UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A
(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, 1998
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number: 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 $339,626,060 as of March 15, 1999 (based on
the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
As of March 15, 1999, the registrant had outstanding 15,080,408 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 11,
1999, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page No.
PART I
Item 1. Business........................................................ 1
Item 2. Properties...................................................... 10
Item 3. Legal Proceedings............................................... 13
Item 4. Submission of Matters to a Vote of Security Holders............. 13
Item 4A. Executive Officers of the Registrant............................ 14
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters...................................................... 15
Item 6. Selected Financial and Operating Data........................... 16
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations........................................ 17
Item 7A. Disclosures Regarding Market Risks.............................. 23
Item 8. Financial Statements and Supplementary Data..................... 23
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure......................................... 23
PART III
Item 10. Directors and Executive Officers of the Registrant.............. 23
Item 11. Executive Compensation.......................................... 23
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 23
Item 13. Certain Relationships and Related Transactions.................. 23
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K................................................ 23
Index to Financial Statements................................... F-1
Glossary of Certain Industry Terms.............................. G-1
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PART I
ITEM 1. BUSINESS
Overview
Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploration, development and operation of oil and gas
properties onshore and offshore in the Gulf Coast Basin. The Company and its
predecessors have been active in the Gulf Coast Basin since 1973, which gives
the Company extensive geophysical, technical and operational expertise in this
area. As of December 31, 1998, the Company had estimated proved reserves of
approximately 243.3 Bcf of natural gas and 18.5 MMBbls of oil, or an aggregate
of approximately 354.1 Bcfe, with a present value of estimated pre-tax future
net cash flows of $286.1 million (based upon year-end 1998 prices which include
hedges and a discount rate of 10%).
The Company's business strategy is to increase production, cash flow and
reserves through the acquisition and development of mature properties located in
the Gulf Coast Basin. The Company seeks properties that have an established
production history, proved undeveloped reserves and multiple prospective
reservoirs that provide significant development opportunities and an attractive
price due to low current production levels and properties in which the Company
would have 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. Through development
activities, the Company seeks 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 15, and serves as operator of 14 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, 1999, the Company
has budgeted exploration and development expenditures of $73.3 million which
includes plans to drill 20 new wells, conduct 23 workovers/recompletions on
existing wells and, depending upon the success of specific development
activities, install two new offshore production platforms. The Company's capital
expenditures for 1998 totaled $158.9 million, of which $14.0 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 15,080,408 shares outstanding at March 15,
1999. In September 1997, the Company completed an offering of $100 million
principal amount of its 8-3/4% Senior Subordinated Notes. 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."
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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. See "Risk Factors-Competition."
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 amounts 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 location, spacing, drilling, operation and production of
both oil and gas wells, determine the reasonable market demand for oil and gas,
and establish allowable rates of production. Such regulatory orders may limit
the number of wells or locations at which the Company can drill, or 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,
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, construction and safety specifications. 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. Lessees must also comply with detailed
MMS regulations governing the calculation of royalty payments and the valuation
of production and permitted costs deductions for that purpose. 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.
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
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
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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 under consideration proposals to modify the valuation procedures
for crude oil transactions. If adopted, these changes would decrease reliance on
crude oil posted prices and assign a value to crude oil intended to better
reflect market value. The Company cannot predict what action the MMS will take
on these matters, nor can it predict at this stage how the Company might be
affected by the adoption of such changes.
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, 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 recent price declines for natural gas may, in
part, reflect increased competition and more efficient gas transportation
resulting from Order No. 636. The courts have largely affirmed the significant
features of Order No. 636 and numerous related orders pertaining to the
individual pipelines, although certain appeals remain pending and the FERC
continues to review and modify its open access regulations. In particular, the
FERC has recently begun a broad review of its transportation regulations,
including how they operate in conjunction with state proposals for retail gas
market restructuring, whether to eliminate cost-of-service rates for short-term
transportation, whether to allocate all short-term capacity on the basis of
competitive auctions, and whether changes to its long-term transportation
policies may also be appropriate to avoid a market bias toward short-term
contracts.
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. To date, the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the OCSLA
with respect to interstate pipelines, on gatherers and other entities not
subject to the FERC's NGA jurisdiction. The FERC has the authority under the
OCSLA to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the OCS. One of the FERC's recently
initiated inquiries involves whether it should alter its regulation of pipelines
(including gathers) and services on the OCS. The Company cannot predict the
outcome of this inquiry or what effect, if any, it may have on the Company. If
the FERC were to apply Order No. 509
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to gatherers in the OCS, and eliminate the exemption of 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. 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.
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 an onshore facility,
pipeline or vessel, or the lessee or permittee of the area in which an offshore
facility is located. OPA assigns liability to each responsible party for oil
cleanup costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75 million in other damages. Few defenses exist
to the liability imposed by OPA.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties for offshore facilities in federal OCS
waters to provide financial assurance in the amount of $35 million to cover
potential OPA liabilities. On August 11, 1998, the MMS promulgated a final rule
implementing the financial responsibility requirements set forth under the Coast
Guard Authorization Act of 1996. 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 based on specific risks posed by the operations or if the
worst case oil-spill discharge volume possible at the facility may exceed the
applicable threshold volumes specified under the MMS's final rule. The Company
does not anticipate that it will experience any difficulty in satisfying the
MMS's requirements for demonstrating financial responsibility under OPA.
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 transported
or disposed or arranged for the transport or disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources, and it is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
The EPA has indicated that the Company may be potentially responsible for
costs and liabilities associated with alleged releases of hazardous substances
at one site. See "Item 3. Legal Proceedings-Environmental."
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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
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.
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.
Production from the D platform at the Company's South Pelto Block 23 Field
accounted for approximately 31% of the Company's total oil and gas production
volumes during 1998. During late 1998, production commenced from two wells on
the E Platform at the South Pelto Block 23 Field both of which have multiple
recompletion opportunities. Production from this field accounted for
approximately 40% of the Company's total production during the first two months
of 1999.
Employees
At March 15, 1999, the Company had 103 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.
Forward-Looking Statements
Certain of the statements under this Item and elsewhere in this Form 10-K
are "forward-looking statements" within the meaning of Section 27A of the
Securities Act and Section 21E of the Securities Exchange Act of 1934, as
amended (the "Exchange Act"). All statements other than statements of historical
facts included in this Form 10-K, including without limitation statements under
"Item 1. Business", "Item 2. Properties" and "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations" regarding
budgeted capital expenditures, increases in oil and gas production, the
assessment of the Company's Year 2000 compliance, the Company's outlook on oil
and gas prices, the Company's financial position, oil and gas reserve estimates,
business strategy and other plans and objectives for future operations, are
forward-looking statements. Although the Company believes that the expectations
reflected in such forward-looking statements are reasonable, it can give no
assurance that such expectations will prove to have been correct. There are
numerous uncertainties inherent in estimating quantities of proved oil and
natural gas reserves and in
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projecting future rates of production and timing of development expenditures,
including many factors beyond the control of the Company. Reserve engineering is
a subjective process of estimating underground accumulations of oil and natural
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. As a result, estimates made by different
engineers often vary from one another. In addition, results of drilling, testing
and production subsequent to the date of an estimate may justify revisions of
such estimate and such revisions, if significant, would change the schedule of
any further production and development drilling. Accordingly, reserve estimates
are generally different from the quantities of oil and natural gas that are
ultimately recovered. Additional important factors that could cause actual
results to differ materially from the Company's expectations are disclosed under
"Risk Factors" and elsewhere in this Form 10-K. Should one or more of these
risks or uncertainties occur, or should underlying assumptions prove incorrect,
the Company's actual results and plans for 1999 and beyond could differ
materially from those expressed in forward-looking statements. All subsequent
written and oral forward-looking statements attributable to the Company or
persons acting on its behalf are expressly qualified in their entirety by such
factors.
Risk Factors
Volatility of Oil and Gas Prices; Marketability of Production. The Company's
revenue, profitability and future rate of growth are substantially dependent
upon the prevailing prices of, and demand for, oil and natural gas. As evidenced
by the decline in oil and natural gas prices since late 1997, prices for oil and
natural gas are volatile and are likely to continue to be subject to wide
fluctuation in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond the control of the Company. These factors include the level of
consumer product demand, weather conditions, domestic and foreign governmental
regulations, the price and availability of alternative fuels, political
conditions in the Middle East, the foreign supply of oil and natural gas, the
price of oil and gas imports and overall economic conditions. From time to time,
oil and gas prices have been depressed by excess domestic and imported supplies.
It is impossible to predict future oil and natural gas price movements with any
certainty. Declines in oil and natural gas prices may adversely affect the
Company's financial condition, liquidity and results of operations and may
reduce the amount of the Company's oil and natural gas that can be produced
economically. Substantially all the Company's sales of oil and natural gas are
made in the spot market or pursuant to contracts based on spot market prices and
not pursuant to long-term fixed price contracts. Additionally, the Company may
have ceiling test write-downs when prices decline. See "-- Ceiling Test
Write-downs." With the objective of reducing price risk, the Company may from
time to time enter into hedging transactions with respect to a portion of its
expected future production. See "-- Risks of Hedging Transactions." There can be
no assurance that such hedging transactions will reduce risk or mitigate the
effect of any substantial or extended decline in oil or natural gas prices. Any
substantial or extended decline in the prices of or demand for oil or natural
gas would have a material adverse effect on the Company's financial condition
and results of operations.
In addition, the marketability of the Company's production depends upon the
availability and capacity of gas gathering systems, pipelines and processing
facilities. The unavailability or lack of capacity thereof could result in the
shut-in of producing wells or the delay or discontinuance of development plans
for properties. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand all
could adversely affect the Company's ability to produce and market its oil and
natural gas. If market factors were to change dramatically, the financial impact
on the Company could be substantial. The availability of markets and the
volatility of product prices are beyond the control of the Company and represent
a significant risk. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations."
Uncertainty of Estimates of Oil and Gas Reserves. This Form 10-K contains
estimates of the Company's proved oil and gas reserves and the estimated future
net revenues therefrom based upon the Company's own estimates or on Reserve
Reports (as defined below) that rely upon various assumptions, including
assumptions required by the Commission as to oil and gas prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds. The
process of estimating oil and gas reserves is complex, requiring significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. As a result, such
estimates are inherently imprecise. Actual future production, oil and gas
prices, revenues, taxes, development expenditures, operating expenses and
quantities of recoverable oil and gas reserves may vary substantially from those
estimated by the Company or contained in the Reserve Reports. Any significant
variance in these assumptions could materially affect the estimated quantity and
value of reserves set forth in this Form 10-K. The Company's properties may also
be susceptible to hydrocarbon drainage from production by other operators on
adjacent properties. In addition, the
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Company's proved reserves may be subject to downward or upward revision based
upon production history, results of future exploration and development,
prevailing oil and gas prices, mechanical difficulties, government regulation
and other factors, many of which are beyond the Company's control. Actual
production, revenues, taxes, development expenditures and operating expenses
with respect to the Company's reserves will likely vary from the estimates used,
and such variances may be material.
