UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2000
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
State of incorporation: Delaware I.R.S. Employer Identification No. 72-1235413
625 E. Kaliste Saloom Road
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (337) 237-0410
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
[x] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $1,120,872,471 as of March 15, 2001 (based
on the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
As of March 15, 2001, the registrant had outstanding 25,981,827 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 17,
2001, 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................................................ 3
Item 2. Properties.............................................. 16
Item 3. Legal Proceedings....................................... 19
Item 4. Submission of Matters to a Vote of Security Holders..... 19
Item 4A. Executive Officers of the Registrant.................... 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................. 21
Item 6. Selected Financial Data................................. 22
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................ 23
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk.......................................... 29
Item 8. Financial Statements and Supplementary Data............. 31
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................. 31
PART III
Item 10. Directors and Executive Officers of the Registrant...... 31
Item 11. Executive Compensation.................................. 31
Item 12. Security Ownership of Certain Beneficial Owners
and Management....................................... 31
Item 13. Certain Relationships and Related Transactions.......... 31
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K............................................ 31
Index to Financial Statements.......................... F-1
Glossary of Certain Industry Terms..................... G-1
PART I
Where specifically indicated, throughout this document we show combined
operational and financial information to give effect to our merger with Basin
Exploration, which was consummated on February 1, 2001 and was accounted for as
a pooling of interests, as if the two companies were combined on January 1,
2000. These combined results should be used for information purposes only as
they are not necessarily indicative of the results that would have occurred if
the merger had been completed on January 1, 2000.
This section highlights information that is discussed in more detail in the
remainder of the document. Throughout this document we make statements that are
classified as "forward-looking". Please refer to the "Forward-Looking
Statements" section on page 9 of this document for an explanation of these types
of statements. We use the terms "Stone", "Stone Energy", "company", "we", "us"
and "our" to refer to Stone Energy Corporation. We use the terms "Basin" and
"Basin Exploration" to refer to Basin Exploration, Inc. The terms "merger" and
"combined company" are used to refer to the combination of Stone Energy and
Basin Exploration. Certain terms relating to the oil and gas industry are
defined in "Glossary of Certain Terms", which begins on page G-1 of this Form
10-K.
ITEM 1. BUSINESS
OPERATIONAL OVERVIEW
Stone Energy is an independent oil and gas company engaged in the
acquisition, exploration, development and operation of oil and gas properties
located onshore and in shallow waters offshore Louisiana. We have been active in
the Gulf Coast Basin since 1973 and have established extensive geophysical,
technical and operational expertise in this area. As of December 31, 2000, we
had estimated proved reserves of approximately 272.2 Bcf of natural gas and 21.3
MMBbls of oil, or an aggregate of approximately 400.2 Bcfe. As of December 31,
2000, the present value of estimated pre-tax net cash flows of our reserves was
$2 billion (based upon year-end 2000 prices and a discount rate of 10%).
Our business strategy is to increase production, cash flow and reserves
through the acquisition and development of mature properties located in the Gulf
Coast Basin, either onshore or in shallow waters offshore. As a result of the
successful and consistent application of this strategy, since our initial public
offering in 1993, we have increased production 502%, cash flow from operations
before working capital changes 1,014% and proved reserves 321%.
Since implementing our acquisition and exploitation strategy in 1990, we
have acquired interests in 21 producing fields and two primary term leases in
the Gulf Coast Basin, excluding the merger with Basin, from major and
independent oil and gas companies. At December 31, 2000, we served as operator
on all of these properties, which enables us to better control the timing and
cost of field rejuvenation activities. We believe that there will continue to be
numerous attractive opportunities to acquire properties in the Gulf Coast Basin
due to the increased focus by major and large independent companies on projects
in deeper waters and in foreign countries.
We seek to acquire properties that have the following characteristics:
o Gulf Coast Basin location;
o mature properties with an established production history and
infrastructure;
o multiple productive sands and reservoirs;
o low current production levels with significant identified proven and
potential reserve opportunities; and
o the opportunity for us to obtain a controlling interest and serve as
operator.
We believe significant reserves remain to be discovered on properties in the
shallow waters of the Gulf Coast Basin that satisfy our acquisition
characteristics. We also believe that we can exploit these reserves by applying
our technical expertise and patient approach in the evaluation and acquisition
of such properties.
Prior to acquiring a property, we perform a thorough geological, geophysical
and engineering analysis of the property to formulate a comprehensive
development plan. To formulate this plan, we utilize the expertise of our
technical team of 12 geologists, 7 geophysicists and 16 engineers. We also
employ our extensive technical database, which includes 3-D seismic data on all
of our current properties and some of the properties that we are evaluating for
acquisition. After acquisition, we seek to increase cash flow from existing
reserves and to establish additional proved reserves through the drilling of new
wells, workovers and recompletions of existing wells and the application of
other techniques designed to increase production. Our geographic focus,
state-of-the-art equipment and high level of operated properties have enabled us
to maintain low operating costs as evidenced by our per unit lease operating
expense of $0.41 per Mcfe in 2000.
FINANCIAL OVERVIEW
We completed our initial public offering of common stock in July 1993 and
our shares are listed on the New York Stock Exchange under the symbol "SGY".
Additional offerings of common stock were completed in November 1996 and July
1999.
In September 1997, we completed an offering of $100 million principal amount
of 8-3/4% Senior Subordinated Notes. These notes are due to mature in September
2007 and as of March 15, 2001 carried credit ratings by Moody's and Standard and
Poor's of B2 and B, respectively. We also have a $200 million revolving credit
agreement that as of December 31, 2000 had a borrowing base availability of
$192.5 million with no outstanding draws.
We have maintained consistent, profitable growth since our initial public
offering in 1993. We have generated net income in all calendar quarters except
the fourth quarter of 1998, which included a non-cash ceiling test write-down of
our oil and gas properties. The production increases discussed above combined
with our focus on maintaining low lease operating and general and administrative
costs on a per Mcfe basis have enabled us to increase EBITDA by 1,003% since
1993. Our per share net cash flow from operations has also grown 501% since 1993
and 75% over 1999.
MERGER WITH BASIN EXPLORATION
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination,
through a pooling of interests, of the two companies in a tax-free,
stock-for-stock transaction. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25 million to 100 million shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. As such, Stone issued
approximately 7.4 million shares of common stock which, based upon Stone's
closing price of $53.70 on February 1, 2001, resulted in total equity value
related to the transaction of approximately $400 million. In addition, Stone
assumed, and subsequently retired with cash on hand, approximately $48 million
of Basin bank debt. The expenses incurred in relation to the merger are
currently estimated to total $27 million and will be a non-recurring item
recorded in the first quarter of 2001.
The combined company, called Stone Energy Corporation, had a total market
capitalization of approximately $1.3 billion as of March 15, 2001. The following
table compares Stone's 2000 stand-alone results to the combined company's 2000
results assuming the merger had occurred on January 1, 2000. These combined
results should be used for information purposes only as they are not necessarily
indicative of the results that would have occurred if the merger had been
completed on January 1, 2000.
SELECTED COMPARATIVE FINANCIAL AND OPERATIONAL DATA
YEAR ENDED DECEMBER 31, 2000
-----------------------------------------------
STONE COMBINED
------------------ --------------------
(in thousands, except per share and per unit amounts)
FINANCIAL HIGHLIGHTS
Total Revenues................................... $260,379 $386,166
Net Income....................................... 84,945 127,973
Per Share..................................... 4.51 4.86
Net Cash Flow from Operations (1)................ 198,886 300,097
Per Share (1)................................. 10.57 11.40
Working Capital.................................. 53,421 53,065
Oil and Gas Properties, net...................... 444,631 747,573
Total Assets..................................... 602,431 944,103
Long-Term Debt................................... 100,000 148,000
Stockholders' Equity............................. 356,743 592,231
Weighted Average Shares Outstanding - Diluted.... 18,824 26,335
OPERATIONAL HIGHLIGHTS
Production:
Oil (MBbls)................................... 3,334 4,449
Gas (MMcf).................................... 46,480 72,239
Oil and Gas (MMcfe)........................... 66,484 98,933
Average Sales Prices (2):
Oil (per Bbl)................................. $25.82 $26.66
Gas (per Mcf)................................. 3.66 3.64
Oil and Gas (per Mcfe)........................ 3.86 3.86
Estimated Proved Reserves:
Oil (MBbls)................................... 21,319 33,625
Gas (MMcf).................................... 272,238 398,524
Oil and Gas (MMcfe)........................... 400,152 600,274
Present Value of Estimated Future
Pre-Tax Net Cash Flows ...................... $2,029,374 $2,941,790
(1) Before working capital changes.
(2) Includes the effects of hedging.
2001 OUTLOOK
The merger with Basin, which was effective February 1, 2001, increased our
property base to 79 producing properties by adding 25 Gulf Coast Basin and 33
Rocky Mountain properties. Our estimated 2001 capital expenditures budget of
approximately $253 million is expected to be allocated approximately 90% to Gulf
Coast operations and 10% to Rocky Mountain activities. The 2001 planned
investment in the Rockies represents over a 200% increase from the investments
made by Basin in the region during 2000. We expect to drill 77 gross wells
during 2001, 43 in the onshore and shallow water offshore regions of the Gulf
Coast Basin and 34 in the Rocky Mountains. Approximately 65% of the estimated
drilling costs are expected to be dedicated to exploratory targets with the
remaining 35% allocated to the development of existing reserves. While the 2001
capital expenditures budget does not include any projected acquisitions, we
continue to seek growth opportunities that fit our specific acquisition profile.
Based on our commodity price and production projections, we expect to
finance our 2001 capital expenditures budget with cash flows from operations.
Our production goal for 2001 is to increase production 15% over 2000's combined
production of 98.9 Bcfe.
OIL AND GAS MARKETING
Our oil, natural gas and natural gas condensate production is sold at
current market prices under short-term contracts providing for variable or
market sensitive prices. Since alternative purchasers of oil and gas are readily
available, we believe that the loss of any of our major purchasers would not
result in a material adverse effect on our ability to market future oil and gas
production. From time to time, we may enter into transactions that hedge the
price of oil, natural gas and natural gas condensate. See "Item 7A. Quantitative
and Qualitative Disclosures About Market Risk - Commodity Price Risk."
COMPETITION AND MARKETS
Competition in the Gulf Coast Basin and the Rocky Mountains is intense,
particularly with respect to the acquisition of producing properties and proved
undeveloped acreage. We compete with major oil companies and other independent
producers of varying sizes, all of which are engaged in the acquisition of
properties and the exploration and development of such properties. Many of our
competitors have financial resources and exploration and development budgets
that are substantially greater than ours, which may adversely affect our ability
to compete. See "Risk Factors - Competition within our industry may adversely
affect our operations."
The availability of a ready market for and the price of any hydrocarbons
produced will depend on many factors beyond our control, including but not
limited to the 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, 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 we conduct activities, there
are statutory provisions regulating the production of oil and natural gas under
which administrative agencies may enforce rules in connection with the location,
spacing, drilling, operation and production of both oil and gas wells, determine
the reasonable market demand for oil and gas and establish allowable rates of
production. These regulatory orders can limit the number of wells or the
location where wells may be drilled. Regulations can also restrict the rate of
production below the rate that these wells would otherwise produce in the
absence of such regulatory orders. Any of these actions could negatively impact
the amount or timing of revenues.
FEDERAL LEASES. We have oil and gas leases both onshore and in the Gulf of
Mexico which were granted by the federal government. Operations on onshore
federal leases must be conducted in accordance with permits issued by the Bureau
of Land Management and are subject to a number of other regulatory restrictions,
such as winter game restrictions and drilling limitations imposed by resource
management plans. Moreover, on certain federal leases, prior approval of
drillsite locations must be obtained from the Environmental Protection Agency
(the "EPA"). On large-scale projects, lessees may be required to perform
Environmental Impact Statements to assess the environmental effects of potential
development, which can delay project implementation or result in the imposition
of environmental restrictions that could have a material impact on the cost or
scope of such project.
Offshore leases are administered by the United States Department of the
Interior Minerals Management Service (the "MMS"). Offshore lessees must obtain
MMS approval of exploration, development and production plans prior to the
commencement of these operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the EPA),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS has enacted regulations requiring offshore production facilities located
on the Outer Continental Shelf ("OCS") to meet stringent engineering,
construction and safety specifications. The MMS also has regulations restricting
the flaring or venting of natural gas, and prohibiting the flaring of liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has enacted
other regulations governing the plugging and abandoning of wells located
offshore and the removal of all production facilities. Lessees must also comply
with detailed MMS regulations governing the calculation of royalty payments and
the valuation of production and permitted cost deductions for that purpose. In
2000, the MMS issued a final rule modifying the valuation procedures for the
calculation of royalties owed for crude oil sales. When oil production sales are
not in arms-length transactions, the new royalty calculation will base the
valuation of oil production on spot market prices instead of the posted prices
that were previously utilized. We are currently selling our crude oil under
arm's-length transactions in a manner that we believe to be acceptable to the
MMS under its new rule. As such, we believe that the effect, if any, of this new
rule will not have a material adverse effect on our results of operations.
With respect to any operations conducted on offshore federal leases,
liability may generally be imposed under the Outer Continental Shelf Lands Act
(the "OCSLA") for costs of clean-up and damages caused by pollution resulting
from these operations, other than damages caused by acts of war or the
negligence of third parties. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that these obligations will be met. The cost of bonds or
other surety can be substantial and there is no assurance that bonds or other
surety can be obtained in all cases.
