STONE ENERGY CORP, 10-K405, 1997-03-28

STONE ENERGY CORP
10-K405, 1997-03-28
CRUDE PETROLEUM & NATURAL GAS

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

FORM 10-K

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

For the fiscal year ended December 31, 1996

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 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: (318) 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. [ X ]

The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $278,359,000 as of March 14, 1997 (based on
the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).

As of March 14, 1997, the registrant had outstanding 15,015,408 shares
of Common Stock, par value $.01 per share.

Document incorporated by reference: Proxy Statement of Stone Energy
Corporation relating to the Annual Meeting of Stockholders to be held on May 15,
1997, which is incorporated into Part III of this Form 10-K.

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<PAGE> 2

TABLE OF CONTENTS

Page No.
--------
PART I

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

Item 2. Properties.................................................... 7

Item 3. Legal Proceedings............................................. 9

Item 4. Submission of Matters to a Vote of Security Holders........... 10

Item 4A. Executive Officers of the Registrant.......................... 10

PART II

Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters........................................... 12

Item 6. Selected Financial and Operating Data......................... 13

Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................. 14

Item 8. Financial Statements and Supplementary Data................... 20

Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................... 20

PART III

Item 10. Directors and Executive Officers of the Registrant............ 20

Item 11. Executive Compensation........................................ 20

Item 12. Security Ownership of Certain Beneficial Owners and Management 20

Item 13. Certain Relationships and Related Transactions................ 20

PART IV

Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................. 21

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

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

<PAGE> 3

PART I

ITEM 1. BUSINESS

OVERVIEW

Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploitation and operation of oil and gas properties onshore
and offshore in the Gulf Coast Basin. The Company and its predecessors have
conducted exploration, development and production operations in the Gulf Coast
Basin since 1973, which gives the Company extensive geophysical, technical and
operational expertise in this area. As of December 31, 1996, the Company had
estimated proved reserves of approximately 144.3 Bcf of natural gas and 12.8
MMBbls of oil, or an aggregate of approximately 36.8 MMBOE, with a present value
of estimated pre-tax future net cash flows of $448.9 million (based upon prices
in December 1996).

The Company's business strategy, adopted in 1990, is to increase production,
cash flow and reserves through the acquisition and development of mature
properties located in the Gulf Coast Basin. These properties have
characteristics that include an established production history, proved
undeveloped reserves and multiple prospective reservoirs that provide
significant development opportunities, an attractive price due to low current
production levels and the ability to control operations. Prior to acquiring a
property, the Company performs a thorough geological, geophysical and
engineering analysis of the property to formulate a comprehensive development
plan. Development activities seek to increase cash flow from existing proved
reserves and to establish additional proved reserves. These activities typically
involve the drilling of new wells, workovers and recompletions of existing
wells, and the application of other techniques designed to increase production.

Since 1993, the Company has increased the number of properties in which it
has an interest from five to 14, and serves as operator of 13 of these
properties. In addition, the Company has substantially expanded its technical
database, including 3-D seismic data relating to its properties and potential
acquisitions. As a result, the Company has been able to significantly increase
its development activities. For the year ending December 31, 1997, the Company
has budgeted capital expenditures for development operations of $104 million,
which includes plans to drill 23 new wells, conduct 26 workovers/recompletions
on existing wells and, depending upon the success of specific development
activities, install three new offshore production platforms. The Company's
capital expenditures for 1996 totalled $79.4 million, of which $22.0 million was
for the acquisition of interests in producing properties.

The Company completed its initial public offering of common stock in July
1993 (the "Initial Public Offering"), and its shares are listed on the New York
Stock Exchange. A secondary offering of common stock was completed in November
1996, and the Company had a total of 15,015,408 shares outstanding at March 31,
1997. Stone Energy is headquartered in Lafayette, Louisiana, with additional
offices in New Orleans and Houston.

As used herein, the "Company" or "Stone Energy" refers to Stone Energy
Corporation and its consolidated subsidiaries, unless the context requires
otherwise. 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.

OIL AND GAS MARKETING

All of the Company's natural gas is sold at current market prices. The
Company's oil and natural gas condensate production is sold at current market
prices, either under short-term contracts providing for variable or market
sensitive prices or under various long-term contracts that dedicate the oil and
natural gas condensate from a property or well to a single purchaser for an
extended period of time, but which still involve variable, market sensitive
pricing. From time to time, the Company may enter into transactions hedging the
price of oil, natural gas and natural gas condensate. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."

<PAGE> 4

COMPETITION AND MARKETS

Competition in the Gulf Coast Basin is intense, particularly with respect to
the acquisition of producing properties and proved undeveloped acreage. The
Company competes with the major oil 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 the Company's
competitors have financial resources and exploration and development budgets
that are substantially greater than those of the Company, which may adversely
affect the Company's ability to compete, particularly in regions outside of the
Gulf Coast Basin.

The availability of a ready market for and the price of any hydrocarbons
produced will depend on many factors beyond the control of the Company,
including the extent 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 and 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 area, 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 the Company conducts
activities, there are statutory provisions regulating the production of oil and
natural gas under which administrative agencies may promulgate rules in
connection with the operation and production of both oil and gas wells,
determine the reasonable market demand for oil and gas, and establish allowable
rates of production. Such regulatory orders may restrict the rate at which the
Company's wells produce oil or gas below the rate at which such wells would be
produced in the absence of such regulatory orders, with the result that the
amount or timing of the Company's revenues could be adversely affected.

FEDERAL LEASES. The Company has oil and gas leases in the Gulf of Mexico,
which were granted by the federal government and are administered by the United
States Department of the Interior Minerals Management Service (the "MMS"). For
offshore operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
the Army Corps of Engineers and the United States Environmental Protection
Agency (the "EPA")), lessees must obtain a permit from the MMS prior to the
commencement of drilling. The MMS has promulgated regulations requiring offshore
production facilities located on the Outer Continental Shelf ("OCS") to meet
stringent engineering and construction specifications. The MMS proposed
additional safety-related regulations concerning the design and operating
procedures for OCS production platforms and pipelines. These proposed
regulations were withdrawn pending further discussions among interested federal
agencies. The MMS also has regulations restricting the flaring or venting of
natural gas, and recently amended such regulations to prohibit the flaring of
liquid hydrocarbons and oil without prior authorization. Similarly, the MMS has
promulgated other regulations governing the plugging and abandoning of wells
located offshore and the removal of all production facilities. With respect to
any Company 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 such
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 such obligations will be met. The cost of such bonds or other
surety can be substantial and there is no assurance that bonds or other surety
can be obtained in all cases.

<PAGE> 5

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, the Company has been granted exempt status by the MMS,
which exempts the Company from the supplemental bonding requirements. Under
certain circumstances, the MMS may require any Company operations on federal
leases to be suspended or terminated. Any such suspension or termination could
materially and adversely affect the Company's financial condition and
operations.

The MMS has issued a notice of proposed rulemaking in which it proposes to
amend its regulations governing the calculation of royalties and the valuation
of natural gas produced from federal leases. The principle feature in the
amendments, as proposed, would establish an alternative market-index based
method to calculate royalties on certain natural gas production sold to
affiliates or pursuant to non-arm's-length sales contracts. The MMS has proposed
this rulemaking to facilitate royalty valuation in light of changes in the gas
marketing environment. In addition, the MMS has recently issued a notice of
proposed rulemaking in which it proposes to amend it regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. This proposed rule would modify the valuation procedures for both
arm's-length and non-arm's-length crude oil transactions to decrease reliance on
crude oil posted prices and assign a value to crude oil that better reflects
market value, establish a new MMS form for collecting value differential data
and amend the valuation procedure for the sale of federal royalty oil. The
Company cannot predict what action the MMS will take on these matters, nor can
it predict at this stage of the rulemaking proceeding how the Company might be
affected by amendments to the regulations.

OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids by the Company are not currently regulated and are made at
negotiated prices. Effective as of January 1, 1995, the Federal Energy
Regulatory Commission (the "FERC") implemented regulations establishing an
indexing system for transportation rates for oil that could increase the cost of
transporting oil to the purchaser. The Company is not able to predict what
effect, if any, this order will have on it, but it may tend to increase
transportation costs or reduce wellhead prices for crude oil.

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 the 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 April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, and
636-C (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 gas suppliers. Although Order
No. 636 does not directly regulate the Company's activities, the FERC has stated
that it intends for Order No. 636 to foster increased competition within all
phases of the natural gas industry. It is unclear what impact, if any, increased
competition within the natural gas industry under Order No. 636 will have on the
Company's activities. Although, Order No. 636, assuming it is upheld in its
entirety, could provide the Company with additional market access and more
fairly applied transportation service rates, Order No. 636, could also subject
the Company to more restrictive pipeline imbalance tolerances and greater
penalties for violation of those tolerances. The FERC has issued final orders in
all Order No. 636 pipeline restructuring proceedings. The United States Court of
Appeals for the District of Columbia Circuit ("D.C. Circuit") has generally
affirmed Order No. 636 and remanded certain issues for further explanation or
clarification. The issues remanded for further action do not appear to
materially affect the Company. A number of parties have appealed the D.C.
Circuit's ruling to the United State Supreme Court and proceedings on the
remanded issues are currently ongoing before the FERC following its issuance of
Order No. 636-C in February 1997. Numerous petitions for review of the
individual pipeline restructuring orders are currently pending in that court.
Although it is difficult to predict when all appeals of pipeline restructuring
orders will be completed or their impact on the Company, the Company does not
believe that it will be affected by the restructuring rule and orders any
differently than other natural gas producers and marketers with which it
competes.

<PAGE> 6

The FERC has announced several important transportation-related policy
statements and proposed rule changes, including the appropriate manner in which
interstate pipelines release capacity under Order No. 636 and, more recently,
the price that shippers can charge for their released capacity. In addition, in
1995, the FERC issued a policy statement on how interstate natural gas pipelines
can recover the costs of new pipeline facilities. In January 1996, the FERC
issued a policy statement and a request for comments concerning alternatives to
its traditional cost-of-service ratemaking methodology. A number of pipelines
have obtained FERC authorization to charge negotiated rates as one such
alternative. While any additional FERC action on these matters would affect the
Company only indirectly, any new rules and policy statements may have the effect
of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.

The OCSLA requires that all pipelines operating on or across the OCS provide
open-access, non-discriminatory service. Although the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the
OCSLA, on gatherers and other non-jurisdictional entities, the FERC has retained
the authority to exercise jurisdiction over those entities if necessary to
permit non-discriminatory access to service on the OCS.

Commencing in May 1994, the FERC issued a series of orders in individual
cases that delineate its new gathering policy. Among other matters, the FERC
slightly narrowed its statutory tests for establishing gathering status and
reaffirmed that, except in situations in which the gatherer acts in concert with
an interstate pipeline affiliate to frustrate the FERC's transportation
policies, it does not generally have jurisdiction over natural gas gathering
facilities and services, and that such facilities and services located in state
jurisdictions are properly regulated by state authorities. This FERC action may
further encourage regulatory scrutiny of natural gas gathering by state
agencies. In addition, the FERC has approved several transfers by interstate
pipelines of gathering facilities to unregulated independent or affiliated
gathering companies, subject to the transferee providing service for two years
from the date of transfer to the pipeline's existing customers pursuant to a
default contract or pursuant to mutually agreeable terms. In August 1996, the
D.C. Circuit largely upheld the FERC's new gathering policy, but remanded the
FERC's default contract condition. The Company does not believe that it will be
affected by the FERC's new gathering policy any differently than other
producers, gatherers and marketers with which it competes.

The new gathering policy thus far announced by the FERC in these orders
does not address its jurisdiction over pipelines operating on or across the OCS
pursuant to the OCSLA. If the FERC were to apply Order No. 509 to gatherers in
the OCS, eliminate the exemption of gathering lines, and redefine its
jurisdiction over gathering lines, then these acts could result in a reduction
in available pipeline space for existing shippers in the Gulf of Mexico, such as
the Company.

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

ENVIRONMENTAL REGULATIONS. The Company's 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 the Company's operations. 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 the operating costs of the Company, as well as the oil and
gas industry in general. Initiatives to further regulate the disposal of oil and
gas wastes are also pending in certain states, and these various initiatives
could have a similar impact on the Company. Management believes that the Company
is in substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements will not
have a material adverse impact on the Company.

<PAGE> 7

The Oil Pollution Act ("OPA") and regulations thereunder impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. A
"responsible party" includes the owner or operator of a facility or vessel, or
the lessee or permittee of the area in which an offshore facility is located.
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 $75,000,000
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. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties for offshore facilities to provide
financial assurance in the amount of $35 million to cover potential OPA
liabilities. This amount can be increased up to $150 million if a formal risk
assessment indicates that an amount higher than $35 million should be required.
The Company does not anticipate that it will experience any difficulty in
satisfying the MMS's requirements for demonstrating financial responsibility
under OPA.