Approximately 17% of the Company's total proved reserves at December 31,
1998 were undeveloped, which are by their nature less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. The Company's reserve data assume that substantial capital
expenditures by the Company will be required to develop such reserves. Although
cost and reserve estimates attributable to the Company's oil and gas reserves
have been prepared in accordance with industry standards, no assurance can be
given that the estimated costs are accurate, that development will occur as
scheduled or that the results will be as estimated. See "Item 2. Properties --
Oil and Gas Reserves."
The present value of future net revenues referred to in this Form 10-K
should not be construed as the current market value of the estimated oil and gas
reserves attributable to the Company's properties. In accordance with applicable
requirements of the Commission, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. The decline in year-end oil and gas prices reduced the Company's present
value of future net revenues. Actual future net cash flows also will be affected
by increases in consumption by oil and gas purchasers and changes in
governmental regulations or taxation. The timing of actual future net cash flows
from proved reserves, and thus their actual present value, will be affected by
the timing of both the production and the incurrence of expenses in connection
with development and production of oil and gas properties. In addition, the 10%
discount factor, which is required by the Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most appropriate discount factor based on interest rates in effect from time to
time and risks associated with the Company or the oil and gas industry in
general.
Ceiling Test Write-downs. The Company reports its operations using the full
cost method of accounting for oil and gas properties. The Company capitalizes
the cost to acquire, explore for and develop oil and gas properties. Under full
cost accounting rules, the net capitalized costs of oil and gas properties may
not exceed a "ceiling limit" which is based upon the present value of estimated
future net cash flows from proved reserves, discounted at 10%, plus the lower of
cost or fair market value of unproved properties. If net capitalized costs of
oil and gas properties exceed the ceiling limit, the Company must charge the
excess to earnings. This is called a "ceiling test write-down." This charge does
not impact cash flow from operating activities, but does reduce the Company's
shareholders' equity. The risk that the Company will be required to write down
the carrying value of its oil and gas properties increases when oil and gas
prices are low or volatile. In addition, write-downs may occur if the Company
has substantial downward adjustments to its estimated proved reserves. The
recent significant declines in oil and gas prices increase the risk that the
Company may be required to record a ceiling test write-down. The Company
recorded an after-tax write-down of $57.4 million for the year ended December
31, 1998. See "-- Volatility of Oil and Gas Prices; Marketability of
Production." No assurance can be given that the Company will not experience
ceiling test write-downs in the future. See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations".
Liquidity. The Company has historically addressed its long-term liquidity
needs through the use of bank credit facilities, the issuance of debt and equity
securities and the use of cash provided by operating activities. The Company
continues to examine alternative sources of long-term capital such as bank
borrowings, the issuance of debt, the sale of common or preferred stock and
joint venture financing. The availability of these sources of capital will
depend upon a number of factors, some of which are beyond the Company's control.
These factors include general economic and financial market conditions, oil and
natural gas prices and the value and performance of the Company. The Company may
be unable to execute its operating strategy if it cannot obtain capital from
these sources.
Substantial Capital Requirements. The Company makes, and will continue to
make, substantial expenditures for the development, exploration, acquisition and
production of oil and gas reserves. The Company made capital expenditures of
$159 million in 1998, $149 million during 1997 and $79 million during 1996. The
Company plans to make capital expenditures of $73 million in 1999. Management
believes that the cash flow provided by operating activities and borrowings
under the bank credit facility will be sufficient to fund planned capital
expenditures during
7
<PAGE>
1999. However, if revenues or cash flows from operations decrease as a result of
lower oil and natural gas prices, operating difficulties or other factors, many
of which are beyond the control of the Company, the Company may be limited in
its ability to expend the capital necessary to undertake or complete its
drilling program, or it may be forced to raise additional debt or equity
proceeds to fund such expenditures. There can be no assurance that additional
debt or equity financing or cash generated by operations will be available to
meet these requirements. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
Need for Acquisition and Development of Additional Reserves. The Company's
future success, as is generally the case in the industry, depends upon its
ability to find, develop or acquire additional oil and gas reserves that are
economically recoverable. Unless the Company acquires additional properties
containing proved reserves or conducts successful development and exploitation
activities on properties it currently owns, the Company's proved reserves will
decline resulting in lower revenues and cash flow from operations. The
successful acquisition of producing properties requires an assessment of
recoverable reserves, future oil and gas prices and operating costs, potential
environmental and other liabilities, title issues and other factors. Such
assessments are necessarily inexact and their accuracy is inherently uncertain.
In addition, any such assessment will not reveal all existing or potential
problems, nor will it permit the Company to become sufficiently familiar with
the properties to assess fully their deficiencies and capabilities. As a result
of the decline in oil and gas prices, the number of properties available for
acquisition in the Gulf Coast Basin has increased from one year ago. The
increased availability of properties has resulted in a decrease in the prices
paid for properties. See "-- Competition and Markets" and "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The Company's strategy includes increasing its production and reserves by
the implementation of a carefully designed field-wide development plan that is
formulated prior to the acquisition of a property. There can be no assurance,
however, that the Company's development projects will result in significant
additional reserves or that the Company will have success drilling productive
wells at economically viable costs. Furthermore, while the Company's revenues
may increase if prevailing oil and gas prices increase, the Company's finding
costs for additional reserves could also increase. The Company's strategy
includes a significant increase in development activities and related capital
expenditures due to, among other things, its significant acquisitions in 1996
and 1997.
Drilling Risks; Operating Delays. Drilling involves numerous risks,
including the risk that no commercially productive oil or gas reservoirs will be
encountered. The cost of drilling and completing wells is often uncertain, and
drilling operations may be curtailed, delayed or canceled as a result of a
variety of factors, many of which are beyond the Company's control, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, weather conditions, and shortages or delays in
the delivery of equipment. The cost of and the demand for drilling rigs,
production equipment and related services are subject to fluctuations in the
prevailing prices of oil and natural gas. Therefore, as a result of the recent
decline in oil and natural gas prices, the cost of and the demand for these
items have declined significantly from 1997 levels. There can be no assurance as
to the success of the Company's future drilling activities. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations."
Operating Hazards. The oil and gas business involves a variety of operating
risks, including the risk of fire, explosions, blowouts, pipe failure,
abnormally pressured formations and environmental hazards such as oil spills,
gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which
could result in substantial losses to the Company due to injury or loss of life,
severe damage to or destruction of property, natural resources and equipment,
pollution or other environmental damage, clean-up responsibilities, regulatory
investigation and penalties, and suspension of operations. In addition to the
foregoing, the Company's offshore operations are subject to the additional
hazards of marine operations, such as capsizing, collision and adverse weather
and sea conditions. In accordance with customary industry practice, the Company
maintains insurance against some, but not all, of the risks described above.
There can be no assurance that any insurance obtained by the Company will be
adequate to cover any losses or liabilities. The Company cannot predict the
continued availability of insurance or the availability of insurance at premium
levels that justify its purchase.
Compliance with Governmental Regulations. Oil and gas operations are subject
to various federal, state and local governmental regulations which may be
changed from time to time in response to economic or political conditions.
Matters subject to regulation include discharge permits for drilling operations,
drilling and abandonment bonds or other financial responsibility requirements,
reports concerning operations, the spacing of wells, unitization and pooling of
8
<PAGE>
properties and taxation. From time to time, regulatory agencies have imposed
price controls and limitations on production by restricting the rate of flow of
oil and gas wells below actual production capacity in order to conserve supplies
of oil and gas. The production, handling, storage, transportation and disposal
of oil and gas, by-products thereof and other substances and materials produced
or used in connection with oil and gas operations are subject to regulation
under federal, state and local laws and regulations primarily relating to
protection of human health and the environment. See "--Regulation" and "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Regulatory and Litigation
Issues."
Effects of Leverage. As of December 31, 1998, the Company's long-term debt
totaled $209.9 million and the Company had $3.6 million of additional available
borrowing capacity under its bank credit facility. The borrowing base limitation
on the Company's credit facility is periodically re-determined. Upon
re-determination, the Company could be forced to repay a portion of its bank
debt. There is no assurance that the Company will have sufficient funds to make
such repayments. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
The Company's level of indebtedness will have several important effects on
its operations, including (i) a substantial portion of the Company's cash flow
from operations will be dedicated to the payment of interest on its indebtedness
and will not be available for other purposes, (ii) the covenants contained in
its indenture and the bank credit facility limit its ability to borrow
additional funds or to dispose of assets and may affect the Company's
flexibility in planning for, and reacting to, changes in business conditions,
(iii) the Company's ability to obtain additional financing in the future for
working capital, capital expenditures (including acquisitions), general
corporate purposes or other purposes may be impaired, (iv) the Company's
leveraged financial position may make the Company more vulnerable to economic
downturns and may limit its ability to withstand competitive pressures, (v) to
the extent that the Company incurs any indebtedness under the bank credit
facility, which indebtedness will be at variable rates, the Company may be
vulnerable to increases in interest rates and (vi) the Company's flexibility in
planning for or reacting to changes in market conditions may be limited.
Moreover, future acquisition or development activities may require the Company
to alter its capitalization significantly. These changes in capitalization may
significantly increase the leverage of the Company. The Company's ability to
meet its debt service obligations and to reduce its total indebtedness will be
dependent upon the Company's future performance, which will be subject to
general economic conditions and to financial, business and other factors
affecting the operations of the Company, many of which are beyond its control.
If the Company is unable to generate sufficient cash flow from operations in the
future to service its indebtedness and to meet its other commitments, the
Company will be required to adopt one or more alternatives, such as refinancing
or restructuring its indebtedness, selling material assets or operations or
seeking to raise additional debt or equity capital. There can be no assurance
that any of these actions could be effected on a timely basis or on satisfactory
terms or that these actions would enable the Company to continue to satisfy its
capital requirements. The terms of the Company's indebtedness, including the
bank credit facility and the indenture, also may prohibit the Company from
taking such actions. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
Reliance on Key Personnel. The Company's operations are dependent upon a
relatively small group of key management and technical personnel. There can be
no assurance that such individuals will remain with the Company for the
immediate or foreseeable future. The unexpected loss of the services of one or
more of these individuals could have a detrimental effect on the Company. See
"Item 4A. Executive Officers of the Registrant."
Risks of Hedging Transactions. In order to manage its exposure to price
risks in the marketing of its oil and gas, the Company has in the past and
expects to continue to enter into oil and gas price hedging arrangements with
respect to a portion of its expected production. The Company's hedging policy
provides that, without the prior approval of the Board of Directors, generally
not more than 50% of its production quantities can be hedged, and that any such
hedges shall not be longer than one year in duration. These arrangements may
include futures contracts on the New York Mercantile Exchange ("NYMEX"). While
intended to reduce the effects of volatile oil and gas prices, such transactions
may limit potential gains by the Company if oil and gas prices were to rise
substantially over the price established by the hedge. In addition, such
transactions may expose the Company to the risk of financial loss in certain
circumstances, including instances in which (i) production is less than
expected, (ii) there is a widening of price differentials between delivery
points for the Company's production and the delivery point assumed in the hedge
arrangement, (iii) the counterparties to the Company's future contracts fail to
perform the contract or (iv) a sudden, unexpected event materially impacts oil
or gas prices. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources."