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 were required to increase their
area-wide bonds and individual lease bonds to $3 million and $1 million,
respectively, unless the MMS allowed exemptions or reduced amounts. We currently
have an area-wide right-of-way bond for $0.3 million and an area-wide lessee's
and operator's bond totaling $3 million issued in favor of the MMS for our
existing offshore properties. The MMS also has discretionary authority to
require supplemental bonding in addition to the foregoing required bonding
amounts but this authority is only exercised on a case-by-case basis at the time
of filing an assignment of record title interest for MMS approval. Based upon
certain financial parameters, we have been granted exempt status by the MMS,
which exempts us from the supplemental bonding requirements. There is no
assurance, however, that such exemption will be maintained. Under certain
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition and operations.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids are not currently regulated and are made at negotiated prices.
Effective January 1, 1995, the Federal Energy Regulatory Commission (the "FERC")
implemented regulations establishing an indexing system for transportation rates
for oil that allowed for an increase in the cost of transporting oil to the
purchaser. The implementation of these regulations has not had a material
adverse effect on our results of operations.
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the
Natural Gas Policy Act of 1978 (the "NGPA") and regulations promulgated
thereunder by the FERC. In the past, the Federal government has regulated the
prices at which gas could be sold. While sales by producers of natural gas can
currently be made at uncontrolled market prices, Congress could reenact price
controls in the future. Deregulation of wellhead natural gas sales began with
the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA
price and non-price controls affecting wellhead sales of natural gas effective
January 1, 1993.
Commencing in 1992, the FERC issued Order No. 636 and subsequent orders
(collectively, "Order No. 636"), which require interstate pipelines to provide
transportation separate, or "unbundled," from the pipelines' sales of gas. Also,
Order No. 636 requires pipelines to provide open-access transportation on a
basis that is equal for all shippers. Although Order No. 636 does not directly
regulate our activities, the FERC has stated that it intends for Order No. 636
to foster increased competition within all phases of the natural gas industry.
The implementation of these orders has not had a material adverse effect on our
results of operations. The courts have largely affirmed the significant features
of Order No. 636 and numerous related orders pertaining to the individual
pipelines, although certain appeals remain pending and the FERC continues to
review and modify its open access regulations.
In 2000, the FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised the FERC pricing policy by waiving price ceilings for short-term
released capacity for a two year period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation, pipeline
penalties, rights of first refusal and information reporting. Most major aspects
of Order No. 637 are pending judicial review. We cannot predict whether and to
what extent FERC's market reforms will survive judicial review and, if so,
whether the FERC's actions will achieve the goal of increasing competition in
markets in which our natural gas is sold. However, we do not believe that we
will be affected by any action taken materially differently than other natural
gas producers and marketers with which we compete.
The OCSLA requires that all pipelines operating on or across the OCS provide
open-access, non-discriminatory service. Commencing in April 2000, the FERC
issued Order Nos. 639 and 639-A (collectively, "Order No. 639"), which imposed
certain reporting requirements applicable to "gas service providers" operating
on the OCS concerning their prices and other terms and conditions of service.
The purpose of Order No. 639 is to provide regulators and other interested
parties with sufficient information to detect and to remedy discriminatory
conduct by such service providers. The FERC has stated that these reporting
rules apply to OCS gatherers and has clarified that they may also apply to other
OCS service providers including platform operators performing dehydration,
compression, processing and related services for third parties. Judicial review
of Order No. 639 is currently pending. We cannot predict whether and to what
extent these regulations will survive such review, and what effect, if any, they
may have on us. The rules, if allowed to stand, may increase the frequency of
claims of discriminatory service, may decrease competition among OCS service
providers and may lessen the willingness of OCS gathering companies to provide
service on a discounted basis.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been 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. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas and impose substantial liabilities for
pollution resulting from our operations. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties or the imposition of injunctive relief. Changes in environmental laws
and regulations occur frequently, and any changes that result in more stringent
and costly waste handling, storage, transport, disposal or cleanup requirements
could materially adversely affect our operations and financial position, as well
as those of the oil and gas industry in general. While we believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements would not
have a material adverse impact on us, there is no assurance that this trend will
continue in the future.
The Oil Pollution Act, as amended ("OPA"), and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of an onshore
facility, pipeline or vessel, or the lessee or permittee of the area in which an
offshore facility is located. OPA assigns liability to each responsible party
for oil cleanup costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or to cooperate fully
in the cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75 million in other damages. Few defenses exist
to the liability imposed by OPA.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and a final rule adopted by the MMS in
August 1998, responsible parties of covered offshore facilities that have a
worst case oil spill of more than 1,000 barrels must demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in OCS waters, with higher amounts of up to $150
million in certain limited circumstances where the MMS believes such a level is
justified by the risks posed by the operations, or if the worst case oil-spill
discharge volume possible at the facility may exceed the applicable threshold
volumes specified under the MMS's final rule. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that are considered to be responsible for the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of the disposal site or sites where the release occurred and companies
that transported or disposed or arranged for the transport or disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. The EPA has indicated that
we may be potentially responsible for costs and liabilities associated with
alleged releases of hazardous substances at one site. See "Item 3. Legal
Proceedings-Environmental."
The Resource Conservation and Recovery Act, as amended ("RCRA"), generally
does not regulate most wastes generated by the exploration and production of oil
and gas. RCRA specifically excludes from the definition of hazardous waste
"drilling fluids, produced waters and other wastes associated with the
exploration, development or production of crude oil, natural gas or geothermal
energy." However, legislation has been proposed in Congress from time to time
that would reclassify certain oil and gas exploration and production wastes as
"hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on our operating costs,
as well as the oil and gas industry in general. Moreover, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils,
may be regulated as hazardous waste.
We currently own or lease, and have in the past owned or leased, onshore
properties that for many years have been used for or associated with the
exploration and production of oil and gas. Although we have utilized operating
and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us on or under other locations where such
wastes have been taken for disposal. In addition, most of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously disposed
wastes (including waste disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination by prior owners or
operators), or to perform remedial plugging or closure operations to prevent
future contamination.
The Federal Water Pollution Control Act, as amended ("FWPCA"), imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas 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 into coastal waters. Although the costs to
comply with zero discharge mandates under federal or state law may be
significant, the entire industry is expected to experience similar costs and we
believe that these costs will not have a material adverse impact on our results
of operations or financial position. The EPA has adopted regulations requiring
certain oil and gas exploration and production facilities to obtain permits for
storm water discharges. Costs may be associated with the treatment of wastewater
or developing and implementing storm water pollution prevention plans.
EMPLOYEES
At March 15, 2001, the combined company had 200 full time employees. We
believe that our relationships with our employees are satisfactory. None of our
employees are covered by a collective bargaining agreement. From time to time we
utilize the services of independent contractors to perform various field and
other services.
FORWARD-LOOKING STATEMENTS
This Form 10-K and the information incorporated by reference contain
statements that constitute "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Securities Exchange
Act. The words "expect", "project", "estimate", "believe", "anticipate",
"intend", "budget", "plan", "forecast", "predict" and other similar expressions
are intended to identify forward-looking statements. These statements appear in
a number of places and include statements regarding our plans, beliefs or
current expectations, including the plans, beliefs and expectations of our
officers and directors with respect to, among other things:
o earnings growth;
o budgeted capital expenditures;
o increases in oil and gas production;
o future project dates;
o our outlook on oil and gas prices;
o estimates of our oil and gas reserves;
o our future financial condition or results of operations; and
o our business strategy and other plans and objectives for future
operations.
When considering any forward-looking statement, you should keep in mind the
risk factors and other cautionary statements in this Form 10-K that could cause
our actual results to differ materially from those contained in any
forward-looking statement. Furthermore, the assumptions that support our
forward-looking statements are based upon information that is currently
available and is subject to change. We specifically disclaim all responsibility
to publicly update any information contained in a forward-looking statement or
any forward-looking statement in its entirety and therefore disclaim any
resulting liability for potentially related damages.
All forward-looking statements attributable to Stone Energy Corporation are
expressly qualified in their entirety by this cautionary statement.
RISK FACTORS
Our business is subject to a number of risks including, but not limited to,
those described below:
OIL AND GAS PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUES,
CASH FLOWS AND PROFITABILITY.
Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Factors
that can cause this fluctuation include:
o relatively minor changes in the supply of and demand for oil and
natural gas;
o market uncertainty;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
particularly those in the Middle East;
o the foreign supply of oil and natural gas;
o the price of oil and gas imports; and
o overall economic conditions.
We cannot predict future oil and natural gas prices. At various times,
excess domestic and imported supplies have depressed oil and gas prices.
Declines in oil and natural gas prices may adversely affect our financial
condition, liquidity and results of operations. Lower prices may reduce the
amount of oil and natural gas that we can produce economically and may also
create ceiling test write-downs of our oil and gas properties. Substantially all
of our oil and natural gas sales are made in the spot market or pursuant to
contracts based on spot market prices, not long-term fixed price contracts.
In an attempt to reduce our price risk, we periodically enter into hedging
transactions with respect to a portion of our expected future production. We
cannot assure you that such transactions will reduce the risk or minimize the
effect of any decline in oil or natural gas prices. Any substantial or extended
decline in the prices of or demand for oil or natural gas would have a material
adverse effect on our financial condition and results of operations.
THE MARKETABILITY OF STONE'S PRODUCTION DEPENDS MOSTLY UPON THE AVAILABILITY,
PROXIMITY AND CAPACITY OF GAS GATHERING SYSTEMS, PIPELINES AND PROCESSING
FACILITIES.
The marketability of our production depends upon the availability, operation
and capacity of gas gathering systems, pipelines and processing facilities. The
unavailability or lack of capacity of these systems and facilities could result
in the shut-in of producing wells or the delay or discontinuance of development
plans for properties. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand
could adversely affect our ability to produce and market our oil and natural
gas. If market factors changed dramatically, the financial impact on us could be
substantial. The availability of markets and the volatility of product prices
are beyond our control and represent a significant risk.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.
This Form 10-K contains estimates of our proved oil and gas reserves and the
estimated future net revenues from such reserves. These estimates are based upon
various assumptions, including assumptions required by the Securities and
Exchange Commission relating to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and gas reserves is complex. This process requires significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Therefore, these
estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth in this document and the information incorporated by reference. Our
properties may also be susceptible to hydrocarbon drainage from production by
other operators on adjacent properties. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond our control. Actual production, revenues, taxes, development expenditures
and operating expenses with respect to our reserves will likely vary from the
estimates used. Such variances may be material.
At December 31, 2000, approximately 19% of our estimated proved reserves
were undeveloped and approximately 23% of the combined company's estimated
proved reserves were undeveloped. Undeveloped reserves, by their nature, are
less certain. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve data assumes that
we will make significant capital expenditures to develop our reserves. Although
we have prepared estimates of our oil and gas reserves and the costs associated
with these reserves in accordance with industry standards, we cannot assure you
that the estimated costs are accurate, that development will occur as scheduled
or that the actual results will be as estimated.
You should not assume that the present value of future net revenues referred
to in this Form 10-K and the information incorporated by reference is the
current fair value of our estimated oil and gas reserves. In accordance with
Securities and Exchange Commission requirements, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs as
of the date of the estimate. Actual future prices and costs may be materially
higher or lower than the prices and costs as of the date of the estimate. Any
changes in consumption by gas purchasers or in governmental regulations or
taxation will also affect actual future net cash flows. The timing of both the
production and the expenses from the development and production of oil and gas
properties will affect the timing of actual future net cash flows from proved
reserves and their present value. In addition, the 10% discount factor, which is
required by the Securities and Exchange Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor.
LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.
We use the full cost method of accounting to account for our oil and gas
operations. Accordingly, we capitalize the cost to acquire, explore for and
develop oil and gas properties. Under full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit"
which is based upon the present value of estimated future net cash flows from
proved reserves, discounted at 10%, plus the lower of cost or fair value of
unproved properties. If net capitalized costs of oil and gas properties exceed
the ceiling limit, we must charge the amount of the excess to earnings. This is
called a "ceiling test write-down." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity. The risk that we
will be required to write down the carrying value of oil and gas properties
increases when oil and gas prices are low or volatile. In addition, write-downs
may occur if we experience substantial downward adjustments to our estimated
proved reserves. Due to low oil and gas prices at the end of 1998, in December
1998 we recorded an after-tax write-down of $57.4 million ($89.1 million
pre-tax). We cannot assure you that we will not experience ceiling test
write-downs in the future.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING
STRATEGY.
We have historically addressed our long-term liquidity needs through the use
of bank credit facilities, the issuance of debt and equity securities and the
use of cash provided by operating activities. We continue to examine the
following alternative sources of long-term capital:
o bank borrowings or the issuance of debt securities;
o the issuance of common stock, preferred stock or other equity
securities;
o joint venture financing; and
o production payments.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and natural gas prices and our
market value and operating performance. We may be unable to execute our
operating strategy if we cannot obtain capital from these sources.
WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.
We spend and will continue to spend a substantial amount of capital for the
development, exploration, acquisition and production of oil and gas reserves.
Our capital expenditures were $164.7 million during 2000, $123.9 million during
1999 and $158.9 million during 1998. We estimate that capital expenditures for
the combined company in 2001 will be approximately $253 million. If low oil and
natural gas prices, operating difficulties or other factors, many of which are
beyond our control, cause our revenues or cash flows from operations to
decrease, we may be limited in our ability to spend the capital necessary to
complete our drilling program. After utilizing our available sources of
financing, we may be forced to raise additional debt or equity proceeds to fund
such expenditures. We cannot assure you that additional debt or equity financing
or cash generated by operations will be available to meet these requirements.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
In general, the volume of production from oil and gas properties declines as
reserves are depleted. The decline rates depend on reservoir characteristics.
Gulf of Mexico reservoirs tend to experience steep declines, while declines in
other regions tend to be relatively slow. A significant portion of our
production is from Gulf of Mexico reservoirs. Our reserves will decline as they
are produced unless we acquire properties with proved reserves or conduct
successful development and exploration activities. Our future natural gas and
oil production is highly dependent upon our level of success in finding or
acquiring additional reserves.