In 1996, the American Institute of Certified Public Accountants issued its
Statement of Position 96-1 ("SOP 96-1"), which provides guidance on accounting
for environmental remediation liabilities. SOP 96-1 interprets existing
Financial Accounting Standards Board standards applicable to public companies.
The Company intends to apply SOP 96-1 starting in 1997. The Company believes
adoption of SOP 96-1 will not have a material adverse impact on its results of
operations or financial position.

The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain 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 disposed or
arranged for the 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 EPA has indicated that the Company may be potentially responsible for
costs and liabilities associated with alleged releases of hazardous substances
at two sites. See "Item 3. Legal Proceedings-Environmental."

The Federal Water Pollution Control Act ("FWPCA") imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes 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 prohibit the discharge of produced water and
sand, drilling fluids, drill cuttings and certain other substances related to
the oil and gas industry to coastal waters. Although the costs to comply with
recently-enacted zero discharge mandates under federal or state law may be
significant, the entire industry is expected to experience similar costs and the
Company believes that these costs will not have a material adverse impact on the
Company's results of operations or financial position. In 1992 the EPA 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.

<PAGE> 8

OPERATIONAL RISKS AND INSURANCE

The Company's operations are subject to the usual hazards incident to the
drilling of oil and gas wells, such as cratering, explosions, uncontrollable
flows of oil, gas or well fluids, fires, pollution and other environmental
risks. The Company's activities are also subject to perils peculiar to marine
operations, such as capsizing, collision, and damage or loss from severe
weather. These hazards can cause personal injury and loss of life, severe damage
to and destruction of property and equipment, pollution or environmental damage
and suspension of operations.

The Company maintains insurance of various types to cover its operations,
including maritime employer's liability and comprehensive general liability.
Amounts in excess of base coverages are provided by primary and excess umbrella
liability policies with ultimate limits of $50 million. In addition, the Company
maintains up to $50 million in operator's extra expense coverage, 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.

The occurrence of a significant event not fully insured or indemnified
against could materially and adversely affect the Company's financial condition
and operations. Moreover, no assurance can be given that the Company will be
able to maintain adequate insurance in the future at rates it considers
reasonable.

EMPLOYEES

At March 14, 1997, the Company had 72 full time employees. The Company
believes that its relationships with its employees are satisfactory. None of the
Company's employees are covered by a collective bargaining agreement. From time
to time the Company utilizes the services of independent contractors to perform
various field and other services.

<PAGE> 9

ITEM 2. PROPERTIES

The Company has grown principally through the acquisition and subsequent
development and exploitation of properties purchased from major oil companies.
The Company's proved oil and gas reserves at December 31, 1996 were attributable
to 14 properties, seven of which are in the Gulf of Mexico offshore Louisiana,
and seven of which are onshore Louisiana. The Company currently manages eight
partnerships formed prior to its Initial Public Offering, and less than 5% of
the Company's assets are owned through these entities.

OIL AND GAS RESERVES

The following table sets forth estimated net proved oil and gas reserves of
the Company and the present value of estimated future pre-tax net cash flows
related to such reserves as of December 31, 1996. All information in this Form
10-K relating to estimated oil and gas reserves and the estimated future net
cash flows attributable thereto is based upon the reserve reports (the "Reserve
Reports") prepared by Atwater Consultants, Ltd. and Cawley, Gillespie &
Associates, Inc., both independent petroleum engineers, as of December 31, 1996.
Using the information contained in the Reserve Reports, the average product
prices for all of the Company's properties were $25.97 per Bbl of oil and $3.94
per Mcf of gas. All product pricing and cost estimates used in the Reserve
Reports are in accordance with the rules and regulations of the Securities and
Exchange Commission, 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%.

<TABLE>
<CAPTION>
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
--------------- ---------------- ---------------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Oil (MBbls).......................................... 9,260 3,512 12,772
Gas (MMcf)........................................... 109,628 34,688 144,316
Total oil and gas (MBOE)............................. 27,531 9,294 36,825
Estimated future net revenues before
income taxes..................................... $534,540 $177,839 $712,379
Present value of estimated future
pre-tax net cash flows........................... $341,476 $107,419 $448,895
</TABLE>

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 represent only 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 such estimates depends on the accuracy of the assumptions upon
which they are based. For example, the market prices for oil and natural gas on
the date of this Form 10-K were significantly lower than the prices used for
purposes of such estimates.

As an operator of domestic oil and gas properties, the Company has 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 on the total
reserves attributable to wells which are operated by it, without regard to
ownership (i.e., reserves are reported on a gross operated basis, rather than on
a net interest basis).

<PAGE> 10

ACQUISITION, PRODUCTION AND DRILLING ACTIVITY

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

YEAR ENDED DECEMBER 31,
-----------------------
1996 1995 1994
----------- ---------- -----------
(In thousands)
<S> <C> <C> <C>
Acquisition costs................................. $26,650 $ 8,074 $11,465
Development costs................................. 24,090 27,383 22,241
Exploratory costs................................. 26,339 8,261 4,719
----------- ---------- -----------
Subtotal........................................ 77,079 43,718 38,425
Capitalized general and administrative costs and
interest, net of fees and reimbursements........ 2,325 1,790 2,749
----------- ---------- ----------
Total costs incurred.............................. $79,404 $45,508 $41,174
=========== ========== ===========
</TABLE>

PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain
statistics for the Company regarding the number of productive wells and
developed and undeveloped acreage as of December 31, 1996.

GROSS NET
------------- --------------
Productive Wells:
Oil(1)................................. 52.00 35.07
Gas(2)................................. 30.00 20.65
------------- --------------
Total.............................. 82.00 55.72
============= ==============
Developed Acres:
Onshore Louisiana...................... 2,806.60 1,903.49
Offshore Louisiana..................... 7,200.00 4,065.01
------------- --------------
Total.............................. 10,006.60 5,968.50
============= ==============
Undeveloped Acres(3):
Onshore Louisiana...................... 17,606.67 15,320.83
Offshore Louisiana..................... 27,338.88 17,914.04
------------- --------------
Total.............................. 44,945.55 33,234.87
============= ==============
- -----------------
(1) Four gross wells each have dual completions.
(2) Nine gross wells each have dual completions.
(3) Leases covering approximately 0.99% of the Company's undeveloped acreage
will expire in 1997, 1.93% in 1998, 0.37% in 1999, 7.85% in 2000 and
5.55% in 2001. Leases covering the remainder of the Company's
undeveloped gross acreage (83.31%) are held by production.

<PAGE> 11

DRILLING ACTIVITY. The following table sets forth the Company's drilling
activity for the periods indicated.

GROSS NET
--------- --------
Wells drilled during the years ended December 31:

1996:
Exploratory.............................. 4.00 3.73
Development.............................. 5.00 4.50

1995:
Exploratory.............................. 3.00 2.94
Development.............................. 6.00 4.40

1994:
Exploratory.............................. 2.00 1.75
Development.............................. 12.00 7.64

All wells drilled were productive except for three gross exploratory wells (2.75
net) and one gross development well (0.76 net) which were drilled in 1996, two
gross exploratory wells (1.94 net) and one gross development well (0.38 net)
which were drilled in 1995 and three gross development wells (2.34 net) which
were drilled in 1994.

TITLE TO PROPERTIES

The Company has obtained title opinions on substantially all of its
producing properties and believes it has satisfactory title to such properties
in accordance with standards generally accepted in the oil and gas industry. The
Company's properties are subject to customary royalty interests, liens for
current taxes and other burdens which the Company believes do not materially
interfere with the use of or affect the value of such properties. The title
investigation performed by the Company prior to acquiring undeveloped properties
is thorough but less vigorous than that conducted prior to drilling, consistent
with standard practice in the oil and gas industry. Prior to the commencement of
drilling operations, a thorough title examination is conducted and curative work
is performed with respect to significant defects before proceeding with
operations. A thorough title examination has been performed with respect to
substantially all producing properties owned by the Company.

ITEM 3. LEGAL PROCEEDINGS

ENVIRONMENTAL

In August 1989, the Company was advised by the EPA that it believed the
Company to be a potentially responsible party (a "PRP") for the cleanup of an
oil field waste disposal facility located near Abbeville, Louisiana, which was
included on CERCLA's National Priority List (the "Superfund List") by the EPA in
March 1989. In addition to the Company, approximately 370 other companies have
been named as being potentially responsible for the cleanup of the site. While
the Company's records do not indicate that any drilling wastes generated by the
Company were disposed of at this site, it is possible that one or more waste
haulers contracted by the Company may have disposed of wastes at this site.
Given the extremely large number of PRPs at this site, management does not
believe that any liability for this site would materially adversely affect the
financial condition of the Company.

In August 1989, the Company was advised by the EPA that it believed the
Company to be a PRP for the cleanup of an oil field waste disposal facility
located adjacent to the site described above. This site is presently owned by a
subsidiary of Dow Chemical Corporation that performed remediation activities at
this site in 1987 before it was placed on the Superfund List by the EPA in
October 1989. The Company entered into a settlement agreement with Dow

<PAGE> 12

Chemical Corporation on September 16, 1996, releasing the Company from any
anticipated claims at this site. The Company paid Dow $50,000 in connection with
such settlement.

OTHER PROCEEDINGS

In December 1995, Goodrich Leasehold L.L.C. and Goodrich Drillers L.L.C.
filed a civil action (No. 95-61313) in the 333rd Judicial District Court, Harris
County, Texas, against the Company in an attempt to set aside a farmout
agreement affecting portions of the West Flank of the Weeks Island Field in
Iberia Parish, Louisiana. Management believes that this claim is without merit
and intends to vigorously defend this action.

The Company is also named as a defendant in certain lawsuits and is a party
to certain regulatory proceedings arising in the ordinary course of business.
Management does not expect these matters, individually or in the aggregate, to
have a material adverse effect on the financial condition of the Company.

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

None.

ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth information regarding the names and ages of
(as of March 14, 1997) and positions held by each of the Company's executive
officers. The Company's executive officers serve at the discretion of the Board
of Directors.

NAME AGE POSITION
---- --- --------
<S> <C> <C>
James H. Stone.................................. 71 Chairman of the Board and Chief Executive
Officer
Joe R. Klutts................................... 62 Vice Chairman of the Board
D. Peter Canty.................................. 50 President, Chief Operating Officer and
Director
Michael L. Finch................................ 41 Executive Vice President, Chief Financial
Officer and Director
Phillip T. Lalande.............................. 47 Vice President - Engineering
James H. Prince................................. 54 Vice President, Chief Accounting Officer and
Controller
Andrew L. Gates, III............................ 49 Vice President - Legal, Secretary and General
Counsel
E. J. Louviere.................................. 48 Vice President - Land
Craig L. Glassinger............................. 49 Vice President - Acquisitions
</TABLE>

The following biographies describe the business experience of the executive
officers of the Company for at least the past five years. The Company was formed
in March 1993 to become a holding company for The Stone Petroleum Corporation
("TSPC") and its subsidiaries.

James H. Stone has served as Chairman of the Board and Chief Executive
Officer of the Company since March 1993, and as Chairman of the Board of TSPC
since 1981 and served as President of TSPC from September 1992 to July 1993. Mr.
Stone is currently a director of Hibernia Corporation and Newpark Resources,
Inc., and is a member of the Advisory Committee of the St. Louis Rams Football
Company.

Joe R. Klutts has served as Vice Chairman of the Board since March 1994 and
as a Director since March 1993. He has also served as a Director of TSPC since
1981. He served as President of the Company from March 1993 to February

<PAGE> 13

1994, and as Executive Vice President - Exploration and President of TSPC from
1981 to 1993 and from July 1993 to May 1994, respectively.

D. Peter Canty served as an Executive Vice President of the Company from
March 1993 to March 1994, when he was named President of the Company. He has
also served as Chief Operating Officer and as a Director of the Company since
March 1993. Mr. Canty was a Vice President and the Chief Geologist of TSPC from
1987 to May 1994, when he was named President of TSPC.

Michael L. Finch has served as Executive Vice President, Chief Financial
Officer and Director since March 1993. From 1988 through July 1993, he was a
partner in the firm of Finch & Pierret, CPAs, which performed a substantial
amount of financial reporting, tax compliance and financial advisory services
for TSPC and its affiliates.

Phillip T. Lalande has served as Vice President - Engineering of the Company
since March 1995. He served as the Company's Operations Manager from July 1993
to March 1995, and as a consulting engineer to TSPC from 1988 to July 1993.