9
<PAGE>
Conflicts of Interest. James H. Stone, the Company's Chairman of the Board
and Chief Executive Officer, and Joe R. Klutts, the Company's Vice Chairman of
the Board, collectively own 9% of the working interest in the Weeks Island
Field. These interests were acquired at the same time as the Company's
predecessor acquired its interest in the Weeks Island Field. In their capacity
as working interest owners, they are required to pay their proportional share of
all costs and are entitled to receive their proportional share of revenues. In
addition, certain officers of the Company were granted net profits interests in
certain of the oil and gas properties of the Company acquired prior to the
Company's initial public offering in 1993. The recipients of the net profits
interests are not required to pay capital costs incurred on the properties
burdened by such interests. Therefore, a conflict of interest may exist between
the Company and such employees and officers with respect to the drilling of
additional wells or other development operations. The Company and James H. Stone
also continue to manage programs formed prior to 1993, and James H. Stone
continues to individually participate in various oil and gas operations and
ventures. It is possible, as a result of these activities, that conflicts of
interest could arise.
Control by Management. Executive officers and directors of the Company
beneficially own approximately 26% of the outstanding Common Stock of the
Company (the "Common Stock"). This percentage ownership is based on the number
of shares of Common Stock outstanding at March 15, 1999 and the beneficial
ownership of such persons at such date. As a result, these persons may be in a
position to control the Company through their ability to determine the outcome
of elections of the Company's directors and certain other matters requiring the
vote or consent of the Company's stockholders.
Competition. The Company operates in a highly competitive environment. The
Company competes with major and independent oil and gas companies for the
acquisition of desirable oil and gas properties, as well as for the equipment
and labor required to develop and operate such properties. Many of these
competitors have financial, technical and other resources substantially greater
than those of the Company. See "Competition and Markets."
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, 1998 were attributable
to 15 properties, nine of which are in the Gulf of Mexico offshore Louisiana,
and six of which are onshore Louisiana. The Company currently manages four
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, 1998. Net revenue and net cash flow
amounts include the effects of hedging contracts. 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, 1998.
Using the information contained in the Reserve Reports, the average product
prices for all of the Company's properties were $10.68 per Bbl of oil and $1.93
per Mcf of gas. All product pricing and cost
10
<PAGE>
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).......................................... 15,242 3,234 18,476
Gas (MMcf)........................................... 200,973 42,297 243,270
Total oil and gas (MMcfe)............................ 292,425 61,701 354,126
Estimated future net revenues before
income taxes..................................... $555,396 $114,965 $670,361
Present value of estimated future
pre-tax net cash flows........................... $267,560 $18,538 $286,098
</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.
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).
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.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1998 1997 1996
--------------- ---------------- -------------
(In thousands)
<S> <C> <C> <C>
Acquisition costs.................................... $17,748 $43,791 $26,650
Development costs.................................... 54,889 43,762 24,090
Exploratory costs.................................... 81,765 57,770 26,339
--------------- ---------------- -------------
Subtotal........................................... 154,402 145,323 77,079
Capitalized general and administrative costs and
interest, net of fees and reimbursements........... 4,480 3,457 2,325
--------------- ---------------- -------------
Total costs incurred................................. $158,882 $148,780 $79,404
=============== ================ =============
</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, 1998.
Gross Net
------------- --------------
Productive Wells:
Oil (1)............................. 50.00 38.40
Gas (2).............................. 60.00 44.98
------------- --------------
Total............................ 110.00 83.38
============= ==============
Developed Acres:
Onshore Louisiana..................... 2,433.43 2,122.45
Offshore Louisiana.................... 9,170.31 6,303.17
------------- --------------
Total............................. 11,603.74 8,425.62
============= ==============
Undeveloped Acres (3):
Onshore Louisiana..................... 15,608.82 13,116.91
Offshore Louisiana.................... 52,296.94 36,642.77
------------- --------------
Total............................. 67,905.76 49,759.68
============= ==============
(1) 4 gross wells each have dual completions.
(2) 10 gross wells each have dual completions.
(3) Leases covering approximately 1% of the Company's undeveloped acreage
will expire in 1999, 1% in 2000, 8% in 2001, 0% in 2002 and 1% in 2003.
Leases covering the remainder of the Company's undeveloped gross acreage
(89%) are held by production.
Drilling Activity. The following table sets forth the Company's drilling
activity for the periods indicated.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------------------------------------
1998 1997 1996
------------------------- -------------------------- ---------------------------
Gross Net Gross Net Gross Net
<S> --------- --------- ---------- ---------- --------- -----------
Exploratory Wells: <C> <C> <C> <C> <C> <C>
Productive.................. 10.00 8.68 10.00 8.70 4.00 3.73
Nonproductive............... 4.00 3.35 - - 3.00 2.75
Development Wells:
Productive.................. 6.00 5.48 2.00 1.26 5.00 4.50
Nonproductive............... 1.00 0.98 - - 1.00 0.76
</TABLE>
11
<PAGE>
Title to Properties
The Company believes it has satisfactory title on substantially all of its
producing 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. Although the Company did not dispose of wastes or salt water at this
site, the EPA contends that transporters of salt water may have rinsed their
trucks' tanks at this site. By letter dated December 9, 1998, the EPA made
demand for approximately $4 million of cleanup costs on 23 of the PRP's,
including the Company, that had not previously settled with the EPA. Given the
number of PRP's at this site, management does not believe that any liability for
this site would materially adversely affect the financial condition of the
Company.
Other Proceedings
On March 5, 1999, the Company was served with a petition filed by Goodrich
Leasehold, L.L.C., in Civil Action No. 1999-06999, 333rd Judicial District
Court, Harris County, Texas, alleging that a 1985 mineral lease rather than a
1942 mineral lease covers approximately 8.421 productive acres in the West Weeks
Island Field, Iberia Parish, Louisiana. The Plaintiff seeks declaratory relief,
payment of an overriding royalty interest, and payment of an additional working
interest, said amounts to be determined at trial. The Company believes that
plaintiff's position is mistaken, and the Company intends to defend this matter.
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.
12
<PAGE>
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names and ages of
(as of March 15, 1999) 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
------ --- --------
James H. Stone......... 73 Chairman of the Board
and Chief Executive Officer
Joe R. Klutts.......... 64 Vice Chairman of the Board
D. Peter Canty......... 52 President, Chief Operating
Officer and Director
Michael L. Finch....... 43 Executive Vice President,
Chief Financial Officer
and Director
Phillip T. Lalande..... 49 Vice President - Engineering
James H. Prince........ 56 Vice President, Chief
Accounting Officer and
Controller
Andrew L. Gates, III... 51 Vice President - Legal,
Secretary and General
Counsel
E. J. Louviere......... 50 Vice President - Land
Craig L. Glassinger.... 51 Vice President - Acquisitions
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 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 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.
13
<PAGE>
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.
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 closing prices per share for the Common Stock.
High Low
------------- -------------
1997
First Quarter.................... $29 1/4 $22
Second Quarter................... 29 3/8 22 3/4
Third Quarter.................... 34 1/2 25 1/16
Fourth Quarter................... 37 28 9/16
1998
First Quarter.................... $39 3/8 $28 9/16
Second Quarter................... 40 3/16 31
Third Quarter.................... 36 5/16 20 1/16
Fourth Quarter................... 36 7/8 25 3/4
1999
First Quarter
(through March 15, 1999)....... $30 1/4 $22 3/4
On March 15, 1999, the last reported sales price on the New York Stock
Exchange Composite Tape was $29.75 per share. As of that date there were
approximately 179 holders of record of the Common Stock.
Dividend Restrictions
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 restrictions on the Company's present or future ability to pay
dividends are included in the provision of the Delaware General Corporation Law
and in certain restrictive provisions in the Indenture executed in connection
with the Company's 8-3/4% Senior Subordinated Notes due 2007. In addition, 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."
14
<PAGE>
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, 1998 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."
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------
1998 1997 1996 1995 1994
<S> ------- -------- ------- ------- -------
Statement of Operations Data:
Operating revenues: <C> <C> <C> <C> <C>
Oil production revenue............................... $38,527 $31,082 $27,788 $24,775 $18,482
Gas production revenue............................... 76,070 37,997 28,051 13,918 12,697
Other revenue........................................ 2,023 1,908 2,126 1,858 1,708
------- ------ ------ ------ ------
Total revenues..................................... 116,620 70,987 57,965 40,551 32,887
------- ------ ------ ------ ------
Expenses:
Normal lease operating expenses...................... 18,042 10,123 8,625 6,294 5,312
Major maintenance expenses........................... 1,278 1,844 427 446 1,834
Production taxes..................................... 2,083 2,215 3,399 3,057 2,303
Depreciation, depletion and amortization............. 68,187 28,739 19,564 15,719 11,569
Write-down of oil and gas properties................. 89,135 - - - -
Interest expense..................................... 12,950 4,916 3,574 2,191 982
General and administrative costs..................... 4,293 3,903 3,509 3,298 3,099
Incentive compensation plan.......................... 763 833 928 85 1,358
------- ------ ------ ------ ------
Total expenses..................................... 196,731 52,573 40,026 31,090 26,457
------- ------ ------ ------ ------
Net income (loss) before income taxes............ (80,111) 18,414 17,939 9,461 6,430
------- ------ ------ ------ ------
Income tax provision (benefit):
Current.............................................. - - 208 131 -
Deferred............................................. (28,480) 6,495 6,698 3,514 2,410
-------- ------ ------- ------ ------
Total income taxes................................. (28,480) 6,495 6,906 3,645 2,410
-------- ------ ------- ------ ------
Net income (loss)...................................... ($51,631) $11,919 $11,033 $5,816 $4,020
========= ======= ======= ====== ======
Earnings and dividends per common share:
Basic net income (loss) per common share ............ ($3.43) $0.79 $0.90 $0.49 $0.34
======= ===== ===== ===== =====
Diluted net income (loss) per common share .......... ($3.43) $0.78 $0.90 $0.49 $0.34
======= ===== ===== ===== =====
Cash dividends declared.............................. - - - - -
Cash Flow Data:
Net cash provided by operating
activities (before working capital changes).......... $77,211 $47,153 $37,295 $25,049 $17,911
Net cash provided by operating
activities........................................... 85,633 32,679 32,751 27,650 9,609
Balance Sheet Data (at end of period):
Working capital ....................................... $9,884 $8,328 $6,683 $5,379 $4,437
Oil and gas properties, net............................ 293,824 291,420 171,396 111,248 81,291
Total assets .......................................... 366,390 354,144 209,406 139,460 109,956
Long-term debt, less current portion................... 209,936 132,024 26,172 47,754 22,725
Stockholders' equity .................................. 105,332 156,637 144,441 66,927 61,045
</TABLE>
15
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in understanding the
Company's financial position and results of operations for each year of the
three-year period ended December 31, 1998. 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."