Our recent growth, including our recent acquisition of Basin, is due in part
to acquisitions of producing properties. The successful acquisition of producing
properties requires an assessment of a number of factors beyond our control.
These factors include recoverable reserves, future oil and gas prices, operating
costs and potential environmental and other liabilities, title issues and other
factors. Such assessments are inexact and their accuracy is inherently
uncertain. In connection with such assessments, we perform a review of the
subject properties, which we believe is generally consistent with industry
practices. However, such a review will not reveal all existing or potential
problems. In addition, the review will not permit a buyer to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. We cannot assure you that we will be able to acquire properties at
acceptable prices because the competition for producing oil and gas properties
is intense and many of our competitors have financial and other resources which
are substantially greater than those available to us.
Our strategy includes increasing our production and reserves by the
implementation of a carefully designed field-wide development plan. These
development plans are often formulated prior to the acquisition of a property.
However, we cannot assure you that our future development, acquisition and
exploration activities will result in additional proved reserves or that we will
be able to drill productive wells at acceptable costs.
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND
PRODUCTION ACTIVITIES.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or natural gas
reservoirs will be found. The cost of drilling and completing wells is often
uncertain. Oil and gas drilling and production activities may be shortened,
delayed or canceled as a result of a variety of factors, many of which are
beyond our control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o weather conditions;
o shortages in experienced labor; and
o shortages or delays in the delivery of equipment.
The prevailing prices of oil and natural gas also affect the cost of and the
demand for drilling rigs, production equipment and related services.
We cannot assure you that the new wells we drill will be productive or that
we will recover all or any portion of our investment. Drilling for oil and
natural gas may be unprofitable. Drilling activities can result in dry wells and
wells that are productive but do not produce sufficient net revenues after
operating and other costs to recoup drilling costs.
OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS.
The exploration, development and operation of oil and gas properties
involves a variety of operating risks including the risk of fire, explosions,
blowouts, pipe failure, abnormally pressured formations and environmental
hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures
or discharges of toxic gases. If any of these industry operating risks occur, we
could have substantial losses. Substantial losses may be caused by injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, our offshore operations are subject to the additional hazards of
marine operations, such as capsizing, collision and adverse weather and sea
conditions. In accordance with industry practice, we maintain insurance against
some, but not all, of the risks described above.
We currently maintain loss of production insurance to protect against
uncontrollable disruptions in production operations. The policy covers the
majority of our anticipated production volumes from selected offshore properties
on an individual facility basis. The value of lost production would be
calculated using the average of the last 45 days' revenue from the facility
prior to the loss. We currently maintain coverage of up to $75 million per
occurrence that becomes effective after 30 consecutive days of lost production.
We also maintain additional insurance of various types to cover our
operations, including maritime employer's liability and comprehensive general
liability. Coverage amounts are provided by primary and excess umbrella
liability policies with ultimate limits of $50 million. In addition, we maintain
up to $50 million in operator's extra expense insurance, which provides coverage
for the care, custody and control of wells drilled and/or completed plus redrill
and pollution coverage. The exact amount of coverage for each well is dependent
upon its depth and location.
We cannot assure you that our insurance will be adequate to cover losses or
liabilities. Also, we cannot predict the continued availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event,
not fully insured or indemnified against, could materially and adversely affect
our financial condition and operations.
A PORTION OF OUR PRODUCTION, REVENUES AND CASH FLOWS ARE DERIVED FROM ASSETS
THAT ARE CONCENTRATED IN A GEOGRAPHIC AREA.
Production from South Pelto Block 23 and Eugene Island Block 243 accounted
for approximately 26% and 23%, respectively, of our total oil and gas production
volumes during 2000. On a combined basis, production from South Pelto Block 23
and Eugene Island Block 243 accounted for approximately 18% and 16%,
respectively, of the combined company's production volumes during 2000.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.
As of December 31, 2000, our long-term debt was $100 million and we had
$192.5 million of available borrowing capacity under our bank credit facility
with no outstanding draws. The borrowing base limitation on our credit facility
is periodically redetermined based on an evaluation of our reserves. Upon a
redetermination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our bank debt. We may not
have sufficient funds to make such repayments.
Our level of debt affects our operations in several important ways,
including the following:
o a large portion of our cash flow from operations may be used to pay
interest on borrowings;
o the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds or to dispose of assets;
o the covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes in
business conditions;
o a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes;
o our leveraged financial position may make us more vulnerable to
economic downturns and may limit our ability to withstand competitive
pressures;
o any debt that we incur under our credit facility will be at variable
rates which makes us vulnerable to increases in interest rates; and
o a high level of debt will affect our flexibility in planning for or
reacting to changes in market conditions.
In addition, we may significantly alter our capitalization in order to make
future acquisitions or develop our properties. These changes in capitalization
may significantly increase our level of debt. A higher level of debt increases
the risk that we may default on our debt obligations. Our ability to meet our
debt obligations and to reduce our level of debt depends on our future
performance. General economic conditions and financial, business and other
factors affect our operations and our future performance. Many of these factors
are beyond our control.
If we are unable to repay our debt at maturity out of cash on hand, we could
attempt to refinance such debt, or repay such debt with the proceeds from an
equity offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that future borrowings
or equity financing will be available to pay or refinance such debt. The terms
of our debt, including our credit facility and the indenture, may also prohibit
us from taking such actions. Factors that will affect our ability to raise cash
through an offering of our capital stock or a refinancing of our debt include
financial market conditions and our market value and operating performance at
the time of such offering or other financing. We cannot assure you that any such
offering or refinancing can be successfully completed.
COMPETITION WITHIN OUR INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.
We operate in a highly competitive environment. We compete with major and
independent oil and gas companies for the acquisition of desirable oil and gas
properties and the equipment and labor required to develop and operate such
properties. Many of these competitors have financial and other resources
substantially greater than ours.
OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE AND LOCAL
GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.
Our oil and gas operations are subject to various U.S. federal, state and
local governmental regulations. These regulations may be changed in response to
economic or political conditions. Regulated matters include permits for
discharges of wastewaters and other substances generated in connection with
drilling operations, bonds or other financial responsibility requirements to
cover drilling contingencies and well plugging and abandonment costs, reports
concerning operations, the spacing of wells and unitization and pooling of
properties and taxation. At various times, regulatory agencies have imposed
price controls and limitations on oil and gas production. In order to conserve
supplies of oil and gas, these agencies have restricted the rates of flow of oil
and gas wells below actual production capacity. In addition, the OPA requires
operators of offshore facilities to prove that they have the financial
capability to respond to costs that may be incurred in connection with potential
oil spills. Under such law and other federal and state environmental statutes,
including CERCLA and RCRA, owners and operators of certain defined onshore and
offshore facilities are strictly liable for spills of oil and other regulated
substances, subject to certain limitations. A substantial spill from one of our
facilities could have a material adverse effect on our results of operations,
competitive position or financial condition. Federal, state and local laws
regulate production, handling, storage, transportation and disposal of oil and
gas, by-products from oil and gas and other substances, and materials produced
or used in connection with oil and gas operations. We cannot predict the
ultimate cost of compliance with these requirements or their effect on our
operations.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
Our operations are dependent upon a relatively small group of key management
and technical personnel. We cannot assure you that such individuals will remain
with us for the immediate or foreseeable future. We do not have employment
contracts with any of these individuals. The unexpected loss of the services of
one or more of these individuals could have a detrimental effect on us.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In order to manage our exposure to price risks in the marketing of our oil
and gas, we enter into oil and gas price hedging arrangements with respect to a
portion of our expected production. Our hedging policy provides that, without
prior approval of our board of directors, generally not more than 50% of our
production quantities may be hedged. These arrangements may include futures
contracts on the New York Mercantile Exchange. While intended to reduce the
effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement;
o the counterparties to our futures contracts fail to perform the
contracts; or
o a sudden, unexpected event materially impacts oil or gas prices.
OWNERSHIP OF WORKING INTERESTS IN CERTAIN OF OUR PROPERTIES BY CERTAIN OF OUR
OFFICERS AND DIRECTORS MAY CREATE CONFLICTS OF INTEREST.
James H. Stone and Joe R. Klutts, both directors of Stone Energy,
collectively own 9% of the working interest in certain wells drilled on Section
19 on the east flank of Weeks Island Field. These interests were acquired at the
same time that our predecessor company acquired its interests in Weeks Island
Field. In their capacity as working interest owners, they are required to pay
their proportional share of all costs and are entitled to receive their
proportional share of revenues.
Certain of our officers were granted net profits interests in some of our
oil and gas properties acquired prior to 1993. The recipients of net profits
interests are not required to pay capital costs incurred on the properties
burdened by such interests.
As a result of these transactions, a conflict of interest may exist between
us and such directors and officers with respect to the drilling of additional
wells or other development operations.
WE DO NOT PAY DIVIDENDS.
We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the near future. The restrictions on our present
or future ability to pay dividends are included in the provisions of the
Delaware General Corporation Law and in certain restrictive provisions in the
indenture executed in connection with our 8-3/4% Senior Subordinated Notes due
2007. In addition, we have entered into a credit facility that contains
provisions that may have the effect of limiting or prohibiting the payment of
dividends.
OUR CERTIFICATE OF INCORPORATION AND BYLAWS HAVE PROVISIONS THAT DISCOURAGE
CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON
THEIR INVESTMENT.
Certain provisions of our Certificate of Incorporation, Bylaws and
shareholders' rights plan and the provisions of the Delaware General Corporation
Law may encourage persons considering unsolicited tender offers or other
unilateral takeover proposals to negotiate with our board of directors rather
than pursue non-negotiated takeover attempts. Our Bylaws provide for a
classified board of directors. Also, our Certificate of Incorporation authorizes
our board of directors to issue preferred stock without stockholder approval and
to set the rights, preferences and other designations, including voting rights
of those shares, as the board may determine. Additional provisions include
restrictions on business combinations and the availability of authorized but
unissued common stock. These provisions, alone or in combination with each other
and with the rights plan described below, may discourage transactions involving
actual or potential changes of control, including transactions that otherwise
could involve payment of a premium over prevailing market prices to stockholders
for their common stock.
During 1998, our board of directors adopted a shareholder rights agreement,
pursuant to which uncertificated stock purchase rights were distributed to our
stockholders at a rate of one right for each share of common stock held of
record as of October 26, 1998. The rights plan is designed to enhance the
board's ability to prevent an acquirer from depriving stockholders of the
long-term value of their investment and to protect stockholders against attempts
to acquire us by means of unfair or abusive takeover tactics. However, the
existence of the rights plan may impede a takeover not supported by our board,
including a takeover that may be desired by a majority of our stockholders or
involving a premium over the prevailing stock price.
ITEM 2. PROPERTIES
We have grown principally through the acquisition and subsequent development
and exploitation of properties purchased from major and independent oil
companies. During 2000, we acquired working interests in two new producing
fields bringing the total number of producing properties that we operate to 21.
Of these properties, 13 are located in the Gulf of Mexico and eight are onshore
Louisiana. In addition to acquiring producing properties, in May 2000, we were
awarded primary term leases at West Cameron Block 177 and Vermilion Block 276.
The merger with Basin Exploration added 58 producing properties to our asset
base increasing the number of producing properties in which we have a working
interest to 79, 46 of which are located in the Gulf Coast Basin and 33 are in
the Rocky Mountains. Of the 79 producing properties, we operate 52.
OIL AND GAS RESERVES
The following table sets forth our estimated net proved oil and gas reserves
and the present value of estimated future pre-tax net cash flows related to such
reserves as of December 31, 2000. The proved natural gas reserves at December
31, 2000 excluded 4 Bcf of gas dedicated to a production payment. Also excluded
are the related estimated future net cash flows and the present value of
estimated future net cash flows of $9 million and $8.5 million, respectively.
The information in this Form 10-K relating to Stone's estimated oil and gas
reserves and the estimated future net cash flows attributable thereto is based
upon the reserve reports (the "Reserve Reports") prepared as of December 31,
2000 by Atwater Consultants, Ltd. and Cawley, Gillespie & Associates, Inc., both
independent petroleum engineers. All product pricing and cost estimates used in
the Reserve Reports are in accordance with the rules and regulations of the
Securities and Exchange Commission, and, except as otherwise indicated, the
reported amounts give no effect to federal or state income taxes otherwise
attributable to estimated future cash flows from the sale of oil and gas. The
present value of estimated future net cash flows has been calculated using a
discount factor of 10%.
You should not assume that the estimated future net cash flows or the
present value of estimated future net cash flows, referred to in the table
below, represent the fair value of our estimated oil and gas reserves. As
required by the SEC, we determine estimated future net cash flows using market
prices for oil and gas on the last day of the fiscal period. Using the
information contained in the Reserve Reports, the average 2000 year-end product
prices for all of our properties were $28.01 per barrel of oil and $10.13 per
Mcf of gas. During the first quarter of 2001, market prices for oil and gas have
generally decreased, which would result in a reduction of estimated future net
cash flows and the present value of estimated future net cash flows if
recomputed.