James H. Prince has served as Vice President, Chief Accounting Officer and
Controller of the Company since March 1993 and as Vice President and Controller
of TSPC since 1981, as Treasurer since 1989, as Secretary from 1989 to 1991 and
as Assistant Secretary since 1992.

Andrew L. Gates, III has served as Vice President - Legal, Secretary and
General Counsel of the Company since August 1995. Prior to joining Stone Energy
in 1995, he was a partner in the law firm of Ottinger, Gates, Hebert & Sikes
from 1987 to August 1995.

E. J. Louviere has served as Vice President - Land since June 1995. He
served as the Land Manager of TSPC and the Company from July 1981 to June 1995.

Craig L. Glassinger has served as Vice President - Acquisitions of the
Company since December 1995. He served TSPC and Stone Energy from October 1992
to December 1995 as Acquisitions Manager. Prior to joining TSPC, he was a
division geologist for Forest Oil Corporation for approximately ten years.

<PAGE> 14

PART II

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

Since July 9, 1993, the 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 sales prices per share for the Common Stock.

HIGH LOW
------------- -------------
1995
First Quarter................... 19 14
Second Quarter.................. 15 5/8 11 5/8
Third Quarter................... 13 5/8 11
Fourth Quarter.................. 15 3/4 11 1/4
1996
First Quarter................... 17 1/4 13 1/4
Second Quarter.................. 20 1/8 15 5/8
Third Quarter................... 23 1/2 17 3/4
Fourth Quarter.................. 30 18 1/8

1997
First Quarter (through March 14, 1997).29 3/4 21 1/4

On March 14, 1997, the last reported sales price on the New York Stock
Exchange Composite Tape was $25 1/8 per share. As of that date there were
approximately 153 holders of record of the Common Stock.

The Company has not in the past, and does not intend to pay cash dividends
on its Common Stock in the foreseeable future. The Company currently intends to
retain earnings, if any, for the future operation and development of its
business. The Company has entered into a credit facility that contains
provisions that may have the effect of limiting or prohibiting the payment of
dividends. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations."

<PAGE> 15

ITEM 6. SELECTED FINANCIAL AND OPERATING DATA

SELECTED HISTORICAL FINANCIAL INFORMATION
(In thousands, except per share amounts)

The following table sets forth a summary of selected historical financial
information for the five years ended December 31, 1996 for the Company. This
information is derived from the consolidated financial statements of the Company
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,
-----------------------------------------------------
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Operating revenue:
Oil production revenue................................... $27,788 $24,775 $18,482 $17,752 $14,557
Gas production revenue................................... 28,051 13,918 12,697 10,718 5,778
Other revenue............................................ 2,126 1,858 1,708 1,252 616
------- ------- ------- ------- --------
Total revenue.......................................... 57,965 40,551 32,887 29,722 20,951
------ ------ ------ ------ ------
Expenses:
Normal lease operating expenses.......................... 8,625 6,294 5,312 4,326 4,164
Major maintenance expenses............................... 427 446 1,834 822 148
Production taxes......................................... 3,399 3,057 2,303 2,000 1,557
Depreciation, depletion and amortization................. 19,564 15,719 11,569 8,028 5,019
Interest expense......................................... 3,574 2,191 982 1,499 1,743
Other expense ........................................... - - - 245 365
General and administrative costs......................... 3,509 3,298 3,099 2,248 1,818
Incentive compensation plan.............................. 928 85 1,358 - -
Exchange offer expenses.................................. - - - 780 -
------- ------ ------ ------ ------
Total expenses......................................... 40,026 31,090 26,457 19,948 14,814
------- ------ ------ ------ ------
Net income before income taxes and cumulative
effect of change in accounting principle................. 17,939 9,461 6,430 9,774 6,137
------- ------- ------ ------- -------
Provision for income taxes:
Current.................................................. 208 131 - - -
Deferred................................................. 6,698 3,514 2,410 943 -
-------- ------ ------ -------- ---------
Total income taxes..................................... 6,906 3,645 2,410 943 -
-------- ------ ------ -------- ---------
Net income before cumulative effect of change in
accounting principle..................................... 11,033 5,816 4,020 8,831 6,137
Cumulative effect of change in accounting principle (2).... - - - - 1,377
--------------------------------------------- -------
Net income................................................. $11,033 $5,816 $4,020 $8,831 $7,514
------- ====== ====== ====== ======

Earnings and dividends per common share:
Net income per share before accounting
principle change....................................... $0.89 $0.49 $0.34 $0.88 $0.71
Cumulative effect of accounting principle change......... - - - - 0.16
--------- --------- -------- -------- ------
Net income per common share.............................. $0.89 $0.49 $0.34 $0.88 $0.87
===== ===== ===== ===== =====
Net income per common share assuming full dilution....... $0.88 $0.49 $0.34 $0.88 $0.87
===== ===== ===== ===== =====
Cash dividends declared.................................. - - - - -

CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes).............. $37,295 $25,049 $17,911 $17,852 $11,156
Net cash provided by operating
activities............................................... 32,333 27,499 9,609 13,857 14,417

BALANCE SHEET DATA (AT END OF PERIOD):
Working capital (deficit).................................. $6,683 $5,379 $4,437 $18,421 $ (6,655)
Oil and gas properties, net................................ 171,396 111,248 81,291 60,097 49,722
Total assets (2)........................................... 209,406 139,460 109,956 98,770 65,117
Long-term debt, less current portion....................... 26,172 47,754 22,725 21,620 26,659
Stockholders' equity (1)(2)................................ 144,441 66,927 61,045 56,997 2,046
</TABLE>
- ----------------
(1) Mandatorily redeemable preferred stock outstanding at December 31, 1992 of
$15,203 is not included in stockholders' equity.
(2) Total assets and stockholders' equity at December 31, 1993 and 1992 have
been restated for an adjustment of the cumulative effect of the adoption in
1992 of SFAS No. 109.

<PAGE> 16

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

The following discussion is intended to assist in an understanding of the
Company's financial position and results of operations for each year of the
three-year period ended December 31, 1996. The Company's financial statements
and the notes thereto contain detailed information that should be referred to in
conjunction with the following discussion.
See "Item 8. Financial Statements and Supplementary Data."

FORMATION OF STONE ENERGY

The Company was formed in March 1993 to become a holding company for TSPC,
its subsidiaries and certain partnership interests, and approximately 8.1
million shares of Common Stock were issued to holders of interests in those
entities. In July 1993, the Company also sold approximately 3.7 million shares
of newly issued Common Stock in the Initial Public Offering. In November 1996,
the Company completed a secondary offering of an additional 3.2 million shares
of Common Stock.

OPERATING ENVIRONMENT

At present, the Company does not expect that changes in the rates of overall
economic growth or inflation will significantly impact product prices in the
short-term. While gas prices seem most dependent on weather in North America and
corresponding usage, oil prices are more subject to global economic forces and
supply. Because all of these factors are beyond the control of the Company, its
marketing efforts have been devoted to achieving the best price available in
each geographic location and a limited amount of fixed price sales and hedging
transactions to take advantage of short-term prices it believes to be
attractive.

Demand for drilling rigs and related products and services has increased
significantly during 1996, and the costs associated with these items are higher
than one year ago. The Company has experienced delays of one to two months in
obtaining drilling rigs and certain other services, and in some instances the
costs incurred are higher than originally budgeted. Despite these changes in the
market for drilling supplies and services, the Company does not expect these
current conditions to have a material impact on the timing or long-term
profitability of its planned activities.

The inventory of oil and gas properties offered for sale has declined over
the last several years. This reduced availability of properties, combined with
the emergence during the same period of a number of well-capitalized independent
oil and gas companies, has caused an increase in the prices paid for properties.

<PAGE> 17

RESULTS OF OPERATIONS

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

YEAR ENDED DECEMBER 31,
----------------------------------------------------
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
PRODUCTION:
Oil (MBbls)................................................... 1,356 1,400 1,113
Gas (MMcf).................................................... 11,331 8,399 6,629
Oil and gas (MBOE)............................................ 3,245 2,800 2,218
SALES DATA (IN THOUSANDS):
Total oil sales............................................... $27,788 $24,775 $18,482
Total gas sales............................................... 28,051 13,918 12,697
AVERAGE SALES PRICES:
Oil (per Bbl)................................................. $20.49 $17.70 $16.61
Gas (per Mcf)................................................. 2.48 1.66 1.92
Per BOE....................................................... 17.21 13.82 14.06
AVERAGE COSTS (PER BOE):
Normal operating costs........................................ $2.66 $2.25 $2.39
General and administrative.................................... 1.08 1.18 1.40
Depreciation, depletion and amortization...................... 5.93 5.57 5.15
RESERVES AT DECEMBER 31:
Oil (MBbls)................................................... 12,772 7,985 6,455
Gas (MMcf).................................................... 144,316 81,179 68,285
Oil and gas (MBOE)............................................ 36,825 21,515 17,836
Present value of estimated pre-tax future
net cash flows (in thousands)............................... $448,895 $179,725 $97,391
</TABLE>

1996 COMPARED TO 1995. Net income for the year ended December 31, 1996 was
$11.0 million, an increase of 90% from 1995 earnings of $5.8 million. Earnings
per share rose to $0.89 in 1996, as compared to $0.49 per share in 1995. Net
income for the three months ended December 31, 1996, was $2.9 million or $0.21
per share, an increase from the $1.8 million and $0.15 per share reported for
the fourth quarter of 1995.

For 1996, oil and gas revenues were $55.8 million as compared to $38.7
million in 1995, a 44% increase. Proceeds from sales of production in 1996 were
50% oil and 50% gas, as compared to 64% and 36%, respectively, for 1995.
Production volumes for 1996 were 1.4 MMBOE of oil and 11.3 Bcf of gas. Oil
production for 1996 was essentially the same as 1995, and gas deliveries
increased 35% from the 1995 amount of 8.4 Bcf of gas.

The increase in 1996's oil and gas revenues resulted from overall production
growth of 16% for the year and a 25% increase in the average price received per
BOE. The average gas price per Mcf increased 49% to $2.48 in 1996 from the 1995
amount of $1.66, and the average oil price per barrel climbed 16%, from $17.70
in 1995 to $20.49 in 1996. For the fourth quarter of 1996, oil and gas revenues
were 37% higher than for the comparable 1995 period due to overall increases,
stated in equivalent barrels, in production of 8% and prices of 27%.

Normal operating costs for 1996 increased in total to $8.6 million from $6.3
million in 1995 due to an increased number of properties and higher production
rates. The primary reason for the increase in such costs on a unit of production
basis ($2.66 per BOE in 1996 versus $2.25 per BOE in 1995) was certain
nonrecurring repairs and generally higher costs of services, although the 1996
unit amount is within the Company's budgeted range for these costs.

<PAGE> 18

Total depreciation, depletion and amortization ("DD&A") expense attributable
to oil and gas properties increased because of higher production rates and
investments in the properties. This non-cash expense increased to $19.3 million
or $5.93 per BOE in 1996 from $15.6 million or $5.57 per BOE in 1995.

During 1996, the Company borrowed funds pursuant to its bank credit facility
to finance a portion of its capital expenditures budget, and as a result
interest expense increased to $3.6 million in 1996 from $2.2 million in 1995.
General and administrative costs also increased in total to $3.5 million in 1996
from $3.3 million in 1995, but on a unit basis declined 9% to $1.08 per BOE in
1996 from $1.18 per BOE in 1995. Due to higher bonus awards during the year, the
expenses of the Company's incentive compensation program increased to $0.9
million in 1996 from $0.1 million in 1995.

Pre-tax income increased to $17.9 million in 1996 from $9.5 million in 1995,
and therefore the tax provision increased to $6.9 million in 1996 from $3.6
million in 1995. Except for an estimated minimum tax liability of $0.2 million,
the remainder of the tax provision is deferred and does not require current
funding.

The Company's reserves at December 31, 1996 were 36.8 MMBOE and represent
an increase of 71% from the comparable amount one year earlier of 21.5 MMBOE.
Oil reserves increased to 12.8 MMBbls at the end of 1996 from 8.0 MMBbls at the
beginning of the year, and gas reserves rose to 144.3 Bcf at December 31, 1996
from 81.2 Bcf at December 31, 1995.

1995 COMPARED TO 1994. Net income for the year ended December 31, 1995 was
$5.8 million or $0.49 per share, an increase of 45% from 1994 earnings of $4.0
million or $0.34 per share. Net cash flow from operations before working capital
changes for 1995 increased 40% to $25.0 million or $2.11 per share, from
comparable 1994 amounts of $17.9 million or $1.51 per share.