General
Stone Energy Corporation is an independent oil and gas company engaged in
the development, exploration, acquisition and operation of oil and gas
properties onshore and offshore in the Gulf Coast Basin. The Company and its
predecessors have been active in the Gulf Coast Basin since 1973, which gives
the Company extensive geophysical, technical and operational expertise in this
area. The Company's business strategy is to increase production, cash flow and
reserves through the acquisition and development of mature properties located in
the Gulf Coast Basin.
Operating Environment
The Company's revenue, profitability and future rate of growth are
substantially dependent upon the prevailing prices of, and demand for, oil and
natural gas. Beginning in late 1997 and continuing throughout 1998, the oil and
gas industry has experienced a trend of declines in natural gas and crude oil
prices. The decline in natural gas prices have been attributable to
milder-than-normal weather conditions resulting in excess domestic supplies,
while oil prices have declined because of higher world supplies coupled with an
anticipated decrease in demand resulting from the overall outlook of the global
economy.
Although the Company operates with relatively high margins, its capital
expenditures budget for 1999 has been adjusted in response to the current price
environment. Currently, the Company has budgeted capital expenditures totaling
$73.3 million for 1999. The Company believes that it will be able to finance its
budgeted 1999 operations with cash flow from operations and available borrowings
under its bank credit facility. However, decreases in product prices or
production rates below budgeted levels may require the Company to reduce its
1999 expenditures or secure additional sources of capital. Because a substantial
portion of the Company's acreage is held by production, a decision to curtail
the 1999 capital expenditures budget would not result in a loss of future
drilling opportunities on its properties.
The demand for drilling rigs and related products and services decreased
during 1998, and the current costs associated with these items are significantly
lower than the costs during the first half of 1998. The decline in the costs of
drilling-related products and services has partially offset the effect of lower
product prices and should enable the Company to complete its 1999 budgeted
operations and development activities with substantially less capital than would
have been required one year ago.
The decline in product prices has also resulted in an increase in the number
of properties available for acquisition in the Gulf Coast Basin. This trend
should provide the Company with greater opportunities to acquire properties that
fit its specific acquisition profile. The Company would have to seek additional
sources of capital or revise its 1999 budget to accommodate the additional costs
to finance any acquisitions during 1999.
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. Furthermore, because most of the factors that affect the prices that
the Company receives for its production are beyond its control, the Company's
marketing efforts are devoted to achieving the best price available in each
geographic location and entering into a limited amount of fixed price sales and
hedging transactions to take advantage of short-term prices it believes to be
attractive.
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<PAGE>
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."
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------
1998 1997 1996
<S> -------------- ------------- -------------
Production: <C> <C> <C>
Oil (MBbls)................................................... 2,876 1,585 1,356
Gas (MMcf).................................................... 33,281 14,183 11,331
Oil and gas (MMcfe)........................................... 50,537 23,693 19,467
Average sales prices:
Oil (per Bbl)................................................. $13.40 $19.61 $20.49
Gas (per Mcf)................................................. 2.29 2.68 2.48
Per Mcfe...................................................... 2.27 2.92 2.87
Average costs (per Mcfe):
Normal operating costs........................................ $0.36 $0.43 $0.44
General and administrative.................................... 0.08 0.16 0.18
Depreciation, depletion and amortization...................... 1.33 1.19 0.99
Reserves at December 31:
Oil (MBbls)................................................... 18,476 17,763 12,772
Gas (MMcf).................................................... 243,270 189,239 144,316
Oil and gas (MMcfe)........................................... 354,126 295,817 220,948
Present value of estimated pre-tax future
net cash flows (in thousands)............................... $286,098 $368,930 $443,361
</TABLE>
1998 Compared to 1997. The Company recognized a net loss for the year ended
December 31, 1998 totaling $51.6 million, or $3.43 per share, as compared to
1997 net income of $11.9 million, or $0.78 per share. The 1998 results include
an after-tax, non-cash ceiling test write-down of $57.4 million or $3.82 per
share.
During December 1997, the Company initiated production from the D Platform
at its South Pelto Block 23 Field. Production from this structure, together with
increases in production at a number of the Company's other fields, generated
record levels of production volumes during 1998. Production volumes during 1998
increased 113%, on a Mcfe basis, over the previous record 1997 production
levels. Production volumes of both oil and gas during 1998, compared to 1997,
rose 81% and 135%, respectively, totaling 2.9 MMBbls of oil and 33.3 Bcf of gas.
Despite a 22% decrease in the average received price per Mcfe, the Company's
growth in production volumes during 1998 resulted in oil and gas revenues rising
to $114.6 million, a 66% increase from 1997 oil and gas revenues of $69.1
million. The average prices received, net of the effects of hedging contracts,
for the Company's production during 1998 were $13.40 per barrel of oil and $2.29
per Mcf of gas, as compared to $19.61 per barrel and $2.68 per Mcf during 1997.
Normal operating costs increased during 1998 to $18.0 million compared to
$10.1 million in 1997. The increase was attributable to an increase in the
number of properties and significantly higher production rates. However, on a
unit basis, these costs declined 16% during 1998 to $0.36 per Mcfe from $0.43
per Mcfe in 1997.
Total depreciation, depletion and amortization ("DD&A") expense attributable
to oil and gas properties increased during 1998 because of higher production
rates, increased investment in the properties and lower quarter-end prices. DD&A
on oil and gas properties increased to $67.3 million or $1.33 per Mcfe in 1998
from $28.1 million or $1.19 per Mcfe in 1997.
The Company follows the full cost method of accounting for its oil and gas
properties. Securities and Exchange Commission regulations require that
companies using full cost accounting value their proved year-end reserves based
on oil and gas prices in effect at December 31. As a result of the low oil and
gas price environment at year-end 1998,
17
<PAGE>
during the fourth quarter the Company recognized a ceiling test write-down of
its oil and gas properties totaling $89.1 million, which on an after-tax basis
was $57.4 million. The Company anticipates that the write-down will provide a
positive impact on future earnings resulting from lower future unit depreciation
expense.
To finance a portion of its 1998 capital expenditures budget, the Company
increased its borrowings under its bank credit facility during 1998. As a result
of these borrowings and the bond offering closed in September 1997, interest
expense increased to $13.0 million during 1998, compared to $4.9 million in
1997. Because of the continued increase in the Company's level of operations
during 1998, general and administrative costs increased in total to $4.3
million. However, on a unit basis, general and administrative costs declined 50%
to $0.08 per Mcfe, compared with $0.16 per Mcfe in 1997.
At December 31, 1998, the Company's reserves totaled 354.1 Bcfe, a 20%
increase from December 31, 1997 reserves of 295.8 Bcfe. Oil reserves increased
to 18.5 MMBbls at the end of 1998 from 17.8 MMBbls at the beginning of the year,
and gas reserves grew to 243.3 Bcf at December 31, 1998 compared to 189.2 Bcf at
year-end 1997. As a result of the decline in oil and gas prices, the estimated
discounted cash flows from the Company's proved reserves declined 22% from 1997.
1997 Compared to 1996. Net income for the year ended December 31, 1997
totaled $11.9 million, an increase of 8.0% from 1996 net income of $11.0
million. However, because of the secondary public offering of the Company's
common stock in late-1996 which issued approximately 3.2 million shares, the
Company's earnings on a per share basis during 1997 declined to $0.78 per share,
compared to $0.90 per share during 1996.
During 1997, the Company implemented a significantly expanded capital
expenditures program. As a result of the success of this program, the Company
experienced a 22% increase in production volumes, on a Mcfe basis, over 1996
production levels. Production volumes of both oil and gas during 1997, compared
to 1996, rose 17% and 25%, respectively, totaling 1.6 MMBbls of oil and 14.2 Bcf
of gas. This growth in production volumes resulted in 1997 oil and gas revenues
rising to $69.1 million, a 24% increase from 1996 oil and gas revenues of $55.8
million. The average prices received for oil and gas during 1997 were $19.61 per
barrel and $2.68 per Mcf as compared to $20.49 per barrel and $2.48 per Mcf
during 1996.
Normal operating costs increased during 1997 to $10.1 million compared to
$8.6 million in 1996. The increase was attributable to property acquisitions,
higher production rates, as well as generally higher costs of services during
1997. However, on a unit basis, these costs declined during 1997 to $0.43 per
Mcfe from $0.44 per Mcfe in 1996.
Major maintenance expenses during 1997 totaled $1.8 million compared to $0.4
million during 1996. The increase was due to one major, non-recurring workover
project during 1997 which cost $1.2 million.
DD&A expense attributable to oil and gas properties increased during 1997
because of higher production rates and increased investment in the properties.
DD&A increased to $28.1 million or $1.19 per Mcfe in 1997 from $19.3 million or
$0.99 per Mcfe in 1996.
During 1997, the Company borrowed funds pursuant to its bank credit facility
and completed a $100 million public offering of its 8-3/4% Senior Subordinated
Notes to finance a portion of its 1997 capital expenditures program. As a
result, interest expense increased to $4.9 million during 1997 compared to $3.6
million in 1996. Because of the overall increase in the Company's operations
during 1997, general and administrative costs increased in total to $3.9
million. However, on a unit basis, general and administrative costs declined to
$0.16 per Mcfe, compared with $0.18 per Mcfe in 1996.
In addition to increasing production volumes, the 1997 capital expenditures
program also increased the Company's year-end 1997 reserve levels. At December
31, 1997, the Company's reserves totaled 295.8 Bcfe, a 34% increase from
December 31, 1996 reserves of 220.9 Bcfe. Oil reserves increased to 17.8 MMBbls
at the end of 1997 from 12.8 MMBbls at the beginning of the year, and gas
reserves grew to 189.2 Bcf at December 31, 1997 compared to 144.3 Bcf at
year-end 1996.
18
<PAGE>
Pre-tax income increased to $18.4 million in 1997 from $17.9 million in
1996. The 1997 tax provision, however, decreased to $6.5 million from $6.9
million in 1996 because of an adjustment to the Company's annual tax rate during
1997.
Liquidity and Capital Resources
Working Capital and Cash Flow. The increase in the Company's production
volumes during 1998 and 1997 has resulted in considerable growth in the cash
flow from the Company's operations. Net cash flow from operations before working
capital changes for 1998 was $77.2 million, which represents a 64% increase from
the 1997 amount of $47.2 million. On a per share basis, net cash flow from
operations before working capital changes was $5.12 per share in 1998 as
compared to $3.10 per share in 1997. Based upon the Company's outlook for 1999
product prices, production rates and drilling costs, the Company believes that
its cash flow from operations, combined with the available borrowings under its
bank credit facility and its working capital of $9.9 million at year-end 1998,
will be sufficient to fund its 1999 capital expenditures budget. However, a
further significant decline in product prices may require the Company to reduce
its 1999 capital expenditures budget or secure additional sources of capital.
During 1998, the Company invested $158.9 million in its oil and gas
properties, which included $4.5 million of net 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. As
a result of these investments, the Company's average net daily production rates
for the first two months of 1999 increased approximately 20% from the net daily
rates achieved during the twelve month period of 1998.
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
primary objective of these transactions is to reduce the Company's exposure to
future oil and gas price declines during the term of the hedge. 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.