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
--------------------------- ---------------------------- --------------------------------
STONE COMBINED (1) STONE COMBINED (1) STONE COMBINED (1)
---------- ------------- ----------- ------------- ------------ --------------
Oil (MBbls)...................... 17,073 25,374 4,246 8,251 21,319 33,625
Gas (MMcf)....................... 221,433 307,320 50,805 91,204 272,238 398,524
Total oil and gas (MMcfe)........ 323,871 459,564 76,281 140,710 400,152 600,274
Estimated future net
cash flows before income
taxes (in thousands)............$2,421,951 $3,299,865 $516,615 $900,899 $2,938,566 $4,200,764
Present value of estimated
future net cash flows before
income taxes (in thousands).... $1,713,634 $2,365,721 $315,740 $576,069 $2,029,374 $2,941,790
(1) Estimates for Basin Exploration at December 31, 2000 were prepared by the
independent petroleum engineering firm of Ryder Scott Company. Based on
the combined reserve reports, the average 2000 year-end product prices
for the combined company were $27.30 per barrel of oil and $9.97 per Mcf
of gas.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein only represents estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the existence of
development plans. As a result, estimates of reserves made by different
engineers for the same property will often vary. Results of drilling, testing
and production subsequent to the date of an estimate may justify a revision of
such estimates. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately produced. Further, the estimated
future net revenues from proved reserves and the present value thereof are based
upon certain assumptions, including geological success, prices, future
production levels and costs that may not prove to be correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
meaningfulness of these estimates depends on the accuracy of the assumptions
upon which they are based.
As an operator of domestic oil and gas properties, we have filed Department
of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by
Public Law 93-275. There are differences between the reserves as reported on
Form EIA-23 and as reported herein. The differences are attributable to the fact
that Form EIA-23 requires that an operator report the total reserves
attributable to wells that it operates, without regard to percentage ownership
(i.e., reserves are reported on a gross operated basis, rather than on a net
interest basis) or non-operated wells in which it owns an interest.
ACQUISITION, PRODUCTION AND DRILLING ACTIVITY
ACQUISITION AND DEVELOPMENT COSTS. The following table sets forth certain
information regarding the costs incurred in our acquisition, development and
exploratory activities during the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
---------- ---------- ----------
(In thousands)
Acquisition costs.................................. $10,803 $31,046 $17,748
Development costs.................................. 57,231 53,463 54,889
Exploratory costs.................................. 87,510 32,117 81,765
---------- ---------- ----------
Subtotal........................................... 155,544 116,626 154,402
Capitalized general and administrative costs and
interest, net of fees and reimbursements........ 9,146 7,284 4,480
---------- ---------- ----------
Total additions to oil and gas properties (1)...... $164,690 $123,910 $158,882
========== ========== ==========
(1) Total additions to oil and gas properties during 1999 included non-cash
additions of $20.3 million related to acquisitions made through production
payments.
COMBINED ACQUISITION AND DEVELOPMENT COSTS. Total additions to oil and gas
properties for the combined company during 2000 were approximately $270 million.
PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain
statistics regarding the number of productive wells and developed and
undeveloped acreage as of December 31, 2000.
STONE COMBINED
---------------------------------------- -----------------------------------------
GROSS NET GROSS NET
---------------- --------------- ---------------- ----------------
Productive Wells:
Oil............................ 87.00 (1) 63.46 368.00 (2) 244.46
Gas............................ 72.00 (3) 55.32 154.00 (4) 94.32
---------------- --------------- ---------------- ----------------
Total...................... 159.00 118.78 522.00 338.78
================ =============== ================ ================
Developed Acres:
Onshore Gulf Coast............. 3,773.71 2,947.50 3,933.71 2,996.25
Gulf of Mexico................. 13,764.64 5,755.87 148,116.82 73,385.67
Rocky Mountain Basin........... - - 48,805.44 28,406.42
---------------- --------------- ---------------- ----------------
Total...................... 17,538.35 8,703.37 200,855.97 104,788.34
================ =============== ================ ================
Undeveloped Acres:
Onshore Gulf Coast............. 27,757.53 17,852.01 39,869.62 23,246.64
Gulf of Mexico................. 83,419.22 70,381.69 257,944.71 213,724.08
Rocky Mountain Basin........... - - 211,213.54 127,885.23
---------------- --------------- ---------------- ----------------
Total...................... 111,176.75 (5) 88,233.70 509,027.87 (6) 364,855.95
================ =============== ================ ================
(1) 6 gross wells each have dual completions.
(2) 47 gross wells each have dual completions.
(3) 9 gross wells each have dual completions.
(4) 18 gross wells each have dual completions.
(5) Leases covering approximately 1% of our undeveloped gross acreage will
expire in 2001, 6% in 2002, 5% in 2003, 1% in 2004 and 10% in 2005. Leases
covering the remainder of our undeveloped gross acreage (77%) are held by
production.
(6) Leases covering approximately 6% of the undeveloped gross acreage will
expire in 2001, 9% in 2002, 17% in 2003, 14% in 2004 and 17% in 2005.
Leases covering the remainder of the undeveloped gross acreage (37%) are
held by production.
DRILLING ACTIVITY. The following table sets forth our drilling activity for
the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
2000 1999 1998
---------------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- -------- --------- --------
Exploratory Wells:
Productive................... 14.00 10.95 8.00 5.16 6.00 5.33
Nonproductive................ 9.00 6.35 1.00 0.31 4.00 3.35
Development Wells:
Productive................... 8.00 7.28 6.00 4.89 3.00 2.63
Nonproductive................ 1.00 0.82 - - 1.00 0.98
COMBINED DRILLING ACTIVITY. Drilling activity for 2000 for the combined
company was as follows:
YEAR ENDED DECEMBER 31, 2000
------------------------------------
COMBINED COMBINED
GROSS NET
---------------- ----------------
Exploratory Wells:
Productive.................. 30.00 17.35
Nonproductive............... 20.00 10.65
Development Wells:
Productive.................. 24.00 16.68
Nonproductive............... 1.00 0.82
TITLE TO PROPERTIES
We believe that we have satisfactory title on substantially all of our
producing properties in accordance with standards generally accepted in the oil
and gas industry. Our properties are subject to customary royalty interests,
liens for current taxes and other burdens, which we believe do not materially
interfere with the use of or affect the value of such properties. Prior to
acquiring undeveloped properties, we perform a title investigation that is
thorough but less vigorous than that conducted prior to drilling, which is
consistent with standard practice in the oil and gas industry. Before we
commence drilling operations, we conduct a thorough title examination and
perform curative work with respect to significant defects before proceeding with
operations. We have performed a thorough title examination with respect to
substantially all of our producing properties.
ITEM 3. LEGAL PROCEEDINGS
ENVIRONMENTAL
In August 1989, we were advised by the EPA that it believed we were 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 we 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 cleanup
costs on 23 of the PRP's, including us, who had not previously settled with the
EPA. Since that time we, together with other PRPs, have been negotiating the
settlement of our respective liability for environmental conditions at this site
with the U.S. Department of Justice. Given the number of PRP's at this site and
the current satisfactory progress of these negotiations, we do not believe that
any liability for this site would have a material adverse affect on our
financial condition. A tentative settlement has been reached with the U.S.
Department of Justice regarding our potential liability at this site. The amount
of this tentative settlement is immaterial to our financial statements and was
not accrued at December 31, 2000. However, the settlement has not been formally
approved by all parties, and we cannot assure you that a settlement will be
formally approved.
OTHER PROCEEDINGS
We are named as a defendant in certain lawsuits and are a party to certain
regulatory proceedings arising in the ordinary course of business. We do not
expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of our stockholders during the fourth
quarter of 2000.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names, ages (as of
March 15, 2001) and positions held by each of our executive officers. Our
executive officers serve at the discretion of the Board of Directors.
Name Age Position
---- --- --------
D. Peter Canty................................ 54 President, Chief Executive Officer and Director
Andrew L. Gates, III.......................... 53 Vice President, Secretary and General Counsel
Craig L. Glassinger........................... 53 Vice President - Resources
Phillip T. Lalande............................ 51 Vice President - Engineering
E. J. Louviere................................ 52 Vice President - Land
J. Kent Pierret............................... 45 Vice President - Accounting and Controller
James H. Prince............................... 58 Vice President, Chief Financial Officer and Treasurer
The following biographies describe the business experience of our executive
officers for at least the past five years. Stone Energy Corporation was formed
in March 1993 to become a holding company for The Stone Petroleum Corporation
("TSPC") and its subsidiaries. In 1997, TSPC was dissolved after the majority of
its assets were transferred to Stone Energy Corporation.
D. Peter Canty was named Chief Executive Officer on January 1, 2001 and
President in March 1994. He has also served as Chief Operating Officer and as a
Director since March 1993. Mr. Canty was President of TSPC from 1994 to 1997.
Andrew L. Gates, III has served as Vice President, Secretary and General
Counsel since August 1995.
Craig L. Glassinger was named Vice President - Resources in February 2001.
From December 1995 to February 2001 he served as Vice President - Acquisitions.
Phillip T. Lalande has served as Vice President - Engineering since March
1995.
E. J. Louviere has served as Vice President - Land since June 1995.
J. Kent Pierret was named Vice President - Accounting and Controller in June
1999. Prior to rejoining us, he was a partner in the firm of Pierret, Veazey &
Co., CPAs (and its predecessors) from May 1988 to May 1999, which performed a
substantial amount of our financial reporting, tax compliance and financial
advisory services.
James H. Prince was named Chief Financial Officer in August 1999 and
Treasurer in June 1999. He previously served as Chief Accounting Officer and
Controller from 1993 to June 1999.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since July 9, 1993, our common stock has been listed on the New York Stock
Exchange under the symbol "SGY." The following table sets forth, for the periods
indicated, the high and low closing prices per share of our common stock.
HIGH LOW
------- -------
1999
First Quarter............................... $33.063 $22.750
Second Quarter.............................. 45.000 31.375
Third Quarter............................... 55.625 42.000
Fourth Quarter.............................. 50.938 33.750
2000
First Quarter............................... $50.375 $32.250
Second Quarter.............................. 61.813 44.875
Third Quarter............................... 60.938 47.063
Fourth Quarter.............................. 67.380 50.190
2001
First Quarter (through March 15, 2001)...... $63.750 $50.390
On March 15, 2001, the last reported sales price on the New York Stock
Exchange Composite Tape was $51.50 per share. As of that date, there were
approximately 178 holders of record of our common stock.
DIVIDEND RESTRICTIONS
In the past, we have not paid cash dividends on our common stock, and we do
not intend to pay cash dividends on our common stock in the foreseeable future.
We currently intend to retain earnings, if any, for the future operation and
development of our business. The restrictions on our present or future ability
to pay dividends are included in the provisions of the Delaware General
Corporation Law and in certain restrictive provisions in the indenture executed
in connection with our 8-3/4% Senior Subordinated Notes due 2007. In addition,
we have entered into a credit facility that contains provisions that may have
the effect of limiting or prohibiting the payment of dividends.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial
information for each of the years in the five year period ended December 31,
2000. This information is derived from our Financial Statements and the notes
thereto. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data."
For combined financial information regarding the merger with Basin
Exploration, see "Note 15 - Supplemental Combined Financial Statements -
Unaudited" to the Financial Statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per share amounts)
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil production revenue............................. $86,083 $56,969 $38,527 $31,082 $27,788
Gas production revenue............................. 170,325 89,950 76,070 37,997 28,051
Other revenue...................................... 3,971 2,215 2,023 1,908 2,126
--------- --------- --------- --------- ---------
Total revenues................................... 260,379 149,134 116,620 70,987 57,965
--------- --------- --------- --------- ---------
Expenses:
Normal lease operating expenses.................... 26,964 22,625 18,042 10,123 8,625
Major maintenance expenses......................... 6,538 1,115 1,278 1,844 427
Production taxes................................... 5,731 2,019 2,083 2,215 3,399
Depreciation, depletion and amortization........... 74,200 65,803 68,187 28,739 19,564
Write-down of oil and gas properties............... - - 89,135 - -
Interest expense................................... 8,534 12,907 12,987 5,004 3,618
General and administrative costs................... 6,005 4,604 4,256 3,815 3,465
Incentive compensation plan........................ 1,722 1,510 763 833 928
--------- --------- --------- --------- ---------
Total expenses................................... 129,694 110,583 196,731 52,573 40,026
--------- --------- --------- --------- ---------
Net income (loss) before income taxes................ 130,685 38,551 (80,111) 18,414 17,939
--------- --------- --------- --------- ---------
Income tax provision (benefit):
Current............................................ 450 25 - - 208
Deferred........................................... 45,290 12,036 (28,480) 6,495 6,698
--------- --------- --------- --------- ---------
Total income taxes............................... 45,740 12,061 (28,480) 6,495 6,906
--------- --------- --------- --------- ---------
Net income (loss).................................... $84,945 $26,490 ($51,631) $11,919 $11,033
========= ========= ========= ========= =========
Earnings and dividends per common share:
Basic net income (loss) per common share .......... $4.60 $1.61 ($3.43) $0.79 $0.90
========= ========= ========= ========= =========
Diluted net income (loss) per common share ........ $4.51 $1.58 ($3.43) $0.78 $0.90
========= ========= ========= ========= =========
Cash dividends declared............................ - - - - -
CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes)........ $198,886 $101,348 $77,211 $47,153 $37,295
Net cash provided by operating
activities......................................... 213,680 78,850 85,633 32,679 32,751
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital ..................................... $53,421 $22,887 $9,884 $8,328 $6,683
Oil and gas properties, net.......................... 444,631 353,141 293,824 291,420 171,396
Total assets ........................................ 602,431 441,738 366,390 354,144 209,406
Long-term debt, less current portion................. 100,000 100,000 209,936 132,024 26,172
Stockholders' equity ................................ 356,743 265,587 105,332 156,637 144,441
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in understanding our
financial position and results of operations for each year of the three-year
period ended December 31, 2000. Our Financial Statements and the notes thereto,
which are found elsewhere in this Form 10-K, contain detailed information that
should be referred to in conjunction with the following discussion. See "Item 8.
Financial Statements and Supplementary Data."
OVERVIEW
We are an independent oil and gas company engaged in the acquisition,
exploration, development and operation of oil and gas properties onshore and in
shallow waters offshore Louisiana. We have been active in the Gulf Coast Basin
since 1973, which gives us extensive geophysical, technical and operational
expertise in this area.