For 1995, oil and gas revenues were $38.7 million as compared to $31.2
million in 1994, a 24% increase. Proceeds from sales of production in 1995 were
64% oil and 36% gas, as compared to 59% and 41%, respectively, for 1994.
Production volumes for 1995 were 1.4 MMBbls of oil and 8.4 Bcf of gas. Oil
production was up 26% and gas deliveries increased 27% from the 1994 amounts of
1.1 MMBbls of oil and 6.6 Bcf of gas. The increase in 1995's revenues resulted
from overall production growth of 26% for the year, despite a 2% decline in the
average prices received per BOE. The average gas price per Mcf decreased by 14%
to $1.66 in 1995 from the 1994 amount of $1.92, but the average oil price per
Bbl climbed 7% from $16.61 in 1994 to $17.70 in 1995.

Normal operating costs for 1995 increased in total to $6.3 million from $5.3
million in 1994 due to an increased number of properties and higher production
rates. When stated on a unit basis, such costs were $2.25 per BOE in 1995 and
$2.39 per BOE in 1994, a 6% improvement. Major maintenance expenses, or workover
costs of producing zones, were $0.4 million in 1995 as compared to $1.8 million
in 1994.

DD&A expense attributable to oil and gas properties increased because of
higher production rates and investments in the properties. This non-cash expense
increased to $15.6 million or $5.57 per BOE in 1995 from $11.4 million or $5.15
per BOE in 1994.

During 1995, the Company borrowed funds pursuant to its bank credit facility
to finance a portion of its capital expenditures budget, and interest expense
increased to $2.2 million in 1995 from $1.0 million in 1994. General and
administrative costs also increased in total to $3.3 million in 1995 from $3.1
million in 1994, but on a unit basis declined 16% to $1.18 per BOE in 1995 from
$1.40 per BOE in 1994. The expenses of the Company's bonus plan declined to $0.1
million in 1995 from $1.4 million in 1994.

Pre-tax income increased to $9.5 million in 1995 from $6.4 million in 1994,
and therefore the tax provision increased to $3.6 million in 1995 from $2.4
million in 1994. Except for an estimated minimum tax liability of $0.1 million,
the remainder of the tax provision is deferred and does not require current
funding.

The Company's reserves at December 31, 1995 were 21.5 MMBOE and represent an
increase of 21% from the comparable amount one year earlier of 17.8 MMBOE. Oil
reserves increased to 8.0 MMBbls at the end of 1995 from

<PAGE> 19

6.5 MMBbls at the beginning of the year, and gas reserves rose to 81.2 Bcf at
December 31, 1995 from 68.3 Bcf at December 31, 1994.

LIQUIDITY AND CAPITAL RESOURCES

In November 1996, the Company completed a secondary offering of 3.2 million
shares of Common Stock. The net proceeds of $66.4 million were used to retire
the Term Loan and reduce the outstanding balance of the Revolver. See "Liquidity
and Capital Resources - Historical Financing Sources." The Company believes that
its existing working capital, combined with expected cash flow from operations
and borrowings under its bank credit facility, will be sufficient to fund its
operations and development activities through the end of 1997.

WORKING CAPITAL AND CASH FLOW. Working capital at December 31, 1996 was $6.7
million. Net cash flow from operations before working capital changes for 1996
was $37.3 million, which represents a 49% increase from the 1995 amount of $25.0
million. On a per share basis, net cash flow from operations before working
capital changes was $3.03 per share in 1996 as compared to $2.11 per share in
1995.

During 1996, the Company invested $79.4 million in its oil and gas
properties, which included $2.3 million of capitalized general and
administrative and interest costs. These investments were financed from cash
flow from operations and borrowings under the Company's bank credit facility.

The Company's production is sold on month-to-month contracts at prevailing
prices. From time to time, however, the Company has entered into hedging
transactions or fixed price sales contracts for its oil and gas production. The
purpose of these transactions is to reduce the Company's exposure to future oil
and gas price declines. This hedging policy provides that, unless prices change
by more than 25%, not more than one-half of the Company's production quantities
can be hedged without the consent of the Company's Board of Directors. Such swap
agreements typically provide for monthly payments by (if prices rise) or to (if
prices decline) the Company based on the difference between the strike price and
the average closing price of the near month NYMEX futures contract for each
month of the agreement. Because its properties are located in the Gulf Coast
Basin, the Company believes that fluctuations in the NYMEX futures prices will
closely match changes in the market prices for its production.

The Company's net loss from hedging transactions relating to 1995 production
was $11,000. Such swap contracts totaled 218.4 MBbls of oil and 460 BBtus of
gas. Additionally, the Company delivered 165.2 MBbls of oil at the Cut Off Field
during the eight month period ending August 31, 1995, at the fixed price of
$18.15 per barrel. The quantities associated with these hedging and fixed price
contracts represented 27% and 6% of the Company's oil and gas production for
1995, respectively.

The Company's net loss from hedging transactions for 1996 was $3.8 million.
Swap contracts totaled 493.9 MBbls of oil and 4,880 BBtus of gas, which
represented approximately 36% and 43%, respectively, of the Company's oil and
gas production for the year. As of March 14, 1997, the Company had hedged oil
and gas prices for certain future periods, and the applicable periods,
quantities and average prices are as follows:

OIL GAS
----------------------------------- -----------------------------------
VOLUMES PRICE VOLUMES PRICE
PERIOD (MBBLS) ($/BBL) (BBTUS) ($MMBTU)
---------------- ------------- --------------- --------------
<S> <C> <C> <C> <C>
First quarter 1997..................... 164.5 20.76 1,645 2.84
Second quarter 1997.................... - - 910 2.19
Third quarter 1997..................... - - 310 2.14
</TABLE>

HISTORICAL FINANCING SOURCES. Since the Company's Initial Public
Offering in July 1993, the Company has financed its activities with offering
proceeds, cash flow from operations, borrowings under its bank credit facility
described below and investments by two partnerships formed before the Initial
Public Offering which had uncommitted funds. These

<PAGE> 20

partnerships were provided the option of participating for a combined interest
of 25%, subject to the amount of available funds, in all new properties acquired
by the Company that met their investment criteria. As of December 1994, all
funds of these partnerships were committed and the Company is not required to
offer participation in subsequently acquired properties to these entities,
unless such acquisitions represent additional interests in properties already
owned by the partnerships.

In September 1996, the Company amended its credit facility with NationsBank
of Texas, N.A. ("NationsBank"), as agent for a group of banks that includes the
First National Bank of Commerce ("FNBC"), Hibernia National Bank and the First
National Bank of Boston. The total facility amount was $125 million which was
comprised of a three-year revolving credit facility (the "Revolver") and a
one-year term loan (the "Term Loan"). Proceeds of borrowings are to be used to
finance the acquisition of oil and gas reserves and for general corporate
purposes. Interest is payable quarterly. The credit agreement provides for
certain covenants, including restrictions or requirements with respect to
working capital, net worth, disposition of properties, incurrence of additional
debt, change of ownership and reporting responsibilities. Such covenants may
result in the limitation or prohibition of the payment of cash dividends by the
Company. A facility fee of $650,000 was paid by the Company on September 26,
1996, and a portion of the fee was expensed in the fourth quarter of 1996 upon
the retirement of the Term Loan.

The Revolver provides for total availability of $80 million with a
limitation on total outstanding borrowings based on a borrowing base amount
established by the banks for the Company's oil and gas properties, which is $60
million and is scheduled for redetermination in April 1997. At the option of the
Company, the outstanding balance of the Revolver will bear interest at the
NationsBank base rate, or at LIBOR plus a spread of 0.75% to 1.25%, depending
upon total outstanding borrowings. At March 14, 1997, the Revolver had an
outstanding principal balance of $23.1 million with a weighted average interest
rate of 6.3% per annum, and letters of credit totaling $6.6 million had been
issued pursuant to the facility. The principal balance of the Revolver is due on
October 1, 1999.

The Term Loan was established to finance the closing of certain 1996
acquisitions and certain development costs incurred by the Company during the
third quarter of 1996. On September 27, 1996, the Company borrowed $31.2 million
of the $45 million which was available under this portion of the facility. The
outstanding balance of the Term Loan was retired on November 15, 1996, and under
its terms is no longer available to the Company.

On November 30, 1995, the Company executed a term loan agreement with FNBC
in the original principal amount of $3.3 million for the purchase of the
RiverStone office building, a portion of which is used by the Company for its
Lafayette office. The loan has a five year term bearing interest at a rate of
7.45% over the entire term of the loan. Principal and interest are payable
monthly and are based upon a 20 year amortization period. The indebtedness under
the agreement is collateralized by the building. This loan agreement contains
covenants and restrictions that are similar to the NationsBank credit facility.

LONG-TERM FINANCING. The Company's 1997 capital expenditures budget is $104
million. Initially, this budget has been allocated to finance the continued
development of its property base and would be funded by a combination of cash
flow from operations and borrowings currently available under its bank credit
facility. A number of proposals for property acquisitions are currently
outstanding, and evaluations of a number of other properties for potential
purchase or joint venture are continuing, although no offers have been accepted
and no future acquisitions can be assured. The Company may seek additional
capital to finance future acquisitions or development activities beyond its
current plans. In addition to the public markets, the Company would also
consider new private financing sources and joint venture or partnership
structures to fund such additional investments.

REGULATORY AND LITIGATION ISSUES. In December 1995, Goodrich Leasehold
L.L.C. and Goodrich Drillers L.L.C. filed a civil action against the Company
in an attempt to set aside a Farmout Agreement affecting portions of the West
Flank of the Weeks Island Field in Iberia Parish, Louisiana. Management
believes that this claim is without merit and intends to vigorously defend
this action.

The Company is also named as a defendant in certain lawsuits and is a
party to certain regulatory proceedings arising in the ordinary course of
business. The regulatory proceedings include two instances in which the EPA has
indicated that it believes that the Company is a PRP for the cleanup of oilfield
waste facilities. Management does not

<PAGE> 21

expect these matters, individually or in the aggregate, to have a material
adverse effect on the financial condition of the Company.

Since November 26, 1993, new levels of lease and areawide bonds have been
required of lessees taking certain actions with regard to OCS leases. Operators
in the OCS waters of the Gulf of Mexico, including the Company, have been or may
be required to increase their areawide bonds and individual lease bonds to $3
million and $1 million, respectively, unless exemptions or reduced amounts are
allowed by the MMS. The Company currently has an areawide pipeline bond of $0.3
million and areawide lease bonds totaling $3.0 million issued in favor of the
MMS for its 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, the Company has been granted exempt
status by the MMS, which exempts the Company from the supplemental bonding
requirements. Under certain circumstances, the MMS may require any Company
operations on federal leases to be suspended or terminated. Any such suspension
or termination could materially and adversely affect the Company's financial
condition and operations.

As amended by the Coast Guard Authorization Act of 1996, OPA requires
responsible parties for offshore facilities to provide financial assurance in
the amount of $35 million to cover potential OPA liabilities. This amount can be
increased up to $150 million if a formal risk assessment indicates that an
amount higher than $35 million should be required. The Company does not
anticipate that it will experience any difficulty in satisfying the MMS's
requirements for demonstrating financial responsibility under OPA.

The Company operates under numerous state and federal laws enacted for the
protection of the environment. In the ordinary course of business, the Company
conducts an ongoing review of the effects of these various environmental laws on
its business and operations. The estimated cost of continued compliance with
current environmental laws, based upon the information currently available, is
not material to the Company's results of operations or financial position. It is
impossible to determine whether and to what extent the Company's future
performance may be affected by environmental laws; however, management believes
that such laws will not have a material adverse effect on the Company's results
of operations or financial position.

FORWARD-LOOKING STATEMENTS

Certain of the statements set forth under this Item and elsewhere in this
Form 10-K, such as the statements regarding planned capital expenditures
(including the number of wells to be drilled in 1997) and the availability of
capital resources to fund capital expenditures, are forward-looking and are
based upon assumptions and anticipated results that are subject to numerous
risks and uncertainties. The actual amount of capital expenditures may vary
significantly due to many factors, including drilling results, oil and gas
prices, industry conditions, the prices of goods and services, the availability
of drilling rigs and other support services, the availability of capital
resources and the extent to which proved properties are acquired. In addition,
the drilling of oil and gas wells is subject to governmental regulations and
operating risks. See "Regulation" and "Operational Risks and Insurance" in Item
1 of this Form 10-K. The availability of capital resources is dependent upon the
Company's ability to generate cash flow from operations and to remain in
compliance with its credit agreements and is subject to the risks and
uncertainties attendant to adverse general economic and financial market
conditions, including stock prices, interest rates and credit availability, as
well as conditions prevailing in the oil and gas industry.

