterly returns on the shares of stock of a peer group of
companies with which we compete and to the growth in our net earnings, net
cash flows and net asset value. Incentive bonuses are awarded to
participants based upon individual performance factors. Stone incurred
expenses of $523, $1,722 and $1,510, net of amounts capitalized, for the
years ended December 31, 2001, 2000 and 1999, respectively, related to
incentive compensation bonuses paid under this program.

ii. The 2001 Amended and Restated Stock Option Plan provides for 3,225,000
shares of common stock to be reserved for issuance pursuant to this plan.
Under this plan, we may grant both incentive stock options qualifying under
Section 422 of the Internal Revenue Code and options that are not qualified
as incentive stock options to all employees and directors. All such options
must have an exercise price of not less than the fair market value of the
common stock on the date of grant. Stock options to all employees vest
ratably over a five-year service-vesting period and expire ten years
subsequent to award. Stock options issued to non-employee directors vest
ratably over a three-year service-vesting period and expire five years
subsequent to award.

iii. The Stone Energy 401(k) Profit Sharing Plan provides eligible employees
with the option to defer receipt of a portion of their compensation and we
may, at our discretion, match a portion or all of the employee's deferral.
The amounts held under the plan are invested in various investment funds
maintained by a third party in accordance with the directions of each
employee. An employee is 20% vested in matching contributions (if any) for
each year of service and is fully vested upon five years of service. For
the years ended December 31, 2001, 2000 and 1999, Stone contributed $688,
$445 and $313, respectively, to the plan.

The following Basin benefit plans were in effect during portions of the
periods presented but were terminated upon consummation of the merger on
February 1, 2001. Unless otherwise indicated, the following share amounts do not
reflect the conversion factor of .3974 of a share of Stone common stock for each
share of Basin common stock:

i. Basin Exploration had a 401(k) profit sharing plan. All Basin employees who
joined Stone were eligible to participate in Stone's 401(k) plan based on
years of service with Basin. In the month of January 2001, Basin
contributed $13 to the Basin 401(k) profit sharing plan prior to
termination. During 2000 and 1999, Basin contributed $383 and $241,
respectively, to the Basin 401(k) profit sharing plan.

ii. Under the Equity Incentive Plan, Basin's officers, key employees,
consultants and directors were eligible to receive incentive stock options,
non-qualified stock options, restricted stock and performance shares. At
December 31, 2000, approximately 1,599,000 shares were available for grant
under the plan. Of this total, an aggregate of 1,283,000 shares of Basin
common stock were subject to prior issuances under such plan, including
182,000 non-vested shares of restricted stock and performance shares and
1,100,000 outstanding stock options.

Basin granted 19,000 shares of restricted stock during 2000. Approximately
$206, $291 and $466 of related compensation expense was recognized during
2001, 2000 and 1999, respectively. As of December 31, 2001 only 2,514
shares of restricted stock, as converted to Stone shares, remained subject
to future vesting in 2002 and 2003. With the consummation of the merger,
no further grants of restricted stock were made and after the remaining
shares are vested this plan will be terminated.

Basin granted 50,000 and 55,000 performance shares during 2000 and 1999,
respectively. Expense was recognized based on vesting schedules,
projections of performance and changes in the price of Basin common
stock during the applicable vesting periods. Related compensation
expense of $640 and $1,593 was recognized during 2000 and 1999,
respectively. All outstanding performance shares at February 1, 2001
were forfeited.

In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which became effective with respect to us in 1996. Under SFAS No.
123, companies can either record expense based on the fair value of stock-based
compensation upon issuance or elect to remain under the current Accounting
Principles Board Opinion No. 25 ("APB 25") method whereby no compensation cost
is recognized upon grant if certain requirements are met. We have continued to
account for our stock-based compensation under APB 25. However, disclosures as
if we had adopted the expensed recognition provisions under SFAS No. 123 are
presented below.