Historically, we have sought growth primarily through the acquisition and
development of mature fields with a prolific production history. As commodity
prices increase and provide financial stability through additional cash flow it
becomes more feasible to pursue an aggressive exploratory drilling strategy.
During 2000, we designed a drilling program that provided an acceptable mix of
high and low risk projects in an effort to capitalize on an opportunity to test
certain prospects that have higher reward potential but are too high risk to
drill in periods of low prices. As a result, we drilled a record number of
wells, the majority of which were classified as exploratory wells.
As commodity prices increased, the demand for and the costs of drilling rigs
and related services did as well. In an attempt to hedge against rising drilling
costs, we entered into long-term fixed dayrate contracts for drilling rigs that
are capable of drilling on all our properties and we occasionally entered into
turnkey contracts that require a fixed payment upon the completion of a project
regardless of the number of drilling days.
The current commodity price environment also impacted the property market.
It is generally more expensive to buy properties at times when oil and gas
prices have increased, which is what we witnessed during the year 2000.
Therefore, we pursued stock-for-stock merger targets and non-cash acquisition
opportunities such as farmins, whereby we earned a working interest in desirable
acreage by drilling a well versus buying the field.
From time to time we enter into hedging contracts to reduce our exposure to
the possibility of declining commodity prices. Traditionally, these contracts
have been in the form of fixed price swaps and collars. In response to rising
commodity prices, we sought a hedging instrument that guaranteed a floor on the
prices we would receive for certain production volumes while allowing us to
fully participate in commodity price increases. As such, we purchased put
contracts for a portion of our future production that guarantee what we believe
to be minimum attractive prices for our hedged volumes.
During 2000, we remained focused on our objectives of increasing production,
cash flow and reserves. We set a company record for annual production by
producing 66.5 billion cubic feet of gas equivalent (Bcfe). We also set a record
for annual cash flow before working capital changes with 2000 results of $198.9
million representing a 96% increase over 1999 results. Finally, at December 31,
2000, we reported 400.2 Bcfe of estimated proved reserves, which is the largest
proved reserve base in our history. Our 2000 reserve replacement ratio was 119%,
which marks the seventh consecutive year that we replaced more than our annual
production.
As a result of the Basin merger's impact on our production, cash flow and
our property base and prospect inventory, we currently expect to implement a
significantly expanded capital expenditures program during 2001. With an
estimated budget of approximately $253 million, we have designed a capital
expenditures program that attempts to maximize the potential of our expanded
prospect inventory and can be financed by future cash flow. In addition to
drilling, we expect to seek growth opportunities through acquisitions that
become more feasible in periods of declining prices. We will continue to modify
our operating strategy to meet the demands of our ever-changing industry.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to
our oil and gas operations and summary information with respect to our estimated
proved oil and gas reserves. See "Item 2. Properties - Oil and Gas Reserves."
For combined operating information regarding the merger with Basin
Exploration, see "Selected Comparative Financial and Operational Data" in "Item
1. Business."
Year Ended December 31,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
PRODUCTION:
Oil (MBbls).................................................. 3,334 3,469 2,876
Gas (MMcf)
Produced excluding volumetric production payment.......... 43,813 36,780 33,281
Volumetric production payment............................. 2,667 1,333 -
------------ ------------ ------------
Total gas volumes produced................................ 46,480 38,113 33,281
Oil and gas (MMcfe)
Produced excluding volumetric production payment.......... 63,817 57,594 50,537
Volumetric production payment............................. 2,667 1,333 -
------------ ------------ ------------
Total volumes produced.................................... 66,484 58,927 50,537
AVERAGE SALES PRICES:
Oil (per Bbl)................................................ $25.82 $16.42 $13.40
Gas (per Mcf)
Price excluding volumetric production payment............. $3.75 $2.36 $2.29
Volumetric production payment............................. 2.24 2.24 -
Net average price......................................... 3.66 2.36 2.29
Oil and gas (per Mcfe)
Price excluding volumetric production payment............. $3.92 $2.50 $2.27
Volumetric production payment............................. 2.24 2.24 -
Net average price......................................... 3.86 2.49 2.27
AVERAGE COSTS (PER MCFE):
Normal operating costs....................................... $0.41 $0.38 $0.36
General and administrative costs............................. 0.09 0.08 0.08
Depreciation, depletion and amortization..................... 1.10 1.10 1.33
RESERVES AT DECEMBER 31:
Oil (MBbls).................................................. 21,319 22,636 18,476
Gas (MMcf)................................................... 272,238 251,614 243,270
Oil and gas (MMcfe).......................................... 400,152 387,430 354,126
Present value of estimated future net cash flows before
income taxes (in thousands)............................... $2,029,374 $561,303 $286,098
2000 COMPARED TO 1999. For the year 2000 we reported record net income
totaling $84.9 million, or $4.51 per share, compared to net income for the year
ended December 31, 1999 of $26.5 million, or $1.58 per share. The favorable
results in net income were due to improvements in the following components:
PRODUCTION. During 2000, production volumes reached a record high totaling
66.5 Bcfe compared to 58.9 Bcfe produced during 1999. Natural gas production
during 2000 increased 22% to approximately 46.5 billion cubic feet compared to
1999 gas production of 38.1 billion cubic feet, while oil production during 2000
totaled approximately 3.3 million barrels compared to 3.5 million barrels
produced during 1999.
The increase in 2000 production rates, compared to 1999, was due to
increases at several of our fields, the most significant of which were Eugene
Island Block 243 and East Cameron Block 64.
PRICES. Prices realized during 2000 averaged $25.82 per barrel of oil and
$3.66 per Mcf of gas. This represents a 55% increase, on an Mcfe basis, over
1999 average realized prices of $16.42 per barrel of oil and $2.36 per Mcf of
gas. All unit pricing amounts include the effects of hedging.
From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. Due to
increases in commodity prices, hedging transactions reduced the average price we
received during the year for oil by $4.60 per barrel and for gas by $0.48 per
Mcf, compared to a net decrease of $1.42 per barrel and a net increase of $0.02
per Mcf realized during 1999.
OIL AND GAS REVENUE. As a result of higher production rates and realized
prices, oil and gas revenue reached a record high during 2000, increasing 75% to
$256.4 million, compared to 1999 oil and gas revenue of $146.9 million.
EXPENSES. Normal operating costs during 2000 increased to $27 million,
compared to $22.6 million during 1999. On a unit of production basis, 2000
operating costs were $0.41 per Mcfe as compared to $0.38 per Mcfe for 1999. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.
During 2000, we performed significant workover operations on nine wells at
three fields. As a result, major maintenance expenses for the year totaled $6.5
million compared to $1.1 million for 1999.
Due to increased 2000 onshore production volumes combined with higher oil
and gas prices, production revenue from onshore properties increased 108%. As a
result, production tax expense increased to $5.7 million from $2 million in
1999. Included in the 1999 amount was a $1 million production tax refund related
to the abatement of severance taxes for certain wells under Louisiana state law.
Depreciation, depletion and amortization (DD&A) expense on our oil and gas
properties totaled $73.2 million compared to $64.6 million for 1999. However, on
a unit of production basis, this expense was unchanged from the 1999 rate of
$1.10 per Mcfe.
General and administrative expenses for 2000 increased in total to $6
million, or $0.09 per Mcfe, from $4.6 million, or $0.08 per Mcfe, during 1999.
Due to our operational and financial results and our stock price performance
during the year, incentive compensation expense for 2000 increased to $1.7
million compared to $1.5 million in 1999. Both general and administrative and
incentive compensation expenses for 2000 were affected by a 10% increase in our
staff level over 1999.
As a result of the repayment of the borrowings under our bank credit
facility in August 1999, interest expense for 2000 decreased to $8.5 million,
compared to $12.9 million during 1999.
RESERVES. At December 31, 2000, our estimated proved oil and gas reserves
totaled 400.2 Bcfe, compared to December 31, 1999 reserves of 387.4 Bcfe.
Estimated proved gas reserves grew to 272.2 Bcf at the end of 2000 from 251.6
Bcf at year-end 1999, while estimated proved oil reserves declined to 21.3
MMBbls at the end of 2000 from 22.6 MMBbls at the beginning of the year.
The increases in our 2000 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions during the year. The reserve
estimates were prepared by independent petroleum consultants in accordance with
guidelines established by the SEC. Adherence to these guidelines limited us in
booking reserves on certain successfully drilled wells to the extent of the base
of known productive sands. Actual limits of the productive sands will ultimately
be determined through production or additional drilling.
Our present values of estimated future net cash flows before income taxes
were $2 billion and $561.3 million at December 31, 2000 and 1999, respectively.
You should not assume that the present values of estimated future net cash flows
represent the fair value of our estimated oil and gas reserves. As required by
the SEC, we determine the present value of estimated future net cash flows using
market prices for oil and gas on the last day of the fiscal period. The average
year-end oil and gas prices on all of our properties used in determining these
amounts were $28.01 per barrel and $10.13 per Mcf for 2000 and $25.07 per barrel
and $2.47 per Mcf for 1999. During the first quarter of 2001, market prices for
oil and gas have generally decreased, which would result in a reduction of
estimated future net cash flows and the present value of estimated future net
cash flows at December 31, 2000 if recomputed.
1999 COMPARED TO 1998. We recognized net income for the year ended December
31, 1999 totaling $26.5 million, or $1.58 per share, compared to the 1998 net
loss of $51.6 million, or $3.43 per share. The 1998 results included an
after-tax non-cash ceiling test write-down of $57.4 million, or $3.82 per share.
Excluding the write-down, favorable results in 1999 net income versus 1998 were
due to improvements in the following components:
PRODUCTION. Production volumes of oil and gas reached a then record high
during 1999 and, as compared to 1998, rose 21% and 15%, respectively, totaling
3.5 million barrels of oil and 38.1 billion cubic feet of gas. On a thousand
cubic feet of gas equivalent (Mcfe) basis, production rates for 1999 were 17%
higher than 1998 production rates.
The increase in 1999 production rates, compared to 1998, was due primarily
to increases at four of our fields. First, we successfully executed an
aggressive exploration and development program at Vermilion Block 255 by
completing and placing on production three exploratory and two development
wells. At the end of 1998, we began producing two high-pressured gas wells at
the South Pelto Block 23 E Platform, which significantly contributed to 1999's
favorable production rates. From June 1998 through August 1999, we successfully
drilled one exploratory well, three development wells and completed three
workovers to enhance production at Clovelly Field. Finally, in May 1999, we
increased our interest, and therefore our share of production, at Weeks Island
Field through the acquisition of an additional 32% working interest in 11
producing wells.
PRICES. Average realized prices during 1999 were $16.42 per barrel of oil
and $2.36 per Mcf of gas and represented a 10% increase, on an Mcfe basis, over
average prices of $13.40 per barrel of oil and $2.29 per Mcf of gas recognized
during 1998, including the effects of hedging. From time to time, we enter into
various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. During 1999, hedging transactions reduced the
average price we received for oil by $1.42 per barrel and increased the average
gas price received by $0.02 per Mcf compared to net increases of $0.28 per
barrel of oil and $0.10 per Mcf of gas during 1998.
OIL AND GAS REVENUE. Oil and gas revenue reached a then record high during
1999. The favorable increases in oil and gas production rates combined with
higher commodity prices resulted in oil and gas revenue increasing 28% to $146.9
million, compared to oil and gas revenue of $114.6 million during 1998.
EXPENSES. Normal operating costs during 1999 increased to $22.6 million,
compared to $18 million during 1998. On a unit of production basis, 1999
operating costs were $0.38 per Mcfe compared to $0.36 per Mcfe for 1998. The
increase in operating costs was due primarily to a 34% increase in the number of
producing wells that we operated as a result of the acquisitions of Lafitte
Field, West Cameron Block 176 and East Cameron Block 46, the increases in
working interest at East Cameron Block 64, Eugene Island Block 243 and Weeks
Island Field and discoveries at many of our fields including Vermilion Block
255, Vermilion Block 131, Clovelly Field and Eugene Island Block 243.
As a result of increased 1999 production volumes due to acquisitions and
discoveries combined with higher oil and gas prices during the year, production
revenue from onshore properties increased 43% during 1999. Our production tax
expense, however, declined during 1999 to $2 million from $2.1 million in 1998.
This decrease resulted from the abatement of severance taxes for certain wells
under Louisiana state law. Accordingly, we accrued in December 1999, and
received in early 2000, a production tax refund of $1 million.
General and administrative expenses for 1999 increased in total to $4.6
million from $4.3 million during 1998. However, on a unit basis, these costs
were unchanged from the 1998 amount of $0.08 per Mcfe. Due to our operational
results and stock performance during the year, incentive compensation expense
for 1999 increased to $1.5 million compared to $0.8 million in 1998.
DD&A expense on our oil and gas properties decreased to $64.6 million, or
$1.10 per Mcfe, compared to $67.3 million, or $1.33 per Mcfe, for 1998. The
decrease in DD&A expense resulted from a combination of the $89.1 million
non-cash ceiling test write-down of oil and gas properties recorded at the end
of 1998 and the improvement in oil and gas prices throughout 1999.
Our provision for income taxes was $12.1 million for the year ended December
31, 1999 and was net of a $1.5 million reduction in deferred taxes relative to
estimates of tax basis that were resolved during 1999.
RESERVES. At December 31, 1999, our estimated proved oil and gas reserves
totaled 387.4 Bcfe, excluding approximately 6.7 Bcf of gas dedicated to a
production payment associated with certain 1999 acquisitions, compared to
December 31, 1998 reserves of 354.1 Bcfe. Estimated proved oil reserves
increased to 22.6 MMBbls at the end of 1999 from 18.5 MMBbls at the beginning of
the year, and estimated proved gas reserves grew to 251.6 Bcf at December 31,
1999, excluding the 6.7 Bcf of gas dedicated to a production payment, compared
to 243.3 Bcf at year-end 1998.