<PAGE> 22

ACCOUNTING MATTERS

BASIS OF PRESENTATION. The consolidated financial statements include the
accounts of the Company and its proportionate share of certain partnerships,
TSPC and TSPC's proportionate share of certain partnerships. All
intercompany balances and transactions are eliminated.

FULL COST METHOD. The Company uses the full cost method of accounting for
its 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. The net employee, general and
administrative costs that were capitalized were $2.3 million, $1.8 million and
$2.7 million for the years ended December 31, 1996, 1995 and 1994, respectively.
The Company amortizes its investment in oil and gas properties using the future
gross revenue method.

DEFERRED INCOME TAXES. Deferred income taxes have been determined in
accordance with Financial Accounting Standards Board Statement No. 109,
"Accounting for Income Taxes." TSPC recorded a deferred tax asset on January 1,
1992, based on the estimated value to be derived from the utilization of the tax
attribute carryovers of TSPC and its subsidiaries. As of December 31, 1996, the
Company has a deferred tax liability of $12.1 million which has been calculated
with the assumption that the Company will have sufficient taxable income in
future years to utilize certain tax attribute carryforwards. The achievement of
these levels of taxable income, however, is subject to a number of factors
beyond the control of the Company.

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 15,
1997, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference. For information concerning Item 10 - Executive
Officers of Registrant, see Part I - Item 4A.

<PAGE> 23

PART IV

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

(A) 1. FINANCIAL STATEMENTS:

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

Report of Independent Public Accountants

Consolidated Balance Sheet as of the years ended December 31, 1996 and 1995

Consolidated Statement of Operations for the three years in the period
ended December 31, 1996

Consolidated Statement of Cash Flows for the three years in the period
ended December 31, 1996

Consolidated Statement of Changes in Equity for the three years in the
period ended December 31, 1996

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 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)).

+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 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated
by reference to Exhibit 10.12 to the Registrant's Registration
Statement on Form S-1 (Registration No. 33-62362)).

+10.5 -- 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. 011-12074)).

<PAGE> 24

10.6 -- Second Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and
NationsBank of Texas, N.A., as Agent, dated as of September 26,
1996 (incorporated by reference to Exhibit 99.1 to the
Registrant's Current Report on Form 8-K as filed with the
Securities and Exchange Commission on October 16, 1996 (File No.
011-12074)).

+10.7 -- 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. 011-12074)) .

10.8 -- Term Loan Agreement, dated November 30, 1995, between the
Registrant and First National Bank of Commerce (incorporated by
reference to Exhibit 10.11 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1995 (File No.
011-12074)) .

21.1 -- Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to the Registrant's Annual Report on Form 10-K
for the year ended December 31, 1995).

*23.1 -- Consent of Arthur Andersen LLP

*23.2 -- Consent of Atwater Consultants, Ltd.

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

*27 -- Financial Data Schedule
------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.

(B) REPORTS ON FORM 8-K

The Company filed a Current Report on Form 8-K on October 16, 1996 that
disclosed the results of a report of the Company's estimated proved oil and gas
reserves dated as of August 31, 1996, prepared in accordance with Securities and
Exchange Commission guidelines.

<PAGE> 25

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 26TH DAY OF MARCH, 1997.

STONE ENERGY CORPORATION

By: /s/ JAMES H. STONE
-------------------------------
James H. Stone
Chairman of the Board 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> <C> <C>
/s/ JAMES H. STONE Chief Executive Officer and March 26, 1997
----------------------------------------- Chairman of the Board
James H. Stone (Principal Executive Officer)

/s/ D. PETER CANTY President, Chief Operating Officer March 26, 1997
----------------------------------------- and Director
D. Peter Canty

/s/ MICHAEL L. FINCH Executive Vice President, Chief March 26, 1997
----------------------------------------- Financial Officer and Director
Michael L. Finch (Principal Financial Officer)

/s/ JAMES H. PRINCE Vice President, Chief Accounting March 26, 1997
----------------------------------------- Officer and Controller
James H. Prince (Principal Accounting Officer)

/s/ JOE R. KLUTTS Director and Vice Chairman of March 26, 1997
----------------------------------------- the Board
Joe R. Klutts

/s/ DAVID R. VOELKER Director March 26, 1997
-----------------------------------------
David R. Voelker

/s/ JOHN P. LABORDE Director March 26, 1997
-----------------------------------------
John P. Laborde

/s/ ROBERT A. BERNHARD Director March 26, 1997
-----------------------------------------
Robert A. Bernhard

/s/ RAYMOND B. GARY Director March 26, 1997
-----------------------------------------
Raymond B. Gary

/s/ B. J. DUPLANTIS Director March 26, 1997
-----------------------------------------
B. J. Duplantis
</TABLE>

<PAGE> 26

INDEX TO FINANCIAL STATEMENTS

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

Consolidated Balance Sheet of Stone Energy Corporation as of
December 31, 1996 and 1995........................................... F-3

Consolidated Statement of Operations of Stone Energy Corporation
for the years ended December 31, 1996, 1995 and 1994................. F-4

Consolidated Statement of Cash Flows of Stone Energy Corporation
for the years ended December 31, 1996, 1995 and 1994................. F-5

Consolidated Statement of Changes in Equity of Stone Energy Corporation
for the years ended December 31, 1996, 1995 and 1994................. F-6

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

F-1

<PAGE> 27

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 subsidiary as of December 31, 1996 and
1995, and the related consolidated statements of operations, changes in equity
and cash flows for each of the three years in the period ended December 31,
1996. 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 generally accepted auditing
standards. 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
subsidiary as of December 31, 1996 and 1995, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1996, in conformity with generally accepted accounting principles.

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
February 28, 1997

F-2

<PAGE> 28

STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

DECEMBER 31,
--------------------------------------
ASSETS 1996 1995
------ ---------------- -------------
<S> <C> <C>
Current assets:
Cash and cash equivalents................................................... $9,864 $6,286
Marketable securities, at market............................................ 10,331 10,232
Accounts receivable......................................................... 12,466 7,247
Unbilled accounts receivable................................................ 470 89
Other current assets........................................................ 94 612
---------------- -------------
Total current assets...................................................... 33,225 24,466
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $125,533 and $106,277, respectively....................... 167,562 108,820
Unevaluated................................................................. 3,834 2,428
Building and land, net of accumulated depreciation of $79 and
$0, respectively.......................................................... 3,390 3,284
Other assets, net of accumulated depreciation and amortization
of $2,058 and $4,177, respectively.......................................... 1,395 462
---------------- -------------
Total assets.............................................................. $209,406 $139,460
================ =============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current portion of long-term loans.......................................... $76 $69
Advance payments............................................................ 354 373
Accounts payable to vendors................................................. 17,651 10,980
Undistributed oil and gas proceeds.......................................... 4,567 5,228
Other accrued liabilities................................................... 3,894 2,437
---------------- -------------
Total current liabilities................................................. 26,542 19,087
Long-term loans................................................................. 26,172 47,754
Deferred tax liability.......................................................... 12,112 5,413
Other long-term liabilities..................................................... 139 279
---------------- -------------
Total liabilities......................................................... 64,965 72,533
---------------- -------------
Commitments and Contingencies (see Note 9)
Common Stock, $.01 par value; authorized 25,000,000 shares;
issued and outstanding 15,015,408 and 11,792,349 shares, respectively....... 150 118
Paid-in capital................................................................. 118,606 52,157
Retained earnings............................................................... 25,685 14,652
---------------- -------------
Total equity.............................................................. 144,441 66,927
---------------- -------------
Total liabilities and equity.............................................. $209,406 $139,460
================ =============
</TABLE>

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

F-3

<PAGE> 29

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS

(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1996 1995 1994
------------ ----------- ------------
<S> <C> <C> <C>
Revenues:
Oil and gas production............................................. $55,839 $38,693 $31,179
Overhead reimbursements and management fees........................ 814 522 444
Other income....................................................... 1,312 1,336 1,264
------------ ----------- ------------
Total revenues................................................... 57,965 40,551 32,887
------------ ----------- ------------
Expenses:
Normal lease operating expenses.................................... 8,625 6,294 5,312
Major maintenance expenses......................................... 427 446 1,834
Production taxes................................................... 3,399 3,057 2,303
Depreciation, depletion and amortization........................... 19,564 15,719 11,569
Interest........................................................... 3,574 2,191 982
Salaries and other employee costs.................................. 2,062 1,663 1,566
Incentive compensation plan........................................ 928 85 1,358
General and administrative costs................................... 1,447 1,635 1,533
------------ ----------- ------------
Total expenses................................................... 40,026 31,090 26,457
------------ ----------- ------------
Net income before income taxes ........................................ 17,939 9,461 6,430
------------ ----------- ------------
Provision for income taxes:
Current............................................................ 208 131 --
Deferred........................................................... 6,698 3,514 2,410
------------ ----------- ------------
Total income taxes............................................... 6,906 3,645 2,410
------------ ----------- ------------
Net income............................................................. $11,033 $5,816 $4,020
============ =========== ============
Earnings per common share (see Note 1):
Net income per share .............................................. $0.89 $0.49 $0.34
============ =========== ============
Net income per share assuming full dilution........................ $0.88 $0.49 $0.34
============ =========== ============
Average shares outstanding......................................... 12,356 11,818 11,801
============ =========== ============
Average shares outstanding assuming full dilution.................. 12,486 11,847 11,870
============ =========== ============

</TABLE>

The accompanying notes are an integral part of this consolidated statement.

F-4

<PAGE> 30

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS

(DOLLAR AMOUNTS IN THOUSANDS)

YEAR ENDED DECEMBER 31,
-----------------------------------------------------
1996 1995 1994
------------ ------------ -------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income......................................................... $11,033 $5,816 $4,020
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization...................... 19,564 15,719 11,569
Provision for deferred income taxes........................... 6,698 3,514 2,410
Gain on sale of other assets.................................. -- -- (88)
------------ ------------ -------------
37,295 25,049 17,911
(Increase) decrease in marketable securities.................. (99) 4,964 (15,196)
(Increase) decrease in accounts receivable.................... (5,600) 426 850
(Increase) decrease in other current assets................... 518 (370) 904
Increase (decrease) in accrued liabilities.................... 777 (2,260) 5,586
Deferred financing costs...................................... (418) (151) (128)
Other......................................................... (140) (159) (318)
------------ ------------ -------------
Net cash provided by operating activities.............................. 32,333 27,499 9,609
------------ ------------ -------------
Cash flows from investing activities:
Investment in oil and gas properties............................... (72,733) (48,122) (41,174)
Sale of reserves in place.......................................... -- -- 2,011
Proceeds from sale of other assets................................. -- -- 179
Purchase of building and land, building additions
and renovations.................................................. (185) (3,284) --
Other asset additions.............................................. (743) (101) (148)
------------ ------------ -------------
Net cash used in investing activities.................................. (73,661) (51,507) (39,132)
------------ ------------ -------------
Cash flows from financing activities:
Proceeds from borrowings........................................... 49,000 30,098 22,725
Repayment of debt.................................................. (70,575) (5,000) (16,223)
Sale of common stock............................................... 66,446 -- --
Exercise of stock options.......................................... 35 66 28
------------ ------------ -------------
Net cash provided by financing activities.............................. 44,906 25,164 6,530
------------ ------------ -------------
Net increase (decrease) in cash and cash equivalents................... 3,578 1,156 (22,993)
Cash and cash equivalents, beginning of year........................... 6,286 5,130 28,123
------------ ------------ -------------
Cash and cash equivalents, end of year................................. $9,864 $6,286 $5,130
============ ============ =============
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)............................. $3,672 $1,927 $1,053
Income taxes..................................................... 145 216 --
------------ ------------ -------------
$3,817 $2,143 $1,053
============ ============ =============
</TABLE>

The accompanying notes are an integral part of this consolidated statement.

F-5

<PAGE> 31

STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

(DOLLAR AMOUNTS IN THOUSANDS)

COMMON PAID-IN RETAINED
STOCK CAPITAL EARNINGS
------------- -------------- -------------
<S> <C> <C> <C>
Balance, December 31, 1993................................... $ 118 $ 52,063 $ 4,816
Net income................................................... -- -- 4,020
Exercise of stock options.................................... 28 --
------------- -------------- -------------
Balance, December 31, 1994................................... 118 52,091 8,836
Net income................................................... -- -- 5,816
Exercise of stock options.................................... 66 --
------------- -------------- -------------
Balance, December 31, 1995................................... 118 52,157 14,652
Net income................................................... -- -- 11,033
Sale of common stock......................................... 32 66,414 --
Exercise of stock options.................................... 35 --
------------- -------------- -------------
Balance, December 31, 1996................................... $ 150 $ 118,606 $ 25,685
============= ============== =============
</TABLE>

The accompanying notes are an integral part of this consolidated statement.