During 1998, the Company realized a net gain from its hedging
transactions of $4.3 million. Swap contracts totaled 144 MBbls of oil and 9,580
BBtus of gas, which represented approximately 5% and 30%, respectively, of the
Company's oil and gas production for the year. As of March 15, 1999, the Company
had hedged gas prices for the applicable periods, quantities and average prices
as follows:
Gas
-------------------------------------
Volumes Price
Period (BBtus) ($/MMBtu)
--------------- ---------------
First quarter 1999................... 3,600 $2.535
Second quarter 1999.................. 3,640 2.195
Third quarter 1999................... 3,680 2.177
The Company's net loss from hedging transactions for 1997 was $0.6 million.
Swap contracts totaled 237.7 MBbls of oil and 4,395 BBtus of gas, which
represented 15% and 33%, respectively, of the Company's oil and gas production
for the year.
19
<PAGE>
Historical Financing Sources. Since the Company's Initial Public Offering in
July 1993, the Company has financed its activities primarily with both debt and
equity offering proceeds, cash flow from operations and borrowings under its
bank credit facility.
In November 1995, the Company executed a term loan agreement with Bank One
in the original principal amount of $3.3 million for the purchase of the
RiverStone office building, the majority 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,
as described below.
In September 1997, the Company completed an offering of $100 million
principal amount of its 8-3/4% Senior Subordinated Notes (the "Notes") due
September 15, 2007 with interest payable semiannually commencing March 15, 1998.
There are no sinking fund requirements on the Notes and they are redeemable at
the option of the Company, in whole or in part, at 104.375% of their principal
amount beginning September 15, 2002, and thereafter at prices declining annually
to 100% on and after September 15, 2005. Provisions of the Notes include,
without limitation, restrictions on liens, indebtedness, asset sales and other
restricted payments.
In March 1998, the Company and its bank group increased the Company's credit
facility to $150 million, increased the borrowing base under the revolving
credit loan (the "Revolver") from $55 million to $120 million and extended the
term of the Revolver by one year to July 30, 2001. Interest under the Revolver
is payable quarterly and at December 31, 1998, the weighted average interest
rate of the facility was 6.9% per annum, the total outstanding principal balance
was $107 million and letters of credit totaling $9.4 million had been issued
pursuant to the facility. The borrowing base limitation, which is re-determined
periodically, is based on a borrowing base amount established by the bank group
for the Company's oil and gas properties.
The Company's credit facility 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. The banks waived the Company's tangible net
worth requirement through December 31, 1999. Such covenants may result in the
limitation or prohibition of the payment of cash dividends by the Company.
Long-Term Financing. The Company's 1999 capital expenditures budget totals
$73.3 million. Initially, the development budget has been allocated to the
Company's existing property base and is expected to be funded by a combination
of cash flow from operations and borrowings 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. To finance future acquisitions or
development activities beyond its current plans, the Company may have to seek
additional sources of capital or revise its 1999 capital expenditures budget to
accommodate the additional costs. In addition to the public debt and equity
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. The Company is 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 one instance in
which the EPA has indicated that it believes that the Company is a PRP for the
cleanup of oil field waste facilities. Management does not 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 area wide 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 area wide 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 area wide pipeline bond of $0.3
million and area wide 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
20
<PAGE>
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.
Year 2000 Compliance. The Year 2000 ("Y2K") issue is the result of
computerized systems being written to store and process the year portion of
dates from and after January 1, 2000 without critical systems failure. During
1998, the Company's executive management and Board of Directors implemented a
program to identify, evaluate and address the Company's Y2K risks to ensure that
its Information Technology ("IT") Systems and Non-IT Systems will be Y2K
compliant. The Company, with the assistance of outside consultants, completed
the evaluation of its IT Systems for Y2K compliance during the first quarter of
1999. As a result, the Company's non-compliant IT Systems are currently being
replaced or modified to Y2K compliant systems.
Regarding the Company's Non-IT Systems, which primarily consist of systems
with embedded technology, the Company has completed its preliminary assessment
of all date-sensitive components. Based upon this assessment, the Company has
determined there will be minimal modification required to become Y2K compliant.
The Company will replace or modify all non-compliant Non-IT Systems as
necessary. Costs incurred as of December 31, 1998, and estimated remaining costs
related to Y2K compliance totals approximately $15,000. The Company does not
separately track internal payroll costs incurred for employees involved in the
Y2K compliance effort.
Based on preliminary risk assessments, the Company believes the most likely
Y2K related failure would be a temporary disruption in certain materials and
services provided by third parties, which would not be expected to have a
material adverse effect on the Company's financial condition or results of
operations. As part of its assessment of the Y2K risk associated with third
parties' systems, the Company has contacted its material suppliers and customers
to determine their level of Y2K compliance. The Company expects to complete its
assessment by the end of the second quarter of 1999. While the Company believes
that the probability of the occurance of a disruption is low, the Company will
develop specific contingency plans to address certain risk areas, as needed,
beginning in the second quarter of 1999. There can be no assurance that the
Company will not be materially adversely affected by Y2K problems or related
costs.
Forward-Looking Statements
Certain of the statements set forth under this Item and elsewhere in this
Form 10-K are forward-looking and are based upon assumptions and anticipated
results that are subject to numerous risks and uncertainties. See "Item 1.
Business --Forward Looking Statements" and " --Risk Factors."
Accounting Matters
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 $4.5 million, $3.5 million and
$2.3 million
21
<PAGE>
for the years ended December 31, 1998, 1997 and 1996, 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, 1998, the
Company had a deferred tax asset of $9.8 million which was calculated based on
management's determination that it is more likely than not 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 7A. DISCLOSURES REGARDING MARKET RISKS
The Company's revenues are derived from the sale of its crude oil and
natural gas production. From time to time, the Company has entered into hedging
transactions which lock in for specified periods the prices the Company will
receive for the production volumes to which the hedge relates. The hedges reduce
the Company's exposure on the hedged volumes to decreases in commodities prices
and limit the benefit the Company might otherwise have received from any
increases in commodities prices on the hedged volumes.
Based on projected annual sales volumes for 1999, a 10% decline in the
prices the Company receives for its crude oil and natural gas production would
have an approximate $9.4 million impact on the Company's annual revenues. The
hypothetical impact of the decline in oil and gas prices is net of the
incremental gain that would be realized upon a decline in prices by the gas
hedging contracts in place as of March 15, 1999.
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 11,
1999, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference. For information concerning Item 10, see Part I
- - Item 4A. Executive Officers of Registrant.
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-21 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 1998 and 1997
Consolidated Statement of Operations for the three years in the period ended
December 31, 1998
Consolidated Statement of Cash Flows for the three years in the period ended
December 31, 1998
22
<PAGE>
Consolidated Statement of Changes in Equity for the three years in the
period ended December 31, 1998
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules:
All schedules are omitted because the required information is inapplicable
or the information is presented in the Financial Statements or the notes
thereto.
3. Exhibits:
3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1 (Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on
Form S-1 (Registration No. 33-62362)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as
of October 15, 1998, between the Company and ChaseMellon
Shareholder Services, L.L.C., as Rights Agent (incorporated by
reference to Exhibit 4.1 to the Registrant's Registration
Statement on Form 8-A (Registration No. 001-12074)).
+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)).
10.6 -- Third Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and
NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997
(incorporated by reference to Exhibit 10.6 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 001-12074)).
+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)) .
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended
and Restated Effective as of May 15, 1997 (incorporated by
reference to Exhibit 10.9 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1997 (File No.
001-12074)).
23
<PAGE>
10.10 -- First Amendment and Restatement of the Third Amended and Restated
Credit Agreement between the Registrant, the financial
institutions named therein and NationsBank of Texas, N.A., as
Agent, dated as of March 31, 1998 (incorporated by reference to
Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q
for the quarter ended March 31, 1998 (File No. 001-12074)).
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 (File No. 011-12074 )).
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Amended 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 under Items 5 and 7
dated October 15, 1998 regarding the adoption of a Stockholder Rights
Plan and the Bylaw Amendments related thereto.
24
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act, as
amended, the Registrant has duly caused this Form 10-K/A to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Lafayette,
State of Louisiana, on the 29th day of March, 1999.
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/A
has been signed by the following persons in the capacities and on the dates
indicated.
Signature Title Date
--------------- ------------ --------
/s/ JAMES H. STONE Chief Executive Officer and March 29, 1999
-------------------------- Chairman of the Board
James H. Stone (Principal Executive Officer)
/s/ D. PETER CANTY President, Chief Operating March 29, 1999
-------------------------- Officer and Director
D. Peter Canty
/s/ MICHAEL L. FINCH Executive Vice President, Chief March 29, 1999
-------------------------- Financial Officer and Director
Michael L. Finch (Principal Financial Officer)
/s/ JAMES H. PRINCE Vice President, Chief Accounting March 29, 1999
-------------------------- Officer and Controller
James H. Prince (Principal Accounting Officer)
/s/ JOE R. KLUTTS Director and Vice Chairman of March 29, 1999
-------------------------- the Board
Joe R. Klutts
/s/ DAVID R. VOELKER Director March 29, 1999
--------------------------
David R. Voelker
/s/ JOHN P. LABORDE Director March 29, 1999
--------------------------
John P. Laborde
/s/ ROBERT A. BERNHARD Director March 29, 1999
--------------------------
Robert A. Bernhard
/s/ RAYMOND B. GARY Director March 29, 1999
--------------------------
Raymond B. Gary
/s/ B.J. DUPLANTIS Director March 29, 1999
--------------------------
B.J. Duplantis
25
<PAGE>
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants................................ F-2
Consolidated Balance Sheet of Stone Energy Corporation as of
December 31, 1998 and 1997........................................... F-3
Consolidated Statement of Operations of Stone Energy Corporation
for the years ended December 31, 1998, 1997 and 1996................. F-4
Consolidated Statement of Cash Flows of Stone Energy Corporation
for the years ended December 31, 1998, 1997 and 1996................. F-5
Consolidated Statement of Changes in Equity of Stone Energy Corporation
for the years ended December 31, 1998, 1997 and 1996................. F-6
Notes to Consolidated Financial Statements.............................. F-7
F-1
<PAGE>
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, 1998 and
1997, 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,
1998. 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, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 2, 1999
F-2
<PAGE>
<TABLE>
<CAPTION>
STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)
December 31,
-----------------------------------
ASSETS 1998 1997
------ ------------ ------------
<S>
Current assets: <C> <C>
Cash and cash equivalents...................................................... $10,550 $10,304
Marketable securities, at market............................................... 16,853 19,940
Accounts receivable............................................................ 26,486 22,202
Unbilled accounts receivable................................................... 317 529
Other current assets........................................................... 184 176
------------- -------------
Total current assets......................................................... 54,390 53,151
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $310,767 and $154,289, respectively.......................... 286,098 274,116
Unevaluated.................................................................... 7,726 17,304
Building and land, net of accumulated depreciation of $255 and
$166, respectively........................................................... 3,559 3,538
Fixed assets, net of accumulated depreciation of $2,013 and $2,131,
respectively................................................................. 1,336 1,089
Other assets, net of accumulated depreciation and amortization
of $791 and $411, respectively............................................... 3,460 4,946
Deferred tax asset................................................................. 9,821 -
------------- -------------
Total assets................................................................. $366,390 $354,144
============= =============
LIABILITIES AND STOCKHOLDERS' EQUITY
-----------------------------------------
Current liabilities:
Current portion of long-term loans............................................. $88 $81
Advance payments............................................................... 21 239
Accounts payable to vendors.................................................... 27,583 32,793
Undistributed oil and gas proceeds............................................. 11,579 6,447
Other accrued liabilities...................................................... 5,235 5,263
------------- -------------
Total current liabilities.................................................... 44,506 44,823
Long-term loans.................................................................... 209,936 132,024
Deferred tax liability............................................................. - 18,659
Other long-term liabilities........................................................ 6,616 2,001
------------- -------------
Total liabilities............................................................ 261,058 197,507
------------- -------------
Commitments and Contingencies (see Note 9)
Common Stock, $.01 par value; authorized 25,000,000 shares;
issued and outstanding 15,070,408 and 15,045,408 shares, respectively.......... 151 150
Paid-in capital.................................................................... 119,208 118,883
Retained earnings (deficit)........................................................ (14,027) 37,604
------------- -------------
Total stockholders' equity................................................... 105,332 156,637
------------- -------------
Total liabilities and stockholders' equity................................... $366,390 $354,144
============= =============
</TABLE>
The accompanying notes are an integral part of this
consolidated balance sheet.