If the compensation cost for stock-based compensation plans had been
determined consistent with the expense recognition provisions under SFAS No.
123, our 2001, 2000 and 1999 net income (loss) and basic and diluted earnings
(loss) per common share would have approximated the pro forma amounts below:

YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------------
2001 2000 1999
-------------------------- ------------------------- -------------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA AS REPORTED PRO FORMA
------------ ------------- ------------ ------------ ------------ ------------

Net income (loss)............. ($71,375) ($74,944) $126,457 $121,248 $37,066 $33,957
Earnings (loss) per common
share:
Basic................... ($2.73) ($2.87) $4.90 $4.70 $1.61 $1.48
Diluted................. ($2.73) ($2.87) $4.80 $4.60 $1.58 $1.45

A summary of stock options as of December 31, 2001, 2000 and 1999 and
changes during the years ended on those dates is presented below.

YEAR ENDED DECEMBER 31,
--------------------------------------------------------------------------------------------
2001 2000 1999
---------------------------- ---------------------------- --------------------------
WGTD. WGTD. WGTD.
NUMBER AVG. NUMBER AVG. NUMBER AVG.
OF EXER. OF EXER. OF EXER.
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
-------------- -------- --------------- --------- -------------- ----------

Outstanding at beginning of year.... 1,880,077 $34.39 1,771,668 $27.22 1,428,029 $21.95
Granted............................. 588,200 48.72 455,045 51.92 530,197 37.47
Expired............................. (163,861) 47.18 (13,000) 23.95 (34,923) 22.73
Exercised........................... (245,885) 28.81 (333,636) 20.52 (151,635) 15.96
--------------- --------------- --------------
Outstanding at end of year.......... 2,058,531 $38.04 1,880,077 $34.39 1,771,668 $27.22
Options exercisable at year-end..... 963,761 27.95 808,072 24.48 782,082 20.29
Options available for future grant.. 910,750 957,250 299,750
Weighted average fair value of
options granted during the year.. $23.86 28.65 $22.87

NOTE 12-- EMPLOYEE BENEFIT PLANS: (Continued)

The weighted average fair value of each option granted during the periods
presented is estimated on the date of grant using the Black-Scholes
option-pricing model with the following assumptions: (a) dividend yield of 0%,
(b) expected volatility of 44.24%, 45.72% and 47.18% in the years 2001, 2000 and
1999, respectively, (c) risk-free interest rate of 4.88%, 6.76% and 6.07% in the
years 2001, 2000 and 1999, respectively and (d) expected life of six years for
employee options and four years for director options.

The following table summarizes information regarding stock options
outstanding at December 31, 2001:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------------------------- -------------------------------
RANGE OF OPTIONS WGTD. AVG. WGTD. AVG. OPTIONS WGTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/01 CONTRACTUAL LIFE PRICE AT 12/31/01 PRICE
- --------------- --------------- --------------------- --------------- -------------- ----------------

$9 - $20 206,110 2.3 years $12.37 206,110 $12.37
20 - 30 490,154 4.6 years 24.09 412,830 23.67
30 - 40 585,145 6.8 years 36.83 226,620 36.04
40 - 50 146,000 8.5 years 45.80 30,200 45.44
50 - 61.93 631,122 7.8 years 56.59 88,001 57.73
--------------- --------------
2,058,531 6.2 years 38.04 963,761 27.95
=============== ==============

NOTE 13 -- OIL AND GAS RESERVE INFORMATION - UNAUDITED:

Our net proved oil and gas reserves at December 31, 2001 have been
estimated by independent petroleum consultants in accordance with guidelines
established by the Securities and Exchange Commission ("SEC"). Accordingly, the
following reserve estimates are based upon existing economic and operating
conditions at the respective dates.

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the market value of the oil and gas properties or the
cost that would be incurred to obtain equivalent reserves.

NOTE 13-- OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)

The following table sets forth an analysis of the estimated quantities of
net proved and proved developed oil (including condensate) and natural gas
reserves, all of which are located onshore and offshore the continental United
States:

NATURAL
OIL IN GAS
MBBLS IN MMCF
-------------- -------------

Proved reserves as of December 31, 1998..................................... 27,143 370,772
Revisions of previous estimates......................................... 3,961 (7,027)
Extensions, discoveries and other additions............................. 3,305 67,001
Purchase of producing properties........................................ 5,128 19,101
Production (1).......................................................... (4,324) (64,180)
-------------- -------------
Proved reserves as of December 31, 1999..................................... 35,213 385,667
Revisions of previous estimates......................................... (3,568) (10,499)
Extensions, discoveries and other additions............................. 6,375 85,534
Purchase of producing properties........................................ 54 7,394
Production (1).......................................................... (4,449) (69,572)
-------------- -------------
Proved reserves as of December 31, 2000..................................... 33,625 398,524
Revisions of previous estimates......................................... (1,703) (2,876)
Extensions, discoveries and other additions............................. 2,727 52,742
Purchase of producing properties........................................ 24,765 59,849
Production (1).......................................................... (4,023) (65,570)
-------------- -------------
Proved reserves as of December 31, 2001..................................... 55,391 442,669
============== =============
Proved developed reserves:

as of December 31, 1999................................................. 25,194 309,696
============== =============
as of December 31, 2000................................................. 25,374 307,320
============== =============
as of December 31, 2001................................................. 43,094 351,269
============== =============

(1) Excludes gas production volumes related to the volumetric production payment. See "Note 6 - Production Payments."

The following tables 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. You should not assume that the future net cash flows or the
discounted future net cash flows, referred to in the table below, represent the
fair value of our estimated oil and gas reserves. As required by the SEC, we
determine estimated future net cash flows using period-end market prices for oil
and gas without considering hedge contracts in place at the end of the period.
The average 2001 year-end product prices for all of our properties were $18.64
per barrel of oil and $2.79 per Mcf of gas. Future production and development
costs are based on current costs with no escalations. Estimated future cash
flows net of future income taxes have been discounted to their present values
based on a 10% annual discount rate.

NOTE 13-- OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)

STANDARDIZED MEASURE
YEAR ENDED DECEMBER 31,
----------------------------------------------------------
2001 2000 1999
---------------- ---------------- ---------------

Future cash flows.............................................. $2,274,665 $4,902,297 $1,806,565

Future production and development costs........................ (767,442) (701,533) (613,129)

Future income taxes............................................ (212,883) (1,392,078) (215,879)
---------------- ---------------- ---------------
Future net cash flows.......................................... 1,294,340 2,808,686 977,557

10% annual discount............................................ (385,764) (825,937) (286,076)
---------------- ---------------- ---------------
Standardized measure of discounted future net cash flows....... $908,576 $1,982,749 $691,481
================ ================ ===============

CHANGES IN STANDARDIZED MEASURE
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------
2001 2000 1999
---------------- ---------------- ---------------

Standardized measure at beginning of year...................... $1,982,749 $691,481 $418,403
Sales and transfers of oil and gas produced, net of
production costs........................................... (333,200) (368,243) (178,007)
Changes in price, net of future production costs............... (2,097,695) 1,784,727 326,300
Extensions and discoveries, net of future production
and development costs...................................... 134,876 656,944 138,945
Changes in estimated future development costs, net of
development costs incurred during the period............... 61,994 30,608 13,348
Revisions of quantity estimates................................ (19,982) (162,462) 28,735
Accretion of discount.......................................... 294,179 83,064 45,059
Net change in income taxes..................................... 828,820 (819,893) (108,160)
Purchases of reserves in-place................................. 314,394 48,752 60,065
Changes in production rates due to timing and other............ (257,559) 37,771 (53,207)
---------------- ---------------- ---------------
Standardized measure at end of year............................ $908,576 $1,982,749 $691,481
================ ================ ===============

NOTE 14 -- SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:

BASIC DILUTED
NET EARNINGS (LOSS) EARNINGS (LOSS)
REVENUES EXPENSES INCOME (LOSS) PER SHARE PER SHARE
------------- ------------- -------------- --------------- -----------------

2001
First Quarter........... $144,001 $104,742 $39,259 $1.51 $1.49
Second Quarter.......... 106,729 77,661 29,068 1.11 1.10
Third Quarter........... 83,082 228,150 (145,068) (5.54) (5.54)
Fourth Quarter.......... 64,684 59,318 5,366 0.20 0.20
------------- ------------- ---------------
$398,496 $469,871 ($71,375) (2.73) (2.73)
============= ============= ===============

2000
First Quarter........... $70,869 $53,097 $17,772 $0.69 $0.68
Second Quarter.......... 84,302 59,007 25,295 0.98 0.96
Third Quarter........... 109,547 72,165 37,382 1.45 1.42
Fourth Quarter.......... 121,448 75,440 46,008 1.78 1.74
------------- ------------- ---------------
$386,166 $259,709 $126,457 4.90 4.80
============= ============= ===============

G-2
GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.