F-6

<PAGE> 32

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

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

Stone Energy Corporation (the "Company" or "Stone Energy") is an independent
oil and gas company primarily engaged in the acquisition, exploitation and
operation of producing oil and gas properties located in the Gulf Coast Basin.
The Company's business strategy is focused on the acquisition of mature
properties with established production history that have significant
exploitation and development potential. Since implementing its present business
strategy in 1989, Stone Energy has acquired 14 properties that comprise its
asset base - seven offshore and seven onshore Louisiana. The Company is
headquartered in Lafayette, Louisiana, with additional offices in New Orleans
and Houston.

The Company was organized under the laws of the State of Delaware in March
1993 to become a holding company for The Stone Petroleum Corporation ("TSPC")
and its subsidiaries and interests in certain partnerships (the "Acquisition
Partnerships").

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

CONSOLIDATION:

The consolidated financial statements include the accounts of the Company
and its proportionate share of the Acquisition Partnerships; TSPC, a
wholly-owned subsidiary organized in June 1981 and TSPC's proportionate share of
managed limited partnerships. In December 1996, TSPC adopted a plan of
dissolution whereby a majority of its assets are to be transferred to the
Company. Any assets necessary to satisfy any known liabilities will remain in
TSPC. In December 1994, Cut Off Corporation ("Cut Off"), a wholly-owned
subsidiary of TSPC organized in May 1991, was merged into TSPC. The accounts of
Cut Off were included in the consolidated financial statements prior to the
merger. In December 1993, The Stone Programs Corporation ("Programs"), a
wholly-owned subsidiary of TSPC organized in March 1976 as a broker dealer, was
liquidated and The Stone Properties Corporation ("Properties"), a wholly-owned
subsidiary of TSPC organized in August 1990, was merged into TSPC. Prior to such
liquidation and merger, the accounts of both Programs and Properties were
included in the consolidated financial statements. Both Properties and Cut Off
were organized for the purpose of purchasing certain oil and gas properties and
conducting related development and operational activities. All intercompany
balances and transactions are eliminated.

USE OF ESTIMATES:

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Estimates
are used primarily when accounting for depreciation, depletion and amortization,
taxes and contingencies.

FAIR VALUE OF FINANCIAL INSTRUMENTS:

Fair value of cash, cash equivalents, net accounts receivable, accounts
payable and debt approximates book value at December 31, 1996.

F-7

<PAGE> 33

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(Continued)

OIL AND GAS PROPERTIES:

The Company follows the full cost method of accounting for oil and gas
properties. Under this method, all acquisition, exploration and development
costs, including certain related employee costs and general and administrative
costs (less any reimbursements for such costs), incurred for the purpose of
finding oil and gas are 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.

The Company amortizes its investment in oil and gas properties using the
future gross revenue method, a unit of production method, whereby the annual
provision for depreciation, depletion and amortization is computed by dividing
revenue produced 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. Additionally, the capitalized costs of oil and gas
properties cannot exceed the present value of the estimated net cash flow from
its proved reserves, together with the lower of cost or estimated fair value of
its unevaluated properties (the full cost ceiling). Transactions involving sales
of reserves in place, unless extraordinarily large portions of reserves are
involved, are recorded as adjustments to the reserves for accumulated
depreciation, depletion and amortization.

Oil and gas properties include $3,834 and $2,428 of unevaluated properties
and related costs that are not being amortized at December 31, 1996 and 1995,
respectively. These costs are associated with the acquisition and evaluation of
unproved properties and major development projects expected to entail
significant costs to ascertain quantities of proved reserves. The unevaluated
costs at December 31, 1996 relate to acquisition and development costs incurred
during 1996, and at December 31, 1995 relate to acquisition costs incurred in
1994. The Company currently believes that the unevaluated properties at December
31, 1996 will be evaluated within one to 24 months. The excluded costs and
related proved reserves 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, 1996 and 1995 was $90 and $246, respectively.

In March 1995, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards No. 121 ("SFAS No. 121"),
"Accounting for the Impairment of Long-Lived Assets and For Long-Lived Assets
to be Disposed of." The Company adopted SFAS No. 121 in 1996. The effect of
adopting SFAS No. 121 was not material.

CASH AND CASH EQUIVALENTS:

The Company considers all highly liquid investments in overnight securities
through its commercial bank accounts, which result in available funds on the
next business day, to be cash and cash equivalents.

MARKETABLE SECURITIES:

The Company has retained a third-party investment firm to manage its
portfolio of short-term marketable securities, which are actively and frequently
bought and sold with the primary objective of generating profits on the
short-term differences in prices. Thus, the related security investments are
classified as trading securities, which are marked to market

F-8

<PAGE> 34

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(Continued)

in accordance with SFAS No. 115. All realized and unrealized gains and losses
are included in current operating results. The securities included in the
portfolio are primarily U.S. Treasury obligations and mortgage-backed securities
with an average maturity of not more than 180 days.

INCOME TAXES:

The Company accounts for income taxes in accordance with SFAS No. 109.
Provisions for income taxes include deferred taxes resulting primarily from
temporary differences due to different reporting methods for oil and gas
properties for financial reporting purposes and income tax purposes. For
financial reporting purposes, all exploratory and development expenditures are
capitalized and depreciated, depleted and amortized on the 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, the Company uses certain provisions of the
Internal Revenue Code which allow capitalization of intangible drilling costs
where management deems appropriate. Other financial and income tax reporting
differences occur as a result of statutory depletion, different reporting
methods for sales of oil and gas reserves in place, and different reporting
periods used in accounting for income and costs arising from oil and gas
operations conducted through tax partnerships.

GAS PRODUCTION REVENUES:

The Company records as revenue only that portion of gas production sold and
allocable to its ownership interest in the related well. Any gas production
proceeds received in excess of its ownership interest are reflected as a
liability in the accompanying consolidated financial statements. Revenues
relating to gas production to which the Company is entitled but for which the
Company has not received payment are not recorded in the consolidated financial
statements until compensation is received.

Net under-balanced production positions at December 31, 1996 and 1995 are
immaterial.

EARNINGS PER COMMON SHARE:

Earnings per share for each of the years ended December 31, 1996, 1995 and
1994, was computed by dividing net earnings by the sum of the outstanding shares
of Common Stock of the Company, plus Common Stock Equivalents, thereby
reflecting the dilutive effect of stock options granted to outside directors and
certain employees on various dates through December 31, 1996 (see Note10).

BUILDING AND LAND:

The Company records building and land at cost. The Company's office building
is being depreciated for financial statement purposes on the straight-line
method over its estimated useful life.

HEDGING ACTIVITIES:

From time to time, the Company has utilized futures and hedging activities
in order to reduce the effect of product price volatility. The resulting gains
or losses on hedging contracts are accounted for as revenues from oil and gas
production in the financial statements.

F-9

<PAGE> 35

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 2 -- ACCOUNTS RECEIVABLE AND ADVANCE PAYMENTS:

In its capacity as operator, manager and/or sponsor for its partners and
other co-venturers, the Company incurs drilling and other costs and receives
payment for advance billings for drilling, all of which are billed to the
respective parties.
Accounts receivable and advance payments were comprised of the following
amounts:

DECEMBER 31,
-----------------------------------------
1996 1995
----------------- ----------------
Accounts Receivable--
Managed partnerships.......... $1,687 $447
Other co-venturers............ 1,136 1,364
Trade......................... 9,637 5,432
Officers and employees........ 6 4
----------------- ----------------
$12,466 $7,247
================= ================

Advance Payments--
Managed partnerships.......... $ -- $ 216
Other co-venturers............ 256 56
Trade......................... 98 101
----------------- ----------------
$354 $373
================= ================

Costs incurred but not yet billed to the managed partnerships and other
co-venturers at December 31, 1996 and 1995 amounted to $470 and $89,
respectively.

F-10

<PAGE> 36

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 3--INVESTMENT IN OIL AND GAS PROPERTIES:

The following table discloses certain financial data relative to the
Company's oil and gas producing activities, which are located onshore and
offshore the continental United States:
<TABLE>
<CAPTION>

YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1996 1995 1994
-------------- --------------- -------------
<S> <C> <C> <C>
Costs incurred during year:
Capitalized--
Acquisition costs:
Proved.................................................... $24,522 $8,104 $6,711
Unevaluated............................................... 2,065 -- 5,080
Investments posted as performance bonds..................... 63 (30) (326)
Exploratory drilling........................................ 26,339 8,261 4,719
Development drilling:
Proved.................................................... 22,321 27,383 18,345
Unevaluated............................................... 1,769 -- 3,896
General and administrative costs............................ 3,238 2,743 3,708
Less: overhead reimbursements, management fees
and repromotion income.................................... (913) (953) (959)
-------------- --------------- -------------
$79,404 $45,508 $41,174
============== =============== =============
Charged to expenses--
Operating costs:
Normal lease operating expenses........................... $8,625 $6,294 $5,312
Major maintenance expenses................................ 427 446 1,834
-------------- --------------- -------------
Total operating costs....................................... 9,052 6,740 7,146
Production taxes............................................ 3,399 3,057 2,303
-------------- --------------- -------------
$12,451 $9,797 $9,449
============== =============== =============
Depreciation, depletion and amortization.......................... $19,256 $15,551 $11,420
============== =============== =============
Oil and gas properties--
Balance, beginning of year.................................... $217,525 $172,017 $130,843
Additions..................................................... 79,404 45,508 41,174
-------------- --------------- -------------
Balance, end of year.......................................... 296,929 217,525 172,017
-------------- --------------- -------------
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year.................................. (106,277) (90,726) (70,746)
Provision for depreciation, depletion and amortization...... ( 19,256) (15,551) (11,420)
Sale of reserves............................................ -- -- (2,011)
Cancellation of loan........................................ -- -- (1,126)
Cancellation of production payment loan..................... -- -- (5,423)
-------------- --------------- -------------
Balance, end of year.......................................... (125,533) (106,277) (90,726)
-------------- --------------- -------------
Net capitalized costs (proved and unevaluated).................... $171,396 $111,248 $81,291
============== =============== =============
</TABLE>

F-11

<PAGE> 37

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 3--INVESTMENT IN OIL AND GAS PROPERTIES: (Continued)

In November 1994, the Company sold to Nuevo Energy Company ("Nuevo") all of
the interests in 11 oil and gas fields located in Louisiana, Mississippi and
Oklahoma owned by the Company and certain of its affiliates. The Company
received $2,011 of the total of $9,480 of sales proceeds, the balance of which
was attributable to the interests of other participants in limited partnerships
and joint ventures formed during the period of 1980 through 1985. The proved
reserves of the properties sold comprised approximately 3% of the Company's
total estimated proved reserves as of December 31, 1994. Therefore, the sale was
recorded as an adjustment to the reserve for accumulated depreciation, depletion
and amortization.

In addition to the cash received, the Company's obligation of $5,423 with
respect to a production payment owed to Energy Assets International Corporation
("EAI"), an affiliate of Nuevo, was terminated. The transaction was recorded as
an adjustment to the reserve for accumulated depreciation, depletion and
amortization.

NOTE 4--INCOME TAXES:

The Company follows the provisions of SFAS No. 109, "Accounting For Income
Taxes," which provides for recognition of a deferred tax asset for deductible
temporary timing differences, operating loss carryforwards, statutory depletion
carryforwards and tax credit carryforwards net of a "valuation allowance." An
analysis of the Company's deferred tax liability follows:

DECEMBER 31,
-------------------------------------
1996 1995
--------------- --------------
Net operating loss carryforwards............... $1,224 $5,335
Statutory depletion carryforward............... 4,463 3,857
Investment tax credit carryforward............. 887 1,967
Alternative minimum tax credit................. 447 239
Temporary differences:
Oil and gas properties--full cost........ (18,794) (15,223)
Other.................................... (339) (487)
--------------- --------------
(12,112) (4,312)
Valuation allowance..................... 0 (1,101)
--------------- --------------
($12,112) ($5,413)
=============== ==============

For tax reporting purposes, the Company had operating loss carryforwards
of $3,180 and investment tax credit carryforwards of $887 at December 31, 1996.
If not utilized, such carryforwards would begin expiring in 1997 and would
completely expire by the year 2007. Because of tax rules relating to changes in
corporate ownership and computations required to be made on a separate entity
basis, the utilization by the Company of these benefit carryforwards in reducing
its tax liability is restricted. Additionally, the Company had available for tax
reporting purposes $11,592 in statutory depletion deductions that may be carried
forward indefinitely. Recognition of a deferred tax asset associated with these
carryforwards is dependent upon the Company's evaluation that it is more likely
than not that the asset will ultimately be realized. As of December 31, 1995,
the valuation allowance was increased due to revised estimates of investment tax
credits that the Company believed more likely than not would expire prior to
their utilization. The valuation allowance was eliminated at December 31, 1996
as the corresponding investment tax credits expired unutilized.