F-3
<PAGE>
<TABLE>
<CAPTION>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
Year Ended December 31,
-----------------------------------------------------
1998 1997 1996
<S> ------------- ----------- -------------
Revenues: <C> <C> <C>
Oil and gas production............................................. $114,597 $69,079 $55,839
Overhead reimbursements and management fees........................ 634 531 814
Other income....................................................... 1,389 1,377 1,312
------------- ----------- -------------
Total revenues................................................... 116,620 70,987 57,965
------------- ----------- -------------
Expenses:
Normal lease operating expenses.................................... 18,042 10,123 8,625
Major maintenance expenses......................................... 1,278 1,844 427
Production taxes................................................... 2,083 2,215 3,399
Depreciation, depletion and amortization........................... 68,187 28,739 19,564
Write-down of oil and gas properties (see Note 1).................. 89,135 - -
Interest........................................................... 12,950 4,916 3,574
Salaries and other employee costs.................................. 2,697 2,329 2,062
Incentive compensation plan (see Note 10).......................... 763 833 928
General and administrative costs................................... 1,596 1,574 1,447
------------- ----------- -------------
Total expenses................................................... 196,731 52,573 40,026
------------- ----------- -------------
Net income (loss) before income taxes ................................. (80,111) 18,414 17,939
------------- ----------- -------------
Income tax provision (benefit):
Current............................................................ - - 208
Deferred........................................................... (28,480) 6,495 6,698
------------- ----------- -------------
Total income taxes............................................... (28,480) 6,495 6,906
------------- ----------- -------------
Net income (loss)...................................................... ($51,631) $11,919 $11,033
============= =========== =============
Earnings (loss) per common share (see Note 1):
Basic earnings (loss) per share.................................... ($3.43) $0.79 $0.90
============= =========== =============
Diluted earnings (loss) per share ................................. ($3.43) $0.78 $0.90
============= =========== =============
Average shares outstanding......................................... 15,066 15,024 12,208
============= =========== =============
Average shares outstanding assuming dilution....................... 15,066 15,230 12,300
============= =========== =============
</TABLE>
The accompanying notes are an integral part of this
consolidated statement.
F-4
<PAGE>
<TABLE>
<CAPTION>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)
Year Ended December 31,
----------------------------------------------------
1998 1997 1996
<S> -------------- ------------ ------------
Cash flows from operating activities: <C> <C> <C>
Net income (loss).................................................. ($51,631) $11,919 $11,033
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization...................... 68,187 28,739 19,564
Provision (benefit) for deferred income taxes................. (28,480) 6,495 6,698
Write-down of oil and gas properties.......................... 89,135 -- --
-------------- ------------ ------------
77,211 47,153 37,295
(Increase) decrease in marketable securities.................. 3,088 (9,609) (99)
Increase in accounts receivable............................... (4,072) (9,795) (5,600)
(Increase) decrease in other current assets................... (96) (116) 518
Increase in accrued liabilities............................... 4,887 3,133 777
Other......................................................... 4,615 1,913 (140)
-------------- ------------ ------------
Net cash provided by operating activities.............................. 85,633 32,679 32,751
-------------- ------------ ------------
Cash flows from investing activities:
Investment in oil and gas properties............................... (164,092) (133,638) (72,733)
Sale of reserves in place.......................................... 9 623 --
Building additions and renovations................................. (110) (235) (185)
(Increase) decrease in other assets................................ 722 (1,830) (743)
-------------- ------------ ------------
Net cash used in investing activities.................................. (163,471) (135,080) (73,661)
-------------- ------------ ------------
Cash flows from financing activities:
Proceeds from borrowings........................................... 89,000 112,000 49,000
Repayment of debt.................................................. (11,081) (106,143) (70,575)
Proceeds from issuance of 8-3/4% Notes............................. -- 100,000 --
Deferred financing costs........................................... (160) (3,293) (418)
Sale of common stock............................................... -- -- 66,446
Expenses from common stock offering................................ -- (111) --
Exercise of stock options.......................................... 325 388 35
-------------- ------------ ------------
Net cash provided by financing activities.............................. 78,084 102,841 44,488
-------------- ------------ ------------
Net increase in cash and cash equivalents.............................. 246 440 3,578
Cash and cash equivalents, beginning of year........................... 10,304 9,864 6,286
-------------- ------------ ------------
Cash and cash equivalents, end of year................................. $10,550 $10,304 $9,864
============== ============ ============
Supplemental disclosures of cash flow information: Cash paid during the year
for:
Interest (net of amount capitalized)............................. $12,745 $2,606 $3,672
Income taxes..................................................... -- 100 145
</TABLE>
The accompanying notes are an integral part of this
consolidated statement.
F-5
<PAGE>
<TABLE>
<CAPTION>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Dollar amounts in thousands)
Retained
Common Paid-In Earnings
Stock Capital (Deficit)
------------------ ------------------ ------------------
<S> <C> <C> <C>
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
Net income......................................... -- -- 11,919
Expenses from common stock offering................ -- (111) --
Exercise of stock options.......................... -- 388 --
------------------ ------------------ ------------------
Balance, December 31, 1997........................... 150 118,883 37,604
Net loss .......................................... -- -- (51,631)
Exercise of stock options.......................... 1 325 --
------------------ ------------------ ------------------
Balance, December 31, 1998........................... $151 $119,208 ($14,027)
================== ================== ==================
</TABLE>
The accompanying notes are an integral part of this
consolidated statement.
F-6
<PAGE>
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, exploration,
development and operation of 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 15 properties that comprise its
asset base -nine offshore and six onshore Louisiana. The Company is
headquartered in Lafayette, Louisiana, with additional offices in New Orleans
and Houston.
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 interest in certain partnerships; The Stone Petroleum
Corporation ("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 were
transferred to the Company. TSPC was dissolved during 1997. All intercompany
balances and transactions are eliminated. Certain prior year amounts have been
reclassified to conform to current year presentation.
Use of Estimates:
The preparation of financial statements in conformity with 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 bank debt approximates book value at December 31, 1998. The fair
value of the Company's 8-3/4% Notes totaled $101,000 at December 31, 1998 and
the fair value of the Company's open hedging contract totaled $3,080 at December
31, 1998.
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 retains 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 in accordance with Statement of
Financial Accounting Standards No. 115 ("SFAS No. 115"). All realized and
unrealized gains and losses are included in current operating results. The net
unrealized gain on the portfolio for the year ended December 31, 1998 was
immaterial. The securities included in the portfolio are primarily U.S. Treasury
obligations and mortgage-backed securities with an average maturity of not more
than 360 days.
F-7
<PAGE>
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.
As required by the Securities and Exchange Commission, under the full cost
method of accounting the Company is required to periodically compare the present
value of the estimated net cash flow from its proved reserves (based on current
commodity prices) to the net capitalized costs of its proved oil and gas
properties. If the net capitalized costs of the Company's proved oil and gas
properties exceed the estimated discounted net cash flows from its proved
reserves, the Company is required to write-down the value of its oil and gas
properties to the value of the discounted cash flows. Due to the impact of low
year-end commodity prices on the Company's December 31, 1998 reserve values, the
Company recorded an $89.1 million reduction in the carrying value of its oil and
gas properties at December 31, 1998.
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. 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 $7,726 and $17,304 of unevaluated properties
and related costs that are not being amortized at December 31, 1998 and 1997,
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 Company
currently believes that the unevaluated properties at December 31, 1998 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, 1998 and 1997 was $606 and $144, respectively.
In March 1995, the Financial Accounting Standards Board ("FASB") issued 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 with no
material effect.
Building and Land:
The Company records building and land at cost. The Company's office building
is being depreciated on the straight-line method over its estimated useful life
of 39 years.
Other Assets:
Other assets at December 31, 1998 and 1997 includes approximately $3,453 and
$3,293, respectively, of deferred financing costs related to the sale of the
8-3/4% Notes (see Note 5). These costs are being amortized over the life of the
Notes using the effective interest method.
F-8
<PAGE>
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(Continued)
Earnings Per Common Share:
In February 1997, the FASB issued SFAS 128, "Earnings Per Share," which
simplifies the computation of earnings per share ("EPS"). The Company adopted
SFAS 128 in the fourth quarter of 1997 and restated prior years' EPS data as
required by SFAS 128. All EPS data in the financial statements and accompanying
footnotes reflects the adoption of SFAS 128.
Basic net income per share of common stock was calculated by dividing net
income applicable to common stock by the weighted-average number of common
shares outstanding during the year. Diluted net income per share of common stock
was calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the year plus the
weighted-average number of dilutive stock options granted to outside directors
and certain employees. There were no dilutive shares for the twelve month period
ending December 31, 1998, and dilutive shares totaled 206,000 shares and 92,000
shares during 1997 and 1996, respectively. There were 257,000 shares which were
considered antidilutive during 1998. Antidilutive options totaled 562 shares
during 1997 and there were no antidilutive options during 1996.
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.
Amounts related to net underdelivered production positions at December 31,
1998 and 1997 are immaterial.
Derivative Instruments and Hedging Activities:
From time to time, the Company utilizes futures and hedging activities in
order to reduce the effect of product price volatility. The resulting gains or
losses on hedging contracts are currently accounted for as revenues from oil and
gas production in the financial statements.
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.
New Accounting Standards:
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive Income"
and SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information." SFAS No. 130 establishes standards for the reporting and display
of comprehensive income in the financial statements. Comprehensive income is the
total of net income and all other nonowner changes in equity. For the years
ended December 31, 1998, 1997 and 1996, the Company's only component of
comprehensive income was net income. SFAS No. 131 requires that companies
disclose segment data based on how management makes decisions about allocating
resources to segments and measuring their performance. Because the Company
operates in a single industry within a single geographic location, the Company
does not have separately identifiable segments
F-9
<PAGE>
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
(Continued)
as defined under SFAS No. 131. SFAS Nos. 130 and 131 became effective and
were adopted by the Company during 1998 with no effect on the Company's
financial statements, financial position or results of operations.