The increases in our 1999 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions made during the year. The
reserve estimates were prepared by independent petroleum consultants in
accordance with guidelines established by the SEC. Adherence to these guidelines
limited us in booking reserves on certain successfully drilled wells to the
extent of the base of known productive sands. Actual limits of the productive
sands will ultimately be determined through production or additional drilling.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Net cash flow from operations before working
capital changes for 2000 was $198.9 million, or $10.57 per share, compared to
$101.3 million, or $6.04 per share, reported for 1999. Working capital at
December 31, 2000 totaled $53.4 million.
CAPITAL EXPENDITURES. Capital expenditures during 2000 totaled $164.7
million and included $7.8 million of capitalized general and administrative
costs, net of reimbursements, and $1.3 million of capitalized interest. These
investments were financed by a combination of cash flows from operations and
working capital.
MERGER WITH BASIN EXPLORATION. On February 1, 2001, the stockholders of
Stone Energy Corporation and Basin Exploration, Inc. voted in favor of, and
thereby consummated, the combination, through a pooling of interests, of the two
companies in a tax-free, stock-for-stock transaction. In connection with the
approval of the merger, stockholders of Stone Energy also approved a proposal to
increase the authorized shares of Stone common stock from 25 million to 100
million shares. Under the merger agreement, Basin stockholders received 0.3974
of a share of Stone common stock for each share of Basin common stock they
owned. As such, Stone issued approximately 7.4 million shares of common stock
which, based upon Stone's closing price of $53.70 on February 1, 2001, resulted
in total equity value related to the transaction of approximately $400 million.
In addition, Stone assumed, and subsequently retired with cash on hand,
approximately $48 million of Basin bank debt. The expenses incurred in relation
to the merger are currently estimated to total $27 million and will be a
non-recurring item recorded in the first quarter of 2001.
BUDGETED CAPITAL EXPENDITURES AND LONG-TERM FINANCING. The merger with
Basin, which was effective February 1, 2001, increased our property base to 79
producing properties by adding 25 Gulf Coast Basin and 33 Rocky Mountain
properties. Our estimated 2001 capital expenditures budget of approximately $253
million is expected to be allocated approximately 90% to Gulf Coast operations
and 10% to Rocky Mountain activities. The 2001 planned investment in the Rockies
represents over a 200% increase from the investments made by Basin in the region
during 2000. We expect to drill 77 gross wells during 2001, 43 in the onshore
and shallow water offshore regions of the Gulf Coast Basin and 34 in the Rocky
Mountains. Approximately 65% of the estimated drilling costs are expected to be
dedicated to exploratory targets with the remaining 35% allocated to the
development of existing reserves. While the 2001 capital expenditures budget
does not include any projected acquisitions, we continue to seek growth
opportunities that fit our specific acquisition profile.
Our production goal for 2001 is to increase production 15% over 2000's
combined production of 98.9 Bcfe. Based upon our outlook on oil and gas prices
and production rates, we believe that our cash flows from operations will be
sufficient to fund the current 2001 capital expenditures budget. If oil and gas
prices or production rates fall below our current expectations, we believe that
the available borrowings under our bank credit facility will be sufficient to
fund 2001 capital expenditures in excess of operating cash flows.
We do not budget acquisitions; however, we are currently evaluating several
opportunities that fit our specific acquisition profile. One or a combination of
certain of these possible transactions could fully utilize our existing sources
of capital. Although we have no plans to access the public markets for purposes
of capital, if the opportunity arose, we would consider such funding sources to
provide capital in excess of what is currently available to us. We would compare
the cost of debt financing with the potential dilution of equity offerings to
determine the appropriate financing vehicle to maximize stockholder value.
HEDGING. See "Item 7A. Quantitative and Qualitative Disclosure About Market
Risk - Commodity Price Risk."
NEW ACCOUNTING STANDARDS. See "Item 7A. Quantitative and Qualitative
Disclosure About Market Risk - Commodity Price Risk - Adoption of SFAS No. 133."
BANK CREDIT FACILITY. During 2000, our bank group increased the borrowing
base under our credit facility to $200 million and extended the maturity date
from July 30, 2001 to July 30, 2005. The borrowing base limitation is based on a
borrowing base amount established by the banks for our oil and gas properties.
During 2000, we did not draw upon our credit facility, and at December 31, 2000
we had outstanding letters of credit totaling $7.5 million.
Our 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. These covenants may limit or prohibit us from paying cash
dividends.
REGULATORY AND LITIGATION ISSUES. In August 1989, we were advised by the EPA
that it believed we were 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 we 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 cleanup costs on 23 of the PRP's, including us, who had not
previously settled with the EPA. Since that time we, together with other PRPs,
have been negotiating the settlement of our respective liability for
environmental conditions at this site with the U.S. Department of Justice. Given
the number of PRP's at this site and the current satisfactory progress of these
negotiations, we do not believe that any liability for this site would have a
material adverse affect on our financial condition. A tentative settlement has
been reached with the U.S. Department of Justice regarding our potential
liability at this site. The amount of this tentative settlement is immaterial to
our financial statements and was not accrued at December 31, 2000. However, the
settlement has not been formally approved by all parties, and we cannot assure
you that a settlement will be formally approved.
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 were required to increase their
area-wide bonds and individual lease bonds to $3 million and $1 million,
respectively, unless the MMS allowed exemptions or reduced amounts. We currently
have an area-wide right-of-way bond for $0.3 million and an area-wide lessee's
and operator's bond totaling $3 million issued in favor of the MMS for our
existing offshore properties. The MMS also has discretionary authority to
require supplemental bonding in addition to the foregoing required bonding
amounts but this authority is only exercised on a case-by-case basis at the time
of filing an assignment of record title interest for MMS approval. Based upon
certain financial parameters, we have been granted exempt status by the MMS,
which exempts us from the supplemental bonding requirements. Under certain
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition and operations.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and a MMS final rule adopted in August
1998, responsible parties of covered offshore facilities that have a worst case
oil spill of more than 1,000 barrels must demonstrate financial responsibility
in amounts ranging from at least $10 million in specified state waters to at
least $35 million in OCS waters, with higher amounts of up to $150 million in
certain limited circumstances where the MMS believes such a level is justified
by the risks posed by the operations or if the worst case oil-spill discharge
volume possible at the facility may exceed the applicable threshold volumes
specified under the MMS's final rule. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
We operate under numerous state and federal laws enacted for the protection
of the environment. In the ordinary course of business, we conduct an ongoing
review of the effects of these various environmental laws on our business and
operations. The estimated cost of continued compliance with current
environmental laws, based upon the information currently available, is not
material to our results of operations or financial position. It is impossible to
determine whether and to what extent our future performance may be affected by
environmental laws; however, we believe that such laws will not have a material
adverse effect on our results of operations or financial position.
We are named as a defendant in certain lawsuits and are a party to certain
regulatory proceedings arising in the ordinary course of business. We do not
expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
FORWARD-LOOKING STATEMENTS
Certain of the statements set forth under this item and elsewhere in this
Form 10-K, including in the documents incorporated by reference, 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 financial statements include our accounts and our
proportionate share of certain partnerships. On December 31, 1999, these
partnerships were dissolved after their assets were transferred to us. All
intercompany balances and transactions that existed prior to these dissolutions
have been eliminated.
Throughout this document we show combined operational and financial
information to give effect to the merger with Basin Exploration, as if the two
companies were combined on January 1, 2000. These combined results should be
used for information purposes only as they are not necessarily indicative of the
results that would have occurred if the merger had been completed on January 1,
2000.
FULL COST METHOD. We use the full cost method of accounting for our oil and
gas properties. Under this method, all acquisition and development costs,
including certain related employee costs and general and administrative costs
(less any reimbursements for such costs), incurred for the purpose of acquiring
and finding oil and gas are capitalized. We amortize our investment in oil and
gas properties 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." As of December 31, 2000, we had a net deferred
tax liability of $43.6 million which was calculated based on our assumption that
it is more likely than not that we will have sufficient taxable income in future
years to utilize certain tax attribute carryforwards.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
COMMODITY PRICE RISK
Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Oil and
gas price declines and volatility could adversely affect our revenues, cash
flows and profitability. In order to manage our exposure to oil and gas price
declines, we occasionally enter into oil and gas price hedging arrangements to
secure a price for a portion of our expected future production. We do not enter
into hedging transactions for trading purposes. While intended to reduce the
effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement;
o the counterparties to our hedging contracts fail to perform the
contracts; or
o a sudden, unexpected event materially impacts oil or gas prices.
Our hedging policy provides that not more than one-half of our production
quantities can be hedged without the consent of the Board of Directors.
Additionally, not more than 75% of our production quantities can be committed to
hedging agreements regardless of the prices available.
HEDGING. During 2000, we realized a net reduction in revenue from our
hedging transactions of $36.3 million. Our contracts totaled 1,739 MBbls of oil
and 21,050 BBtus of gas, which represented approximately 52% and 48%,
respectively, of our oil and gas production for the year. The net reduction in
revenue from hedging transactions for 1999 was $4.3 million. Our contracts
totaled 1,363 MBbls of oil and 16,440 BBtus of gas, which represented
approximately 39% and 47%, respectively, of our oil and gas production for that
year.
At December 31, 2000, the only hedging contracts we had in place were oil
puts. Put contracts are not costless; they are purchased at a rate per unit of
hedged production that fluctuates with the commodity futures market. The
historical cost of the put contracts represents our maximum cash exposure. We
are not obligated to make any further payments under the put contracts
regardless of future commodity price fluctuations. Our oil puts were reflected
as assets in our December 31, 2000 balance sheet at a historical cost of $3.6
million.
Under put contracts, monthly payments are made to us if NYMEX prices fall
below the agreed upon floor price, while allowing us to fully participate in
commodity prices above that floor. Oil contracts typically settle using the
average of the daily closing prices for a calendar month. Since our properties
are located in the Gulf Coast Basin, we believe that fluctuations in NYMEX
prices will closely match changes in market prices for our production.
At December 31, 2000, we had hedged oil prices for the applicable periods,
quantities and prices as follows:
Puts
----------------------------------------
Oil
----------------------------------------
Volume Cost
(Bbls) Floor (millions)
---------- ----------- ------------
2001.................... 912,500 $25.00 $1.3
2002.................... 912,500 $24.00 $2.3
The expenditures made in 2000 to obtain puts totaled $3.6 million. At
December 31, 2000, the fair market value of these put contracts was $5.5 million
resulting in an unrealized gain of $1.9 million. This gain was not reflected in
our financial statements at December 31, 2000 because we did not adopt SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," until
January 1, 2001.
ADOPTION OF SFAS NO. 133. We adopted SFAS No. 133 effective January 1, 2001.
Under SFAS No. 133, as amended, the nature of a derivative instrument must be
evaluated to determine if it qualifies for special hedge accounting treatment.
If the instrument qualifies for hedge accounting treatment, it would be recorded
as either an asset or liability measured at fair value and subsequent changes in
the derivative's fair value would be recognized in equity through other
comprehensive income, to the extent the hedge is considered effective. If the
derivative does not qualify for hedge accounting treatment, it would be recorded
in the balance sheet and changes in fair value would be recognized in earnings.
At December 31, 2000, the only derivative instruments we had in place were
puts which, to the extent of changes in time value, do not meet the
"effectiveness" criteria for special hedge accounting treatment. These puts were
reflected as assets in our December 31, 2000 balance sheet at a historical cost
of $3.6 million. At year-end 2000, the fair value of our puts was $5.5 million.
If we had adopted SFAS No. 133 during 2000, we would have marked the puts to
market by recording a gain of $1.9 million in earnings.
Upon adoption of SFAS No. 133, the increase in fair value over historical
cost of $1.9 million was recorded as a transition adjustment. We recorded the
gain in equity through other comprehensive income. As each put contract expires,
we will recognize the related portion of the transition adjustment in earnings.
COMBINED HEDGING. The following table shows the hedging position of the
combined company as of February 23, 2001.
Puts
---------------------------------------------------------------------------------------------
Gas Oil
------------------------------------------- ---------------------------------------------
Volume Cost Volume Cost
(BBtus) Floor (millions) (Bbls) Floor (millions)
----------- ----------- ----------- ----------- ------------- -------------
2001(1).................. 22,000 $3.50 $1.3 1,277,500 $25.00 $1.8
2002..................... 21,900 $3.50 $5.2 1,277,500 $24.00 $3.2
(1) The hedged volumes related to the 2001 gas put contracts are from
April 2001 - December 2001.
Fixed Price Gas Swaps
---------------------------------------
Volume(BBtus) Price
--------------- ---------------
2001...................... 7,300 $2.33
2002...................... 3,650 $2.15
2003...................... 3,650 $2.15
In addition to put contracts, discussed above, the combined company utilized
fixed price swaps to hedge a portion of its future gas production. The combined
company did not enter into hedging transactions for trading purposes. Fixed
price swaps typically provide for monthly payments by the combined company if
NYMEX prices rise above the fixed swap price or to the combined company if NYMEX
prices fall below the fixed swap price. Natural gas contracts typically settle
using the average closing prices for near month NYMEX futures contracts for the
three days prior to the settlement date. Fixed price swaps meet the
"effectiveness" criteria to qualify for special hedge account treatment under
SFAS No. 133, as amended.
IMPACT OF THE ADOPTION OF SFAS NO. 133 ON THE COMBINED COMPANY. At December
31, 2000, the oil put contracts were recorded in the Supplemental Combined
Balance Sheet (See "Note 15 - Supplemental Combined Financial Statements -
Unaudited" to the Financial Statements) at a historical cost of $5 million and,
in accordance with generally accepted accounting principles in effect at
year-end 2000, the fixed price gas swap contracts were not recorded in the
Supplemental Combined Balance Sheet since they were costless. The gas put
contracts were purchased subsequent to year-end and therefore were not recorded
in the December 31, 2000 balance sheet. At December 31, 2000, the fair values of
the combined company's oil put contracts and fixed price gas swaps were $7.7
million and ($43.9) million, respectively.