F-12

<PAGE> 38

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 4--INCOME TAXES: (Continued)

Reconciliations between the statutory federal income tax expense (benefit)
rate and the Company's effective income tax expense rate as a percentage of
income before income taxes were as follows:

YEAR ENDED DECEMBER 31,
-----------------------------------------------
1996 1995 1994
---------- ---------- -----------
<S> <C> <C> <C>
Income taxes computed at the statutory
federal income tax rate........................................ 35% 35% 35%
Changes in valuation allowance................................... -- -- 9
State tax and other.............................................. 4 4 (7)
---------- ---------- -----------
Effective income tax rate........................................ 39% 39% 37%
========== ========== ===========
</TABLE>

NOTE 5--LONG-TERM LOANS:

Long-term loans consisted of the following at:
<TABLE>
<CAPTION>

DECEMBER 31,
-----------------------------------
1996 1995
------------- -------------
<S> <C> <C>
Unsecured revolving credit facility with NationsBank
of Texas, N.A. ("NationsBank") (described below)............................ $23,073 $44,573
Term Loan Agreement with First National Bank of
Commerce ("FNBC") with interest at 7.45%.................................... 3,175 3,250
Less: portion due within one year.............................................. (76) (69)
------------- -------------
Total long-term loans....................................................... $26,172 $47,754
============= =============
</TABLE>

Aggregate minimum principal payments at December 31, 1996 for the next five
years are as follows: 1997-$76, 1998-$81, 1999-$23,161, 2000-$94 and
2001-$2,843.

On September 26, 1996, the Company executed its Second Amended and Restated
Credit Agreement with NationsBank of Texas, N.A., as agent for a group of banks.
The agreement provided for a total facility of $125,000 and was comprised of a
three-year revolving credit loan and a one-year term loan. The term loan of
$45,000 was established to finance the closing of three acquisitions and certain
development costs incurred during the third quarter of 1996. The Company retired
the term loan in November 1996 with the proceeds from the common stock offering
described in Note 8. No amounts under the term loan may be reborrowed.

The revolver provides for total availability of $80,000, with a current
borrowing base limitation on total outstanding borrowings of $60,000. The amount
of the borrowing base is scheduled for redetermination in April 1997. The
borrowing base limitation is based on a borrowing base amount established by the
banks for the Company's oil and gas properties. Interest under the revolver is
payable quarterly and, at December 31, 1996, the weighted average interest rate
of the facility was 6.3% per annum, the total outstanding principal balance was
$23,073 and letters of credit totaling $6,627 had been issued pursuant to the
facility.

F-13

<PAGE> 39

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 5--LONG-TERM LOANS: (Continued)

On November 30, 1995, the Company executed a term loan agreement with First
National Bank of Commerce ("FNBC") in the original principal amount of $3,250 to
finance the purchase of the Company's office building (see Note 6). The loan has
a five-year term bearing interest at the rate of 7.45% over the entire term of
the loan. Payments of $26 are due monthly and are based upon a 20-year
amortization period. The indebtedness under the agreement is collateralized by
the building.

The terms of the NationsBank and FNBC agreements contain, among other
provisions, requirements for maintaining defined levels of working capital and
tangible net worth.

NOTE 6--TRANSACTIONS WITH RELATED PARTIES:

The Company receives certain fees as a result of its function as managing
partner of certain partnerships. For the years ended December 31, 1996, 1995 and
1994, the Company generated management fees and overhead reimbursements from
partnerships amounting to $744, $851and $637, respectively, the majority of
which was treated as a reduction of the investment in oil and gas properties.

The Company collects and distributes production revenues as managing partner
for the partnerships' interests in oil and gas properties. At December 31, 1995,
$858 was included in undistributed oil and gas proceeds that was identified as
distributable to partners in the partnerships.

TSPC leased office space in a building owned by RiverStone Associates, an
affiliate, from 1982 through November 30, 1995, on which date the building and
related land were purchased by the Company. The entire purchase price of $3,250
was paid to the holder of the first mortgage on the property. RiverStone
Associates and its partners did not receive any of the sales proceeds, nor were
any such parties relieved of any personal liability as a result of the sale.
James H. Stone and Joe R. Klutts, each an officer and director of the Company,
are partners in RiverStone Associates. The sale was approved by the
disinterested members of the Board of Directors. The Company and TSPC incurred
net rent expense of $633 and $702, respectively, during the years ended December
31, 1995 and 1994.

In December 1994, the Company sold a residential townhouse located in
Houston, Texas to Frantzen/Voelker Investments, L.L.C. ("Frantzen/Voelker") for
$77. David Voelker, a director of the Company, is a principal of
Frantzen/Voelker. The sales price was based upon an appraisal of the property by
an independent third party and the sale was approved by the disinterested
members of the Board of Directors.

The Company's interests in certain oil and gas properties are burdened by
various net profit interests granted at the time of acquisition to certain
officers and other employees of the Company. Such net profit interest owners do
not receive any cash distributions until the Company has recovered all of its
acquisition, development, financing and operating costs. Management believes the
estimated value of such interests at the time of acquisition is not material to
the Company's financial position or results of operations.

Certain officers and directors are working interest owners in properties
operated by the Company and are billed and pay their proportionate share of
drilling and operating costs in the normal course of business.

NOTE 7--HEDGING ACTIVITIES:

In order to reduce its exposure to the possibility of declining oil and gas
prices, the Company hedges with third parties certain of its crude oil and
natural gas production in various swap agreement contracts. The crude oil
contracts are tied to the price of NYMEX light sweet crude oil futures and are
settled monthly based on the differences between

F-14

<PAGE> 40

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 7--HEDGING ACTIVITIES: (Continued)

contract prices and the average NYMEX prices for that month applied to the
related contract volumes. Settlement for gas swap contracts is based on the
average of the last three days of trade on the NYMEX for each month of the swap.

As of February 28, 1997, the Company's forward position was as follows:

OIL GAS
---------------------------------- -------------------------------------
AVERAGE AVERAGE
PRICE PRICE
MBBLS ($/BBL) BBTU ($MMBTU)
------------ -------------- ------------- ----------------
<S> <C> <C> <C> <C>
1997....................... 165 $20.76 2,865 $2.556
</TABLE>

The fair market value of the hedging contracts is ($434) at December 31,
1996. For the years ended December 31, 1996 and 1995, net oil and gas hedging
losses of $3,801 and $11, respectively, were treated as a reduction of revenues
from oil and gas production.

NOTE 8--COMMON STOCK:

On November 19, 1996, the Company completed an underwritten public offering
of 3,680,000 shares of Common Stock at a price to the public of $21.75 per
share. The shares offered included 3,221,159 shares sold by the Company (480,000
shares of which represented the exercise of the underwriters' over-allotment
option) and 458,841 shares sold by certain selling stockholders. This offering
resulted in the receipt by the Company of cash proceeds (net of $217 of offering
costs) totaling approximately $66,446. The Company used a portion of the
proceeds to retire a term loan incurred to finance the cost of acquisitions and
certain development projects performed in the third quarter of 1996 (see Note
5), and the remainder was used to repay a portion of the outstanding
indebtedness under its revolving bank credit facility.

NOTE 9--COMMITMENTS AND CONTINGENCIES:

The Company leases office facilities in New Orleans, Louisiana under the
terms of a long-term non-cancelable lease expiring on March 15, 1998. Office
facilities in Lafayette, Louisiana were leased through November 30, 1995, on
which date the Company purchased the building (see Note 6). Additionally, the
Company leases automobiles under terms of non-cancelable leases expiring at
various dates through 1999. The minimum net annual commitments under all leases,
subleases and contracts noted above at December 31, 1996 are as follows:

1997......................... $100
1998......................... 40
1999......................... 14

Rent expense for the years ended December 31, 1996, 1995 and 1994 was
approximately $114, $727 and $793, respectively.

The Company is the managing general partner of eight partnerships and is
contingently liable for any recourse debts and other liabilities that result
from their operations. Management currently is not aware of the existence of any
such liabilities that would have a material impact on the future operations of
the Company.

F-15

<PAGE> 41

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 9--COMMITMENTS AND CONTINGENCIES: (Continued)

In December 1995, Goodrich Leasehold L.L.C. and Goodrich Drillers L.L.C.
filed a civil action in the 333rd Judicial District Court, Harris County, Texas,
against the Company in an attempt to set aside a Farmout Agreement affecting
portions of the West Flank of the Weeks Island field in Iberia Parish,
Louisiana. Management believes that this claim is without merit and intends to
vigorously defend this action.

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. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties for offshore facilities to provide
financial assurance in the amount of $35,000 cover potential OPA liabilities.
This amount can be increased up to $150,000 if a formal risk assessment
indicates that an amount higher than $35,000 should be required. The Company
does not anticipate that it will experience any difficulty in satisfying the
MMS's requirements for demonstrative financial responsibility under OPA.

In 1996, the American Institute of Certified Public Accountants issued its
Statement of Position 96-1 ("SOP 96-1"), which provides guidance on accounting
for environmental remediation liabilities. SOP 96-1 interprets existing
Financial Accounting Standards Board standards applicable to public companies.
The Company intends to apply SOP 96-1 starting in 1997. The Company believes
adoption of SOP 96-1 will not have a material effect on its results of
operations or financial position.

NOTE 10--EMPLOYEE BENEFIT PLANS:

The Company entered into deferred compensation and disability agreements
with certain of its employees whereby the Company has purchased split-dollar
life insurance policies to provide certain retirement and death benefits for the
employees and death benefits payable to the Company. The aggregate death benefit
of the policies is $3,473 at December 31, 1996, of which $2,400 is payable to
employees or their beneficiaries and $1,073 is payable to the Company. Total
cash surrender value of the policies, net of related surrender charges at
December 31, 1996, was approximately $748. Additionally, the benefits under the
deferred compensation agreements vest after certain periods

F-16

<PAGE> 42

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 10--EMPLOYEE BENEFIT PLANS: (Continued)

of employment, and at December 31, 1996, the liability for such vested benefits
was approximately $710. 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 liability
and is being amortized over the remaining term of the various deferred
compensation agreements.

The Company has adopted a series of incentive compensation plans designed to
align the interests of the executives and employees with those of its
stockholders. The following is a brief description of each of the plans.

i. The Annual Incentive Compensation Program provides for an annual
incentive bonus that ties incentives to the annual return on the
Company's Common Stock and also a comparison of the price performance
of the Common Stock to the average annual return on the shares of stock
of a peer group of companies with which the Company competes and to the
growth in net earnings, net cash flow and net asset value of the
Company. Incentive bonuses are awarded to participants based upon
individual performance factors.

ii. The Nonemployee Directors' Stock Option Plan provides for the issuance
of up to 250,000 shares of Common Stock upon the exercise of such
options granted pursuant to such plan. Generally, options outstanding
under the Nonemployee Directors' Stock Option Plan: (a) are granted at
prices that equate to the fair market value of the Common Stock on date
of grant, (b) vest ratably over a three year service vesting period,
and (c) expire five years subsequent to award.

iii. The Company's Stock Option Plan provides for 850,000 shares of Common
Stock to be reserved for issuance pursuant to such plan. Under this
plan, the Company 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. All such options: (a) must have
an exercise price of not less than the fair market value of the Common
Stock on the date of grant, (b) vest ratably over a five year service
vesting period, and (c) expire ten years subsequent to award.

iv. The 401(k) Profit Sharing Plan provides eligible employees with the
option to defer receipt of a portion of their compensation and the
Company may, at its 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 the
Company's matching contributions (if any) for each year of service and
is fully vested upon five years of service with the Company. For the
years ended December 1996, 1995 and 1994, the Company contributed $169,
$168 and $134, respectively, to the plan.

In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which became effective with respect to the Company 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 ("APB25") method whereby no
compensation cost is recognized upon grant if certain requirements are met. The
Company is continuing to account for its stock-based compensation under APB 25.
However, pro forma disclosures as if the Company adopted the cost recognition
requirements under SFAS No. 123 are presented below.