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value and
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. The Company expects to adopt
SFAS No. 133 during the first quarter of 2000. Because of the nature of the
Company's only derivative instrument (see Note 7), the Company does not expect
that the adoption of SFAS No. 133 will have a material impact on the Company's
results of operations. However, the adoption may create volatility in equity
through changes in other comprehensive income.
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,
------------------------------------------
1998 1997
------------------ -----------------
Accounts Receivable:
Managed partnerships........... $1,882 $ 1,485
Other co-venturers............. 5,885 5,025
Trade.......................... 18,716 15,639
Officers and employees......... 3 53
------------------ -----------------
$26,486 $22,202
================== =================
Advance Payments:
Other co-venturers.............. $21 $239
================== =================
Costs incurred but not yet billed to the managed partnerships and other
co-venturers at December 31, 1998 and 1997 amounted to $317 and $529,
respectively.
F-10
<PAGE>
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,
----------------------------------------------------------
1998 1997 1996
<S> --------------- --------------- --------------
Oil and gas properties-- <C> <C> <C>
Balance, beginning of year................................... $445,709 $296,929 $217,525
Costs incurred during year:
Capitalized--
Acquisition costs........................................ 17,748 43,791 26,650
Exploratory drilling..................................... 81,765 57,770 26,339
Development drilling..................................... 54,889 43,762 24,090
General and administrative costs......................... 5,416 4,494 3,238
Less: overhead reimbursements............................ (936) (1,037) (913)
--------------- --------------- --------------
Total costs incurred during year......................... 158,882 148,780 79,404
--------------- --------------- --------------
Balance, end of year......................................... $604,591 $445,709 $296,929
=============== =============== ==============
Charged to expenses--
Operating costs:
Normal lease operating expenses.......................... $18,042 $10,123 $8,625
Major maintenance expenses............................... 1,278 1,844 427
--------------- --------------- --------------
Total operating costs.................................... 19,320 11,967 9,052
Production taxes......................................... 2,083 2,215 3,399
--------------- --------------- --------------
$21,403 $14,182 $12,451
=============== =============== ==============
Unevaluated oil and gas properties-- Costs incurred during year:
Acquisition costs........................................ $5,352 $5,395 $1,785
Exploration costs........................................ -- 11,020 --
Development costs........................................ 58 47 2,049
--------------- --------------- --------------
$5,410 $16,462 $3,834
=============== =============== ==============
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year............................... ($154,289) ($125,533) ($106,277)
Provision for depreciation, depletion and amortization... (67,334) (28,133) (19,256)
Write-down of oil and gas properties..................... (89,135) -- --
Sale of reserves......................................... (9) (623) --
--------------- --------------- --------------
Balance, end of year......................................... (310,767) (154,289) (125,533)
--------------- --------------- --------------
Net capitalized costs (proved and unevaluated)................... $293,824 $291,420 $171,396
=============== =============== ==============
DD&A per Mcfe.................................................... $1.33 $1.19 $0.99
=============== =============== ==============
</TABLE>
F-11
<PAGE>
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 asset (liability) follows:
December 31,
------------------------------
1998 1997
---------- ----------
Net operating loss carryforwards.......... $6,365 $3,658
Statutory depletion carryforward.......... 4,046 3,826
Investment tax credit carryforward........ - 158
Alternative minimum tax credit............ 396 396
Temporary differences:
Oil and gas properties--full cost... (359) (25,035)
Other............................... (627) (1,662)
---------- ----------
$9,821 ($18,659)
========== ==========
For tax reporting purposes, the Company had operating loss carryforwards
of $18,148 at December 31, 1998. If not utilized, such carryforwards would begin
expiring in 2001 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 $11,537 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.
The Company's provision for income taxes during 1997 decreased because of
an adjustment to the Company's annual tax rate. Reconciliations between the
statutory federal income tax expense rate and the Company's effective income tax
expense rate as a percentage of income before income taxes were as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------
1998 1997 1996
<S> ----------- ---------- ----------
Income taxes (benefit) computed at the statutory <C> <C> <C>
federal income tax rate....................................... (35%) 35% 35%
State tax and other............................................... -- -- 4
----------- ---------- ----------
Effective income tax rate......................................... (35%) 35% 39%
=========== ========== ==========
</TABLE>
F-12
<PAGE>
NOTE 5--LONG-TERM LOANS:
Long-term loans consisted of the following at:
<TABLE>
<CAPTION>
December 31,
-----------------------------------
1998 1997
-------------- -------------
<S> <C> <C>
8-3/4% Senior Subordinated Notes due 2007............................... $100,000 $100,000
Unsecured revolving credit facility with NationsBank
of Texas, N.A. ("NationsBank") (described below)........................ 107,000 29,000
Term Loan Agreement with Bank One with interest at 7.45%................ 3,024 3,105
Less: portion due within one year...................................... (88) (81)
-------------- -------------
Total long-term loans................................................... $209,936 $132,024
============== =============
</TABLE>
Aggregate minimum principal payments at December 31, 1998 for the next five
years are as follows: 1999-$88, 2000-$2,936, 2001-$107,000, 2002-$0 and
2003-$0.
In November 1995, the Company executed a term loan agreement with Bank One
in the original principal amount of $3,250 to finance the purchase of the
Company's office building. 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.
In September 1997, the Company completed an offering of $100,000 principal
amount of its 8-3/4% Senior Subordinated Notes (the "Notes") due September 15,
2007 with interest payable semiannually commencing March 15, 1998. At December
31, 1998, $2,601 had been accrued in connection with the March 1999 interest
payment. The Notes were sold at a discount for an aggregate price of $99,283 and
the net proceeds from the offering were used to repay amounts outstanding under
the Company's bank credit facility and for other general corporate purposes.
There are no sinking fund requirements on the Notes and they are redeemable at
the option of the Company, in whole or in part, at 104.375% of their principal
amount beginning September 15, 2002, and thereafter at prices declining annually
to 100% on and after September 15, 2005. Provisions of the Notes include,
without limitation, restrictions on liens, indebtedness, asset sales and other
restricted payments.
In March 1998, the Company and its bank group increased the Company's credit
facility to $150,000, increased the borrowing base under the Revolver from
$55,000 from $120,000 and extended the term of the Revolver by one year to July
30, 2001. Interest under the revolver is payable quarterly and at December 31,
1998, the weighted average interest rate of the facility was 6.9% per annum and
letters of credit totaling $9,383 had been issued pursuant to the facility. The
borrowing base limitation, which is re-determined periodically, is based on a
borrowing base amount established by the bank group for the Company's oil and
gas properties.
The terms of the NationsBank and Bank One agreements contain, among other
provisions, requirements for maintaining defined levels of working capital and
tangible net worth. The banks waived the Company's tangible net worth
requirement through December 31, 1999.
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, 1998, 1997 and
1996, the Company generated management fees and overhead reimbursements from
partnerships amounting to $1,095, $1,098 and $744, 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.
F-13
<PAGE>
NOTE 6--TRANSACTIONS WITH RELATED PARTIES: (Continued)
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 and their affiliates 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:
The Company engages in futures contracts with certain of its production
through master swap agreements ("Swap Agreements"). The Company considers these
futures contracts to be hedging activities and, as such, monthly settlements on
these contracts are reflected in revenues from oil and gas production. In order
to consider these futures contracts as hedges, (i) the Company must designate
the futures contract as a hedge of future production and (ii) the contract must
reduce the Company's exposure to the risk of changes in prices. Changes in the
market value of futures contracts treated as hedges are not recognized in income
until the hedged item is also recognized in income. If the above criteria are
not met, the Company will record the market value of the contract at the end of
each month and recognize a related gain or loss. Proceeds received or paid
relating to terminated contracts or contracts that have been sold are amortized
over the original contract period and reflected in revenues from oil and gas
production. The Company enters into hedging transactions for the purpose of
securing a price for a portion of future production that is acceptable at the
time the transaction is entered into. The primary objective of these activities
is to reduce the Company's exposure to the possibility of declining oil and gas
prices during the term of the hedge.
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 contract
prices and the average NYMEX closing prices for that month applied to the
related contract volumes. Settlement for gas swap contracts is based on the
average closing prices of either the last three days or last full month of
trading on the NYMEX for each month of the swap.
As of March 15, 1999, the Company's forward sales position was as follows:
Gas
--------------------------------------
Average
Price
BBtu ($/MMBtu)
------------- -----------------
1999...................... 10,920 $2.30
For the years ended December 31, 1998, 1997 and 1996, the Company realized
net oil and gas hedging gains (losses) of $4,265, ($569) and ($3,801),
respectively, which were included in 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, and the
remainder was used to repay a portion of the outstanding indebtedness under its
revolving bank credit facility.
F-14
<PAGE>
NOTE 8--COMMON STOCK: (Continued)
During the third quarter of 1998, the Company's Board of Directors
authorized the adoption of a stockholder rights plan to protect and advance the
interests of the Company and its stockholders in the event of a proposed
takeover. The plan provides for the issuance of one right for each outstanding
share of the Company's common stock. The rights will become exercisable only if
a person or group acquires 15% or more of the Company's outstanding voting stock
or announces a tender or exchange offer that would result in ownership of 15% or
more of the Company's voting stock. The rights were issued on October 26, 1998
to stockholders of record on that date, and expire on September 30, 2008.
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 April 4, 2003.
Additionally, the Company leases automobiles under terms of non-cancelable
leases expiring at various dates through 2000. The minimum net annual
commitments under all leases, subleases and contracts noted above at December
31, 1998 are as follows:
1999.................................................... $248
2000.................................................... 286
2001.................................................... 281
2002.................................................... 274
2003.................................................... 221
Thereafter.............................................. 68
Rent expense for the years ended December 31, 1998, 1997 and 1996 was
approximately $132, $118 and $114, respectively.
The Company is the managing general partner of four 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.
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. Given the number of PRP's at this site, management does not believe
that any liability for this site would materially adversely affect the financial
condition of the Company.
The Company is contingently liable to a surety insurance company in the
aggregate amount of $14,774 relative to bonds issued on its behalf to the MMS
and certain third parties from which it purchased oil and gas working interests.
The bonds represent guarantees by the surety insurance company that the Company
will operate offshore in accordance with MMS rules and regulations and perform
certain plugging and abandonment obligations as specified by the applicable
working interest purchase and sale contracts.
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.
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 to 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.
F-15
<PAGE>
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 was $3,288 at December 31, 1998, of which $1,975 is payable to
employees or their beneficiaries and $1,313 is payable to the Company. Total
cash surrender value of the policies, net of related surrender charges at
December 31, 1998, was approximately $1,054. Additionally, the benefits under
the deferred compensation agreements vest after certain periods of employment,
and at December 31, 1998, the liability for such vested benefits was
approximately $813. 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 directors 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 1993 Stock Option Plan (as amended and restated) provides
for 1,170,000 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 31, 1998, 1997 and 1996, the Company contributed
$270, $207 and $169, respectively, to the plan.