SFAS No. 133 was adopted on January 1, 2001. Upon adoption of SFAS No. 133,
as amended, the increase in fair value over historical cost of the combined
company's oil put contracts of $2.7 million was a transition adjustment that was
recorded as a gain in equity through other comprehensive income. In addition,
the fair market value of the fixed price gas swaps was recorded in the balance
sheet as a liability and the corresponding loss of $43.9 million was recorded in
equity through other comprehensive income.
PROJECTED REVENUE. Based on projected combined annual sales for 2001, a 10%
decline in the prices the combined company is projecting to receive for its
crude oil and natural gas production would have an approximate $62.6 million
impact on its annual revenue. This hypothetical impact of the decline in oil and
gas prices is net of the incremental increase in revenue that the combined
company would realize, upon a decline in prices, from the oil and gas hedging
contracts in place as of February 23, 2001.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair value of cash and cash equivalents, net accounts receivable and
accounts payable approximated book value at December 31, 2000. At December 31,
2000, the fair value of the 8-3/4% Notes totaled $102 million.
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 17,
2001, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference. For information concerning Item 10, see also
"Part I - Item 4A. Executive Officers of the Registrant," set forth above in
this Form 10-K.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. FINANCIAL STATEMENTS:
The following financial statements and the Report of Independent Public
Accountants thereon are included on pages F-1 through F-23 of this Form
10-K.
Report of Independent Public Accountants
Balance Sheet as of December 31, 2000 and 1999
Statement of Operations for the three years in the period ended December
31, 2000
Statement of Cash Flows for the three years in the period ended December
31, 2000
Statement of Changes in Stockholders' Equity for the three years in the
period ended December 31, 2000
Notes to the Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is inapplicable
or the information is presented in the Financial Statements or the notes
thereto.
3. EXHIBITS:
2.1 -- Agreement and Plan of Merger, dated as of October 28, 2000, by
and among Stone Energy Corporation, Partner Acquisition Corp.
and Basin Exploration, Inc. (incorporated by reference to
Exhibit 2.1 to the Registrant's Registration Statement on
Form S-4 (Registration No. 333-51968)).
3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on
Form S-1 (Registration No. 33-62362)).
3.3 -- Certificate of Amendment of the Certificate of Incorporation
of Stone Energy Corporation, dated February 1, 2001 (incorporated
by reference to Exhibit 4.1 to the Registrant's Form 8-K, dated
February 7, 2001).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as
of October 15, 1998, between Stone Energy Corporation and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form 8-A (File No. 001-12074)).
4.2 -- Indenture between Stone Energy Corporation and Texas Commerce
Bank, National Association dated as of September 19, 1997
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form S-4 dated October 22, 1997 (File
No. 333-38425)).
4.3 -- Amendment No. 1, dated as of October 28, 2000, to Rights
Agreement dated as of October 15, 1998, between Stone Energy
Corporation and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent (incorporated by reference to Exhibit 4.4 to the
Registrant's Registration Statement on Form S-4 (Registration
No. 333-51968)).
+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 -- 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)).
+10.5 -- Deferred Compensation and Disability Agreement between TSPC
and E. J. Louviere dated July 16, 1981 (incorporated by
reference to Exhibit 10.10 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1995 (File
No. 001-12074)).
10.6 -- 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)).
+10.7 -- Stone Energy Corporation 2000 Amended and Restated Stock
Option Plan (incorporated by reference to Appendix A to the
Registrant's Definitive Proxy Statement on Schedule 14A for
Stone's 2000 Annual Meeting of Stockholders (File No.
001-12074)).
+10.8 -- Stone Energy Corporation Annual Incentive Compensation Plan
(incorporated by reference to Exhibit 10.14 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1993
(File No. 001-12074)).
*+10.9 -- Stone Energy Corporation Amendment to the Annual Incentive
Compensation Plan dated January 15, 1997.
*21.1 -- Subsidiaries of the Registrant.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*23.4 -- Consent of Ryder Scott Company.
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
(b) REPORTS ON FORM 8-K
Stone filed the following report on Form 8-K during the fourth quarter
of 2000:
Form 8-K filed by the Registrant on October 31, 2000 (press release
announcing the Agreement and Plan of Merger dated as of October 28,
2000 by and among Stone Energy Corporation, Partner Acquisition Corp.
and Basin Exploration, Inc.).
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act, as
amended, the Registrant has duly caused this Form 10-K to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Lafayette,
State of Louisiana, on the 22nd day of March 2001.
STONE ENERGY CORPORATION
By: /s/ D. PETER CANTY
------------------------
D. Peter Canty
President and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act, this Form 10-K
has been signed by the following persons in the capacities and on the dates
indicated.
Signature Title Date
--------- ----- ----
/s/ James H. Stone Chairman of the Board March 22, 2001
- ---------------------------------------
James H. Stone
/s/ Joe R. Klutts Vice Chairman of the Board March 22, 2001
- ---------------------------------------
Joe R. Klutts
/s/ D. Peter Canty President, Chief Executive Officer March 22, 2001
- --------------------------------------- and Director
D. Peter Canty (principal executive officer)
/s/ James H. Prince Vice President, Chief Financial March 22, 2001
- --------------------------------------- Officer and Treasurer
James H. Prince (principal financial officer)
/s/ J. Kent Pierret Vice President - Accounting March 22, 2001
- --------------------------------------- and Controller
J. Kent Pierret (principal accounting officer)
/s/ Peter K. Barker Director March 22, 2001
- ---------------------------------------
Peter K. Barker
/s/ Robert A. Bernhard Director March 22, 2001
- ---------------------------------------
Robert A. Bernhard
/s/ B.J. Duplantis Director March 22, 2001
- ---------------------------------------
B.J. Duplantis
/s/ Raymond B. Gary Director March 22, 2001
- ---------------------------------------
Raymond B. Gary
/s/ John P. Laborde Director March 22, 2001
- ---------------------------------------
John P. Laborde
/s/ Richard A. Pattarozzi Director March 22, 2001
- ---------------------------------------
Richard A. Pattarozzi
Director March 22, 2001
- ---------------------------------------
Michael S. Smith
/s/ David R. Voelker Director March 22, 2001
- ---------------------------------------
David R. Voelker
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants................................ F-2
Balance Sheet of Stone Energy Corporation as of
December 31, 2000 and 1999.............................. ............ F-3
Statement of Operations of Stone Energy Corporation for the
years ended December 31, 2000, 1999 and 1998......................... F-4
Statement of Cash Flows of Stone Energy Corporation
for the years ended December 31, 2000, 1999 and 1998................. F-5
Statement of Changes in Stockholders' Equity of Stone Energy Corporation
for the years ended December 31, 2000, 1999 and 1998................. F-6
Notes to Financial Statements........................................... F-7
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
Stone Energy Corporation:
We have audited the accompanying balance sheets of Stone Energy Corporation (a
Delaware corporation) as of December 31, 2000 and 1999, and the related
statements of operations, changes in stockholders' equity and cash flows for
each of the three years in the period ended December 31, 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Stone Energy Corporation as of
December 31, 2000 and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2000, in
conformity with accounting principles generally accepted in the United States.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
February 23, 2001
STONE ENERGY CORPORATION
BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)
December 31,
-------------------------------
ASSETS 2000 1999
------ ------------ ------------
Current assets:
Cash and cash equivalents................................................... $78,443 $13,874
Marketable securities, at market............................................ 300 34,906
Accounts receivable......................................................... 62,814 29,729
Other current assets........................................................ 441 297
Investment in put contracts................................................. 1,329 -
----------- -----------
Total current assets...................................................... 143,327 78,806
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $448,560 and $375,360, respectively....................... 424,104 335,959
Unevaluated................................................................. 20,527 17,182
Building and land, net of accumulated depreciation of $465 and
$355, respectively........................................................ 4,914 3,864
Fixed assets, net of accumulated depreciation of $2,022 and $1,239,
respectively.............................................................. 3,167 2,850
Other assets, net of accumulated depreciation and amortization
of $1,499 and $1,157, respectively........................................ 4,134 3,077
Investment in put contracts..................................................... 2,258 -
----------- -----------
Total assets.............................................................. $602,431 $441,738
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable to vendors................................................. $53,111 $36,060
Undistributed oil and gas proceeds.......................................... 29,365 13,130
Other accrued liabilities................................................... 7,430 6,729
----------- -----------
Total current liabilities................................................. 89,906 55,919
Long-term debt.................................................................. 100,000 100,000
Production payments............................................................. 10,906 17,284
Deferred tax liability.......................................................... 43,645 746
Other long-term liabilities..................................................... 1,231 2,202
----------- -----------
Total liabilities......................................................... 245,688 176,151
----------- -----------
Common stock, $.01 par value; authorized 25,000,000 shares;
issued and outstanding 18,543,875 and 18,336,458 shares, respectively....... 185 183
Paid-in capital................................................................. 259,150 252,941
Retained earnings............................................................... 97,408 12,463
----------- -----------
Total stockholders' equity................................................ 356,743 265,587
----------- -----------
Total liabilities and stockholders' equity................................ $602,431 $441,738
=========== ===========
The accompanying notes are an integral part of this balance sheet.
STONE ENERGY CORPORATION
STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
Year Ended December 31,
----------------------------------------------
2000 1999 1998
------------ ------------ -----------
Revenues:
Oil and gas production.......................................... $256,408 $146,919 $114,597
Other revenue................................................... 3,971 2,215 2,023
------------ ------------ -----------
Total revenues................................................ 260,379 149,134 116,620
------------ ------------ -----------
Expenses:
Normal lease operating expenses................................. 26,964 22,625 18,042
Major maintenance expenses...................................... 6,538 1,115 1,278
Production taxes................................................ 5,731 2,019 2,083
Depreciation, depletion and amortization........................ 74,200 65,803 68,187
Write-down of oil and gas properties............................ - - 89,135
Interest........................................................ 8,534 12,907 12,987
Salaries and other employee costs............................... 3,609 2,960 2,697
Incentive compensation plan..................................... 1,722 1,510 763
General and administrative costs................................ 2,396 1,644 1,559
------------ ------------ -----------
Total expenses................................................ 129,694 110,583 196,731
------------ ------------ -----------
Net income (loss) before income taxes .............................. 130,685 38,551 (80,111)
------------ ------------ -----------
Income tax provision (benefit):
Current......................................................... 450 25 -
Deferred........................................................ 45,290 12,036 (28,480)
------------ ------------ -----------
Total income taxes............................................ 45,740 12,061 (28,480)
------------ ------------ -----------
Net income (loss)................................................... $84,945 $26,490 ($51,631)
============ ============ ===========
Earnings (loss) per common share:
Basic earnings (loss) per share................................. $4.60 $1.61 ($3.43)
============ ============ ===========
Diluted earnings (loss) per share .............................. $4.51 $1.58 ($3.43)
============ ============ ===========
Average shares outstanding...................................... 18,448 16,469 15,066
============ ============ ===========
Average shares outstanding assuming dilution.................... 18,824 16,789 15,066
============ ============ ===========
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)
Year Ended December 31,
-------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
Cash flows from operating activities:
Net income (loss)............................................... $84,945 $26,490 ($51,631)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
DD&A and other non-cash expenses........................... 74,435 65,803 68,187
Deferred income tax provision (benefit).................... 45,290 12,036 (28,480)
Non-cash effect of production payments..................... (5,784) (2,981) -
Write-down of oil and gas properties....................... - - 89,135
-------------- -------------- --------------
198,886 101,348 77,211
(Increase) decrease in marketable securities............... 34,606 (18,053) 3,088
Increase in accounts receivable........................... (33,085) (2,926) (4,072)
Increase in other current assets.......................... (144) (140) (96)
Increase in undistributed oil and gas proceeds and other.. 16,936 3,024 4,887
Investment in put contracts............................... (3,587) - -
Other..................................................... 68 (4,403) 4,615
-------------- -------------- --------------
Net cash provided by operating activities........................... 213,680 78,850 85,633
-------------- -------------- --------------
Cash flows from investing activities:
Investment in oil and gas properties............................ (149,447) (95,168) (164,092)
Sale of oil and gas properties.................................. - - 9
Building additions and renovations.............................. (1,160) (405) (110)
(Increase) decrease in other assets.............................. (2,124) (2,226) 722
-------------- -------------- --------------
Net cash used in investing activities............................... (152,731) (97,799) (163,471)
-------------- -------------- --------------
Cash flows from financing activities:
Proceeds from borrowings........................................ - 13,000 89,000
Repayment of debt............................................... - (123,024) (11,081)
Deferred financing costs........................................ (200) - (160)
Proceeds from stock offering.................................... - 131,139 -
Expenses for stock offering..................................... - (379) -
Proceeds from exercise of stock options......................... 3,820 1,537 325
-------------- -------------- --------------
Net cash provided by financing activities........................... 3,620 22,273 78,084
-------------- -------------- --------------
Net increase in cash and cash equivalents........................... 64,569 3,324 246
Cash and cash equivalents beginning of year......................... 13,874 10,550 10,304
-------------- -------------- --------------
Cash and cash equivalents end of year............................... $78,443 $13,874 $10,550
============== ============== ==============
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)........................ $8,108 $13,125 $12,782
Income taxes................................................ 450 25 -
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
STATEMENT OF CHANGES IN STOCKHOLDERS' EQUITY
(Dollar amounts in thousands)
RETAINED
COMMON PAID-IN EARNINGS
STOCK CAPITAL (DEFICIT)
----------------- ----------------- ----------------
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)
Net income ............................................... - - 26,490
Sale of common stock...................................... 32 131,107 -
Expenses from common stock offering....................... - (379) -
Exercise of stock options................................. - 1,537 -
Tax benefit from stock option exercises................... - 1,468 -
----------------- ----------------- ----------------
Balance, December 31, 1999.................................. 183 252,941 12,463
Net income................................................ - - 84,945
Exercise of stock options................................. 2 3,818 -
Tax benefit from stock option exercises................... - 2,391 -
----------------- ----------------- ----------------
Balance, December 31, 2000.................................. $185 $259,150 $97,408
================= ================= ================
The accompanying notes are an integral part of this statement.