F-17

<PAGE> 43

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 10--EMPLOYEE BENEFIT PLANS: (Continued)

If the compensation cost for the Company's 1996 and 1995 grants for
stock-based compensation plans had been determined consistent with SFAS No. 123,
the Company's net income and earnings per common share for the years ended
December 31, 1996 and 1995 would have approximated the pro forma amounts below:

DECEMBER 31,
-----------------------------------------------------------------------
1996 1995
-------------------------------- ---------------------------------
AS REPORTED PRO FORMA AS REPORTED PRO FORMA
---------------- ------------- ---------------- --------------
<S> <C> <C> <C> <C>
Net income $11,033 $10,639 $5,816 $5,749
Earnings per common share:
Primary $0.89 $0.86 $0.49 $0.49
Fully-diluted $0.88 $0.85 $0.49 $0.49
</TABLE>

The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to grants prior to
1995, and additional awards in the future are anticipated.

A summary of the Company's stock options as of December 31, 1996 and 1995
and changes during the years ended on those dates is presented below:
<TABLE>
<CAPTION>

DECEMBER 31,
-----------------------------------------------------------------------------------------
1996 1995 1994
---------------------------- ---------------------------- ---------------------------
WGTD. WGTD. WGTD.
NUMBER AVG. NUMBER AVG. NUMBER AVG.
OF EXER. OF EXER. OF EXER.
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
------------ ---------- ------------ ---------- ------------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 420,000 $12.33 248,000 $12.24 195,000 $12.37
Granted 317,000 20.27 195,000 12.45 55,000 11.80
Expired -- -- (18,000) 12.38 -- --
Exercised (2,000) 12.38 (5,000) 12.38 (2,000) 12.38
------------ ------------ -------------

Outstanding at end of year 735,000 $15.76 420,000 $12.33 248,000 $12.24
Options exercisable at year-end 180,667 $12.29 86,997 $12.23 37,665 $12.36
Options available for future grant 338,000 655,000 850,000
Weighted average fair value of
options granted during the year $12.95 $7.83
</TABLE>

The fair value of each option granted during the periods presented is
estimated on the date of grant using the Black- Scholes option-pricing model
with the following assumptions: (a) dividend yield of 0%, (b) expected
volatility of 42.83% and 46.86% in the years 1996 and 1995, respectively, (c)
risk-free interest rate of 6.41% and 5.55% in the years 1996 and 1995,
respectively, and (d) expected life of 10 years for employee options and five
years for director options.

F-18

<PAGE> 44

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 10--EMPLOYEE BENEFIT PLANS: (Continued)

The following table summarizes information about stock options outstanding
at December 31, 1996:

OPTIONS OUTSTANDING OPTIONS EXERCISABLE
--------------------------------------------------------- ----------------------------------
RANGE OF NUMBER WGTD. AVG. WGTD. AVG. NUMBER WGTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/96 CONTRACTUAL LIFE PRICE AT 12/31/96 PRICE
-------- ----------- ---------------- ---------- ----------- ----------
<S> <C> <C> <C> <C> <C>
$11-$15 418,000 9.0 $12.33 180,667 $12.29
15- 19 25,000 5.0 17.81
19- 24 292,000 10.0 20.48
----------------- ----------------
735,000 9.3 15.76 180,667 12.29
================= ================
</TABLE>

F-19

<PAGE> 45

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 11--OIL AND GAS RESERVE INFORMATION - UNAUDITED:

A majority of the Company's net proved oil and gas reserves at December 31,
1996 has been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions at the respective dates.

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

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

NATURAL
OIL IN GAS
MBBLS IN MMCF
---------------- -------------
<S> <C> <C>
Proved reserves as of December 31, 1993............................... 6,080 58,491
Revisions of previous estimates................................... (50) (7,579)
Extensions, discoveries and other additions....................... 1,454 14,877
Purchase of producing properties.................................. 235 11,304
Sale of reserves.................................................. (151) (2,179)
Production........................................................ (1,113) (6,629)
---------------- -------------
Proved reserves as of December 31, 1994............................... 6,455 68,285
Revisions of previous estimates................................... 476 1,208
Extensions, discoveries and other additions....................... 399 13,478
Purchase of producing properties.................................. 2,054 6,607
Production........................................................ (1,399) (8,399)
---------------- -------------
Proved reserves as of December 31, 1995............................... 7,985 81,179
Revisions of previous estimates................................... (783) (4,025)
Extensions, discoveries and other additions....................... 5,526 37,175
Purchase of producing properties.................................. 1,400 41,318
Production........................................................ (1,356) (11,331)
---------------- -------------
Proved reserves as of December 31, 1996............................... 12,772 144,316
================ =============

Proved developed reserves:
as of December 31, 1994........................................... 5,840 52,215
================ =============
as of December 31, 1995........................................... 7,055 67,797
================ =============
as of December 31, 1996........................................... 9,260 109,628
================ =============
</TABLE>

F-20

<PAGE> 46

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 11--OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)

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. The oil, condensate and gas price structure utilized to
project future net cash flows reflects current prices at each year end and has
been escalated only where known and determinable price changes are provided by
contracts and law. 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.

Crude oil and natural gas prices have declined from year-end 1996 to
February 28, 1997. Accordingly, the discounted future net cash flows would be
reduced if the standardized measure was calculated at the latter date. As a
result of the continued volatility in oil and natural gas markets, future prices
received from oil, condensate and natural gas sales may be higher or lower than
current levels.

<TABLE>
<CAPTION>
STANDARDIZED MEASURE
DECEMBER 31,
--------------------------------------------------------
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Future cash flows................................................. $894,418 $347,796 $225,345
Future production and development costs........................... (187,715) (89,739) (80,339)
Future income taxes............................................... (198,637) (56,146) (26,629)

------------- ------------- -------------
Future net cash flows............................................. 508,066 201,911 118,377
10% annual discount............................................... (178,728) (57,121) (35,309)
------------- ------------- -------------
Standardized measure of discounted future net cash flows.......... $329,338 $144,790 $83,068
============= ============= =============
</TABLE>

CHANGES IN STANDARDIZED MEASURE
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1996 1995 1994
------------- ------------- -------------
<S> <C> <C> <C>
Standardized measure at beginning of year......................... $144,790 $83,068 $84,404
Sales and transfers of oil and gas produced, net of
production costs.............................................. (43,389) (28,897) (21,730)
Changes in price, net of future production costs.................. 81,428 39,592 (15,388)
Extensions and discoveries, net of future production
and development costs......................................... 156,804 25,927 24,318
Changes in estimated future development costs, net of
development costs incurred during the period.................. (13,214) 6,717 (95)
Revisions of quantity estimates................................... (19,372) 5,867 (7,745)
Accretion of discount............................................. 17,837 9,739 10,471
Net change in income taxes........................................ (80,443) (19,257) 5,986
Purchase of reserves in place..................................... 105,035 22,039 8,382
Sale of reserves in place......................................... -- -- (4,994)
Changes in production rates (timing) and other.................... (20,138) (5) (541)
------------- ------------- -------------
Standardized measure at end of year $329,338 $144,790 $83,068
============= ============= =============
</TABLE>

F-21

<PAGE> 47

STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

(DOLLAR AMOUNTS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)

NOTE 12--SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:

FULLY
PRIMARY DILUTED
NET EARNINGS EARNINGS
REVENUES EXPENSES INCOME PER SHARE PER SHARE
------------- ------------- -------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
1996
First Quarter.............. $15,093 $11,831 $3,262 $0.27 $0.27
Second Quarter............. 14,403 11,548 2,855 0.24 0.24
Third Quarter.............. 13,251 11,230 2,021 0.17 0.17
Fourth Quarter............. 15,218 12,323 2,895 0.21 0.20
------------- ------------- -------------- --------------- --------------
$57,965 $46,932 $11,033 $0.89 $0.88
============= ============= ============== =============== ==============
1995
First Quarter.............. $8,176 $7,340 $836 $0.07 $0.07
Second Quarter............. 10,278 8,693 1,585 0.13 0.13
Third Quarter.............. 10,656 9,060 1,596 0.14 0.14
Fourth Quarter............. 11,441 9,642 1,799 0.15 0.15
------------- ------------- -------------- --------------- --------------
$40,551 $34,735 $5,816 $0.49 $0.49
============= ============= ============== =============== ==============
</TABLE>

F-22

<PAGE> 48

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. Billion cubic feet of gas.

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

BOE. Barrels of oil equivalent, determined using the ratio of six Mcf of
natural gas to one Bbl of crude oil, condensate or natural gas liquids.

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.

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 whereunder 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 by the Company 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.

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.

MBOE. One thousand barrels of oil equivalent.

MBOE/d. One thousand barrels of oil equivalent per day.

Mcf. One thousand cubic feet of gas.

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

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

MMBOE. One million barrels of oil equivalent.

MMBtu. One million Btus.

G-1

<PAGE> 49

GLOSSARY OF CERTAIN INDUSTRY TERMS--(Continued)

Mmcf. One million cubic feet of gas.

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

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

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%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

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 costs of production.

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.

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

G-2

<PAGE> 50

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)).

+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)).

+10.4 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated
by reference to Exhibit 10.12 to the Registrant's
Registration Statement on Form S-1 (Registration No. 33-62362)).

+10.7 -- 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. 011-12074)) .

10.8 -- Term Loan Agreement, dated November 30, 1995, between the
Registrant and First National Bank of Commerce (incorporated
by reference to Exhibit 10.11 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1995
(File No. 011-12074)) .

21.1 -- Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1995).

*23.1 -- Consent of Arthur Andersen LLP

*23.2 -- Consent of Atwater Consultants, Ltd.

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

*27 -- Financial Data Schedule
------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.

<PAGE> 1

Exhibit 23.1

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS

As independent public accountants, we hereby consent to the incorporation by
reference of our report, dated February 28, 1997, on our audits of the
consolidated financial statements of Stone Energy Corporation as of December 31,
1995 and 1996 and for each of the three years in the period ended December 31,
1996 included in this Annual Report on Form 10-K for the year ended December 31,
1996, into the Company's previously filed Registration Statement on Form S-8
(Registration No.
33-67332).

ARTHUR ANDERSEN LLP

New Orleans, Louisiana
March 24, 1997

<PAGE> 1

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We do hereby consent to the use of our name in "Item 2. Properties" of
the Annual Report on Form 10-K of Stone Energy Corporation (the "Company") for
the year ended December 31, 1996 (the "Form 10-K"), and the incorporation by
reference of the Form 10-K into the Company's Registration Statement on Form S-8
(Registration No. 33-67332), and the incorporation by reference of the Form 10-K
into the Company's Registration Statement on Form S-3 (Registration No. 33-
72236).

ATWATER CONSULTANTS, LTD.

By: /s/ O.R. Carter
---------------------------------
O.R. Carter
Co-Chairman, Board of Directors

New Orleans, Louisiana
March 26, 1997

<PAGE> 1

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We do hereby consent to the use of our name in "Item 2. Properties" of
the Annual Report on Form 10-K of Stone Energy Corporation (the "Company") for
the year ended December 31, 1996 (the "Form 10-K"), the incorporation by
reference of the Form 10-K into the Company's Registration Statement on Form S-8
(Registration No. 33-67332), and the incorporation by reference of the Form 10-K
into the Company's Registration Statement on Form S-3 (Registration No.
33-72236).

Cawley, Gillespie & Associates, Inc.

By: /s/ Aaron Cawley
---------------------------------
Aaron Cawley, P.E.
Executive Vice President

Fort Worth, Texas
March 26, 1997

<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONSOLIDATED BALANCE SHEET OF STONE ENERGY CORPORATION ("COMPANY") AS OF
DECEMBER 31, 1996 AND THE RELATED CONSOLIDATED STATEMENT OF OPERATIONS FOR THE
YEAR ENDED DECEMBER 31, 1996 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS INCLUDED IN THE COMPANY'S ANNUAL REPORT ON FORM 10-K.
</LEGEND>
<MULTIPLIER> 1,000

<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<CASH> 9,864
<SECURITIES> 10,331
<RECEIVABLES> 12,466
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 33,225
<PP&E> 6,922
<DEPRECIATION> 2,137
<TOTAL-ASSETS> 209,406
<CURRENT-LIABILITIES> 26,542
<BONDS> 0
0
0
<COMMON> 150
<OTHER-SE> 144,291
<TOTAL-LIABILITY-AND-EQUITY> 209,406
<SALES> 55,839
<TOTAL-REVENUES> 57,965
<CGS> 0
<TOTAL-COSTS> 32,015
<OTHER-EXPENSES> 4,437
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 3,574
<INCOME-PRETAX> 17,939
<INCOME-TAX> 6,906
<INCOME-CONTINUING> 11,033
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 11,033
<EPS-PRIMARY> 0.89
<EPS-DILUTED> 0.88

</TABLE>