During the third quarter of 1998, the Company's Board of Directors elected
to reprice all non-Director employee stock options which had an exercise price
above the then market value of $26.00 per share. As a result, 265,000 stock
options, which were granted to non-Director employees during 1997 and 1998, were
repriced from a weighted average exercise price of $29.35 per share to the then
market value of $26.00 per share.
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 ("APB 25") 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-16
<PAGE>
NOTE 10--EMPLOYEE BENEFIT PLANS: (Continued)
If the compensation cost for the Company's 1998, 1997 and 1996 grants for
stock-based compensation plans had been determined consistent with SFAS No. 123,
the Company's 1998, 1997 and 1996 net income and basic and diluted earnings per
common share would have approximated the pro forma amounts below:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------------------------------
1998 1997 1996
---------------------------- ------------------------ ---------------------------
As Pro As Pro As Pro
Reported Forma Reported Forma Reported Forma
------------ ---------- ----------- -------- -------------- -------
<S> <C> <C> <C> <C> <C> <C>
Net income (loss)............... ($51,631) ($53,141) $11,919 $10,966 $11,033 $10,639
Earnings (loss) per
common share:
Basic..................... ($3.43) ($3.53) $0.79 $0.73 $0.90 $0.87
Diluted................... ($3.43) ($3.53) $0.78 $0.72 $0.90 $0.87
</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, 1998, 1997
and 1996 and changes during the years ended on those dates is presented below.
The table reflects the effects of the repricing of certain options granted
during 1997 and 1998.
<TABLE>
<CAPTION>
December 31,
-----------------------------------------------------------------------------------------------
1998 1997 1996
----------------------------- ---------------------------- -------------------------
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 950,000 $18.54 735,000 $15.76 420,000 $12.33
Granted 100,000 30.43 245,000 26.21 317,000 20.27
Expired -- -- -- -- -- --
Exercised (25,000) 13.00 (30,000) 12.95 (2,000) 12.38
------------- ------------ -------------
Outstanding at end of year 1,025,000 $19.84 950,000 $18.54 735,000 $15.76
Options exercisable at year-end 479,800 $15.97 309,400 $13.93 180,667 $12.29
Options available for future grant 331,000 413,000 338,000
Weighted average fair value of
options granted during the year $21.23 $17.05 $12.95
</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 43.90%, 41.20% and 42.83% in the years 1998, 1997 and 1996,
respectively, (c) risk-free interest rate of 5.50%, 6.04% and 6.41% in the years
1998, 1997 and 1996, respectively, and (d) expected life of 10 years for
employee options and five years for director options.
F-17
<PAGE>
NOTE 10--EMPLOYEE BENEFIT PLANS: (Continued)
The following table summarizes information regarding stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------------------- ----------------------------------
<S> <C> <C> <C> <C> <C>
Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/98 Contractual Life Price at 12/31/98 Price
------ ----------- ---------------- ----- ----------- ---------
$11 -$15 367,000 9.6 years $12.32 301,334 $12.39
17 - 21 293,000 9.6 years 20.10 118,133 20.03
22 - 26 290,000 10.0 years 25.78 52,000 25.51
27 - 37 75,000 6.7 years 32.61 8,333 28.06
----------------- ----------------
1,025,000 9.5 years 19.84 479,800 15.97
================= ================
</TABLE>
NOTE 11--OIL AND GAS RESERVE INFORMATION - UNAUDITED:
A majority of the Company's net proved oil and gas reserves at December
31, 1998 have been estimated by independent petroleum consultants in accordance
with guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the current market value of the Company's oil and gas
properties or the cost that would be incurred to obtain equivalent reserves.
F-18
<PAGE>
NOTE 11--OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
The following table sets forth an analysis of the Company's estimated
quantities of net proved and proved developed oil (including condensate) and
natural gas, all located onshore and offshore the continental United States:
<TABLE>
<CAPTION>
Natural
Oil in Gas in
MBbls MMcf
--------------- ---------------
<S> <C> <C>
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
Revisions of previous estimates........................................... 1,673 (12,252)
Extensions, discoveries and other additions............................... 2,675 45,276
Purchase of producing properties.......................................... 2,302 26,409
Sale of reserves.......................................................... (74) (327)
Production................................................................ (1,585) (14,183)
--------------- --------------
Proved reserves as of December 31, 1997....................................... 17,763 189,239
Revisions of previous estimates........................................... (1,001) 2,162
Extensions, discoveries and other additions............................... 4,353 70,936
Purchase of producing properties.......................................... 237 14,214
Production................................................................ (2,876) (33,281)
--------------- ---------------
Proved reserves as of December 31, 1998....................................... 18,476 243,270
=============== ===============
Proved developed reserves:
as of December 31, 1996................................................... 9,260 109,628
=============== ===============
as of December 31, 1997................................................... 14,485 141,424
=============== ===============
as of December 31, 1998................................................... 15,242 200,973
=============== ===============
</TABLE>
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.
F-19
<PAGE>
NOTE 11--OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
<TABLE>
<CAPTION>
Standardized Measure
December 31,
--------------------------------------------------------
1998 1997 1996
------------- ------------- -------------
<S> <C> <C> <C>
Future cash flows................................................. $670,361 $801,647 $894,418
Future production and development costs........................... (281,920) (268,641) (187,715)
Future income taxes............................................... (22,409) (104,521) (198,637)
------------- ------------- -------------
Future net cash flows............................................. 366,032 428,485 508,066
10% annual discount............................................... (97,584) (132,145) (178,728)
------------- ------------- -------------
Standardized measure of discounted future net cash flows.......... $268,448 $296,340 $329,338
============= ============= =============
Changes in Standardized Measure
Year Ended December 31,
--------------------------------------------------------
1998 1997 1996
------------- ------------- -------------
Standardized measure at beginning of year......................... $296,340 $329,338 $144,790
Sales and transfers of oil and gas produced, net of
production costs.............................................. (93,194) (54,898) (43,389)
Changes in price, net of future production costs.................. (156,107) (186,615) 81,428
Extensions and discoveries, net of future production
and development costs......................................... 111,828 87,491 156,804
Changes in estimated future development costs, net of
development costs incurred during the period.................. 22,923 26,738 (13,214)
Revisions of quantity estimates................................... (3,548) (3,502) (19,372)
Accretion of discount............................................. 36,863 32,934 17,837
Net change in income taxes........................................ 55,852 52,338 (80,443)
Purchase of reserves in place..................................... 10,321 21,725 105,035
Sale of reserves in place......................................... -- 420 --
Changes in production rates (timing) and other.................... (12,830) (9,629) (20,138)
------------- ------------- -------------
Standardized measure at end of year............................... $268,448 $296,340 $329,338
============= ============= =============
</TABLE>
F-20
<PAGE>
NOTE 12--SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
<TABLE>
<CAPTION>
Basic Diluted
Net Earnings (Loss) Earnings (Loss)
Revenues Expenses Income (Loss) Per Share Per Share
<S> ------------- --------------- ------------------ ------------------- ----------------
1998 <C> <C> <C> <C> <C>
First Quarter.......... $28,795 $25,497 $3,298 $0.22 $0.22
Second Quarter......... 28,474 26,642 1,832 0.12 0.12
Third Quarter.......... 27,412 26,667 745 0.05 0.05
Fourth Quarter ........ 31,939 89,445(a) (57,506)(a) (3.82)(a) (3.82)(a)
------------- --------------- ------------------ ------------------- ---------------
$116,620 $168,251 ($51,631) ($3.43) ($3.43)
============= =============== ================== =================== ===============
1997
First Quarter.......... $16,237 $12,641 $3,596 $0.24 $0.24
Second Quarter......... 13,662 12,065 1,597 0.11 0.11
Third Quarter.......... 15,958 13,463 2,495 0.17 0.16
Fourth Quarter......... 25,130 20,899 4,231 0.28 0.28
------------- --------------- ------------------ ------------------- -------------
$70,987 $59,068 $11,919 $0.79 $0.78
============= =============== ================== =================== =============
</TABLE>
(a) Includes a pre-tax, non-cash ceiling test write-down of $89,135.
F-21
<PAGE>
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
Bbtu. One billion Btus.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
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.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent. Determined using the
ratio of one barrel of crude oil to six mcf of natural gas.
Mcf/d. One thousand cubic feet of gas per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
G-1
<PAGE>
GLOSSARY OF CERTAIN INDUSTRY TERMS--(Continued)
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>
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 -- estated 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)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as
of October 15, 1998, between the Company and ChaseMellon
Shareholder Services, L.L.C., as Rights Agent (incorporated by
reference to Exhibit 4.1 to the Registrant's Registration
Statement on Form 8-A (Registration No. 001-12074)).
+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)).
10.6 -- Third Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and
NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997
(incorporated by reference to Exhibit 10.6 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No.001-12074)).
+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)) .
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended
and Restated Effective as of May 15, 1997 (incorporated by
reference to Exhibit 10.9 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1997 (File No.
001-12074)).
10.10 -- First Amendment and Restatement of the Third Amended and Restated
Credit Agreement between the Registrant, the financial
institutions named therein and NationsBank of Texas, N.A., as
Agent, dated as of March 31, 1998 (incorporated by reference to
Exhibit 10.1 to the Registrant's Quarterly Report on Form
10-Q for the quarter ended March 31, 1998 (File No. 001-12074)).
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 (File No. 011-12074 )).
G-3
<PAGE>
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Amended Financial Data Schedule
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
G-4
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation by
reference of our report, dated March 2, 1999, on our audits of the consolidated
financial statements of Stone Energy Corporation as of December 31, 1998 and
1997 and for each of the three years in the period ended December 31, 1998
included in this Annual Report on Form 10-K for the year ended December 31,
1998, into the Company's previously filed Registration Statement on Form S-8
(Registration No.33-67332).
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 24, 1999
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, 1998 (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 15, 1999
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, 1998 (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 15, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
consolidated balance sheet of Stone Energy Corporation as of December 31,
1998 and the related consolidated statement of operations for the year
ended December 31, 1998 and is qualified in its entirety by reference to
such financial statements included in Stone Energy Corporation's annual
report on Form 10-K.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> DEC-31-1998
<CASH> 10,550
<SECURITIES> 16,853
<RECEIVABLES> 26,486
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 54,390
<PP&E> 11,414
<DEPRECIATION> 3,059
<TOTAL-ASSETS> 366,390
<CURRENT-LIABILITIES> 44,506
<BONDS> 100,000
0
0
<COMMON> 151
<OTHER-SE> 105,181
<TOTAL-LIABILITY-AND-EQUITY> 366,390
<SALES> 114,597
<TOTAL-REVENUES> 116,620
<CGS> 0
<TOTAL-COSTS> 89,590
<OTHER-EXPENSES> 94,191
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,950
<INCOME-PRETAX> (80,111)
<INCOME-TAX> (28,480)
<INCOME-CONTINUING> (51,631)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (51,631)
<EPS-PRIMARY> (3.43)
<EPS-DILUTED> (3.43)
</TABLE>