Bbtu. One billion Btus.

Bcf. One billion cubic feet of gas.

Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.

Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5
degrees Fahrenheit.

EBITDA. Represents net income attributable to common stock plus interest,
income taxes, depreciation, depletion and amortization and non-cash ceiling test
write-downs of oil and gas properties.

Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.

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

Farmin or farmout. An agreement under which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof 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 "farmin" while the interest
transferred by the assignor is a "farmout."

Finding costs. Costs associated with acquiring and developing proved oil
and gas reserves which are capitalized pursuant to generally accepted accounting
principles, excluding any capitalized general and administrative expenses.

Gross acreage or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.

LIBOR. Represents the London Inter-Bank Overnight Rate of interest.

MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.

MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.

Mcf. One thousand cubic feet of gas.

Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.

Mcf/d. One thousand cubic feet of gas per day.

MMBbls. One million barrels of crude oil or other liquid hydrocarbons.

MMBtu. One million Btus.

MMcf. One million cubic feet of gas.

MMcfe. One million cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.

MMcf/d. One million cubic feet of gas per day.

Make-Whole Amount. The greater of 104.125% of the principal amount of the 8
1/4% Notes and the sum of the present values of the remaining scheduled payments
of principal and interest discounted to the date of redemption on a semiannual
basis at the applicable treasury rate plus 50 basis points.

Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.

Pooling of Interests. An accounting method for business combinations in
which the financial statements and results of operations are prepared as if the
companies had been combined at the beginning of the earliest period shown. In
addition, the assets and liabilities of the combining companies are carried
forward to the combined entity at book value.

Present value. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date of the report
or estimate, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax expense
or to depreciation, depletion and amortization, discounted using an annual
discount rate of 10%.

Production payment. An obligation of the purchaser of a property to pay a
specified portion of future gross revenues, less related production taxes and
transportation costs, to the seller of the property.

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 exceeds production expenses and taxes.

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 which 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. Reserves that are expected to be recovered
from new wells on developed acreage where the subject reserves cannot be
recovered without drilling additional wells.

Royalty interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of production costs.

Tcf. One trillion cubic feet of gas.

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 oil and gas regardless of whether such acreage contains proved reserves.

Volumetric production payment. An obligation of the purchaser of a property
to deliver a specific volume of production, free and clear of all costs, to the
seller of the property.

Working interest. An operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to receive a
share of production.

EXHIBIT INDEX

Exhibit
Number Description

3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the
Registrant's Registration Statement on Form S-1 (Registration
No. 33-62362)).

3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on Form
S-1 (Registration No. 33-62362)).

3.3 -- Certificate of Amendment of the Certificate of Incorporation
of Stone Energy Corporation, dated February 1, 2001 (incorporated
by reference to Exhibit 4.1 to the Registrant's Form 8-K, dated
February 7, 2001).

+10.3 -- Conveyances of Net Profits Interests in certain properties
to D. Peter Canty and James H. Prince (incorporated by
reference to Exhibit 10.9 to the Registrant's Registration
Statement on Form S-1 (Registration No. 33-62362)).

+10.4 -- Deferred Compensation and Disability Agreement between TSPC
and E. J. Louviere dated July 16, 1981 (incorporated by
reference to Exhibit 10.10 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1995 (File
No. 001-12074)).

+10.5 -- Stone Energy Corporation 2000 Amended and Restated Stock Option
Plan (incorporated by reference to Appendix A to the
Registrant's Definitive Proxy Statement on Schedule 14A for
Stone's 2000 Annual Meeting of Stockholders (File No.
001-12074)).

10.8 -- Fourth Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and Bank
of America, N.A., as administrative agent, dated as of December
20, 2001. (incorporated by reference to Exhibit 10.3 to the
Registrant's Registration Statement on Form S-4
(Registration No. 333-81380)).

+10.9 -- Stone Energy Corporation 2001 Amended and Restated Stock Option
Plan (incorporated by reference to Exhibit 4.1 to the
Registrant's Registration Statement on Form S-8 (Registration No.
333-64448)).

*21.1 -- Subsidiaries of the Registrant.

*23.1 -- Consent of Arthur Andersen LLP.

*23.2 -- Consent of Atwater Consultants, Ltd.

*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.

*23.4 -- Consent of Ryder Scott Company.
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.