STONE ENERGY CORPORATION
NOTES TO FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per share and price amounts)
NOTE 1 -- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Stone Energy Corporation is an independent oil and gas company engaged in
the acquisition, exploration, development and operation of oil and gas
properties onshore and in shallow waters offshore Louisiana. We have been active
in the Gulf Coast Basin since 1973, and have extensive geophysical, technical
and operational expertise in this area. Our business strategy is focused on the
acquisition of mature properties with an established production history that
have significant exploitation and development potential. Since implementing this
business strategy in 1990, we have acquired 21 producing properties that
comprise our asset base, including 13 offshore and eight onshore Louisiana
properties. We are 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 financial statements is set forth below:
BASIS OF PRESENTATION:
The financial statements include our accounts and our proportionate interest
in certain partnerships. These partnerships were dissolved on December 31, 1999.
All intercompany balances have been eliminated. Certain prior year amounts have
been reclassified to conform to current year presentation.
USE OF ESTIMATES:
The preparation of financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of
contingent assets and liabilities at the date of the financial statements and
the reported amounts of revenues and expenses during the reporting period.
Actual results could differ from those estimates. Estimates are used primarily
when accounting for depreciation, depletion and amortization, unevaluated
property costs, estimated future net cash flows, taxes and contingencies.
FAIR VALUE OF FINANCIAL INSTRUMENTS:
The fair value of cash and cash equivalents, net accounts receivable and
accounts payable approximated book value at December 31, 2000. At December 31,
2000, the fair value of the 8-3/4% Notes totaled $102,000 and the fair value of
our oil put contracts in place was $5,478.
CASH AND CASH EQUIVALENTS:
We consider all highly liquid investments in overnight securities through
our commercial bank accounts, which result in available funds on the next
business day, to be cash and cash equivalents.
OIL AND GAS PROPERTIES:
We follow the full cost method of accounting for oil and gas properties.
Under this method, all acquisition, exploration and development costs, including
certain related employee 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.
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:(Continued)
As required by the Securities and Exchange Commission, under the full cost
method of accounting we are required to periodically compare the present value
of estimated future net cash flows from proved reserves (based on period-end
commodity prices) to the net capitalized costs of proved oil and gas properties.
If the net capitalized costs of proved oil and gas properties exceed the
estimated discounted future net cash flows from proved reserves, we are required
to write-down the value of our oil and gas properties to the value of the
discounted cash flows. Due to the impact of low year-end commodity prices on
December 31, 1998 reserve values, we recorded an $89,135 reduction in the
carrying value of our oil and gas properties at December 31, 1998.
Our investment in oil and gas properties is amortized 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 earned
during the period by future gross revenues at the beginning of the period, and
applying the resulting rate to the cost of oil and gas properties, including
estimated future development, restoration, dismantlement and abandonment costs.
Transactions involving sales of reserves in place, unless extraordinarily large
portions of reserves are involved, are recorded as adjustments to accumulated
depreciation, depletion and amortization.
Oil and gas properties included $20,527 and $17,182 of unevaluated property
and related costs that were not being amortized at December 31, 2000 and 1999,
respectively. These costs were associated with the acquisition and evaluation of
unproved properties and major development projects expected to entail
significant costs to ascertain quantities of proved reserves. We believe that a
majority of unevaluated properties at December 31, 2000 will be evaluated within
one to 24 months. The excluded costs and related proved reserve volumes will be
included in the amortization base as the properties are evaluated and proved
reserves are established or impairment is determined. Interest capitalized on
unevaluated properties during the years ended December 31, 2000 and 1999 was
$1,325 and $320, respectively.
BUILDING AND LAND:
Building and land are recorded at cost. Our Lafayette office building is
being depreciated on the straight-line method over its estimated useful life of
39 years.
FIXED ASSETS:
Fixed assets at December 31, 2000 and 1999 included approximately $2,187 and
$1,900, respectively, of computer hardware and software costs, net of
accumulated depreciation. These costs are being depreciated on the straight-line
method over an estimated useful life of 5 years.
OTHER ASSETS:
Other assets at December 31, 2000 and 1999 included approximately $2,637 and
$2,910, respectively, of deferred financing costs, net of accumulated
amortization, related to the sale of the 8-3/4% Notes (see Note 7). These costs
are being amortized over the life of the notes using the effective interest
method. Other assets at December 31, 2000 also included approximately $840 of
deferred expenses related to the Basin merger, which will be recorded in the
statement of operations as a non-recurring item in the first quarter of 2001.
EARNINGS PER COMMON SHARE:
Basic net income per share of common stock was calculated by dividing net
income applicable to common stock by the weighted-average number of common
shares outstanding during the year. Diluted net income per share of common stock
was calculated by dividing net income applicable to common stock by the
weighted-average number of common shares outstanding during the year plus the
weighted-average number of dilutive stock options granted to outside directors
and certain officers and employees. There were approximately 376,000 and 320,000
weighted-average dilutive shares for the years ending December 31, 2000 and
December 31, 1999, respectively, and there were no dilutive shares during 1998.
Options that were considered antidilutive because the exercise price of the
stock exceeded the average price for the applicable period totaled 17,958 shares
and 2,806 shares during 2000 and 1999, respectively. All options were considered
antidilutive in 1998 due to the net loss incurred in that year.
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:(Continued)
GAS PRODUCTION REVENUE:
We record as revenue only that portion of gas production sold and allocable
to our ownership interest in the related well. Any gas production proceeds
received in excess of our ownership interest are reflected as a liability in the
accompanying balance sheet.
Revenue relating to net undelivered gas production to which we are entitled
but for which we have not received payment are not recorded in the financial
statements until compensation is received. These amounts at December 31, 2000,
1999 and 1998 were immaterial.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
From time to time, we utilize hedging activities to reduce the effect of
commodity price volatility. These transactions are accounted for as increases or
decreases in revenue from oil and gas production in the financial statements
(See Note 9).
INCOME TAXES:
Income taxes are accounted for in accordance with SFAS No. 109, "Accounting
for Income Taxes." Provisions for income taxes include deferred taxes resulting
primarily from temporary differences due to different reporting methods for oil
and gas properties for financial reporting purposes and income tax purposes. For
financial reporting purposes, all exploratory and development expenditures are
capitalized and depreciated, depleted and amortized on the future gross revenue
method. For income tax purposes, only the equipment and leasehold costs relative
to successful wells are capitalized and recovered through depreciation or
depletion. Generally, most other exploratory and development costs are charged
to expense as incurred; however, we follow certain provisions of the Internal
Revenue Code that allow capitalization of intangible drilling costs where
management deems appropriate. Other financial and income tax reporting
differences occur as a result of statutory depletion, different reporting
methods for sales of oil and gas reserves in place, and different reporting
methods used in the capitalization of general and administrative expenses.
NEW ACCOUNTING STANDARDS:
We adopted SFAS No. 133 effective January 1, 2001. Under SFAS No. 133, as
amended, the nature of a derivative instrument must be evaluated to determine if
it qualifies for special hedge accounting treatment. If the instrument qualifies
for hedge accounting treatment, it would be recorded as either an asset or
liability measured at fair value and subsequent changes in the derivative's fair
value would be recognized in equity through other comprehensive income, to the
extent the hedge is considered effective. If the derivative does not qualify for
hedge accounting treatment, it would be recorded in the balance sheet and
changes in fair value would be recognized in earnings.
At December 31, 2000, the only derivative instruments we had in place were
puts which, to the extent of changes in time value, do not meet the
"effectiveness" criteria for special hedge accounting treatment. These puts were
reflected as assets in our December 31, 2000 balance sheet at a historical cost
of $3,587. At year-end 2000, the fair value of our puts was $5,478. If we had
adopted SFAS No. 133 during 2000, we would have marked the puts to market by
recording a gain of $1,891 in earnings.
Upon adoption of SFAS No. 133, the increase in fair value over historical
cost of $1,891 was recorded as a transition adjustment. We recorded the gain in
equity through other comprehensive income. As each put contract expires, we will
recognize the related portion of the transition adjustment in earnings.
MERGER WITH BASIN EXPLORATION:
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination,
through a pooling of interests, of the two companies in a tax-free,
stock-for-stock transaction. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25,000,000 to 100,000,000 shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. As such, Stone issued
7,436,652 shares of common stock which, based upon Stone's closing price of
$53.70 on February 1, 2001, resulted in total equity value related to the
transaction of
NOTE 1-- ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:(Continued)
approximately $400,000. In addition, Stone assumed, and subsequently retired
with cash on hand, approximately $48,000 of Basin bank debt. The expenses
incurred in relation to the merger are currently estimated to total
approximately $27,000 and will be a non-recurring item recorded in the first
quarter of 2001. At December 31, 2000, approximately $840 of these expenses were
recorded in other assets in the balance sheet. See "Note 15 - Supplemental
Combined Financial Statements - Unaudited", "Note 16 - Supplemental Combined
Hedging Position - Unaudited" and "Note 17 - Supplemental Combined Commitments
and Contingencies - Unaudited."
NOTE 2 -- ACCOUNTS RECEIVABLE:
In our capacity as operator for our co-venturers, we incur drilling and
other costs that we bill to the respective parties based on their working
interests. We also receive payments for these billings and, in some cases, for
billings in advance of incurring costs. Our accounts receivable was comprised of
the following amounts:
December 31,
-------------------------------------
2000 1999
---------------- ----------------
Accounts Receivable:
Other co-venturers.................. $8,991 $6,019
Trade............................... 53,609 23,270
Officers and employees.............. 3 27
Unbilled accounts receivable........ 211 413
---------------- ----------------
$62,814 $29,729
================ ================
NOTE 3 -- CONCENTRATIONS:
Sales to Major Customers
Our production is sold on month-to-month contracts at prevailing prices. The
following table identifies customers to whom we sold 10% or more of our total
oil and gas revenue during each of the twelve-month periods ended:
December 31,
---------------------------
2000 1999 1998
---- ---- ----
BP Amoco Energy Company............ - - 14%
Columbia Energy Services........... - 28% -
Conoco, Incorporated .............. - - 24%
El Paso Merchant Energy, LP........ 20% 12% -
Enron North America Corporation.... 16% - -
Genesis Crude Oil LP............... - 12% -
Northridge Energy Marketing........ - 22% 14%
Williams-Gulfmark Energy Co........ 10% - -
Since alternative purchasers of oil and gas are readily available, we
believe that the loss of any of these purchasers would not result in a material
adverse effect on our ability to market future oil and gas production.
Production Volumes
Production from South Pelto Block 23 and Eugene Island Block 243 accounted
for approximately 26% and 23%, respectively, of our total oil and gas production
volumes during 2000.
NOTE 4 -- INVESTMENT IN OIL AND GAS PROPERTIES:
The following table discloses certain financial data relative to our oil and
gas producing activities, which are located onshore and offshore the continental
United States:
Year Ended December 31,
--------------------------------------------------
2000 1999 1998
------------- -------------- --------------
Oil and gas properties--
Balance, beginning of year................................ $728,501 $604,591 $445,709
Costs incurred during year:
Capitalized--
Acquisition costs..................................... 10,803 31,046 17,748
Exploratory drilling.................................. 87,510 32,117 81,765
Development drilling.................................. 57,231 53,463 54,889
General and administrative costs and interest......... 9,669 7,753 5,416
Less: overhead reimbursements......................... (523) (469) (936)
-------------- -------------- --------------
Total costs incurred during year (1).................. 164,690 123,910 158,882
-------------- -------------- --------------
Balance, end of year...................................... $893,191 $728,501 $604,591
============== ============== ==============
Charged to expense--
Operating Costs:
Normal lease operating expenses..................... $26,964 $22,625 $18,042
Major maintenance expenses.......................... 6,538 1,115 1,278
-------------- -------------- --------------
Total operating costs................................. 33,502 23,740 19,320
Production taxes...................................... 5,731 2,019 2,083
-------------- -------------- --------------
$39,233 $25,759 $21,403
============== ============== ==============
Unevaluated oil and gas properties--
Costs incurred during year:
Acquisition costs................................... $4,517 $10,059 $5,410
Exploration costs................................... 6,229 806 -
-------------- -------------- --------------
$10,746 $10,865 $5,410
============== ============== ==============
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year............................ ($375,360) ($310,767) ($154,289)
Provision for depreciation, depletion and amortization (73,200) (64,593) (67,334)
Write-down of oil and gas properties.................. - - (89,135)
Sale of reserves...................................... - - (9)
-------------- -------------- --------------
Balance, end of year...................................... (448,560) (375,360) (310,767)
============== ============== ==============
Net capitalized costs (proved and unevaluated)................ $444,631 $353,141 $293,824
============== ============== ==============
DD&A per Mcfe................................................. $1.10 $1.10 $1.33
============== ============== ==============
(1) Total costs incurred during 1999 included non-cash additions of $20,272
related to acquisitions made through production payments.
NOTE 4-- INVESTMENT IN OIL AND GAS PROPERTIES: (Continued)
The following table discloses financial data associated with unevaluated
costs as of December 31, 2000:
Balance at Costs incurred during the
December 31, 2000 year ended December 31,
-------------------- -----------------------------------------------------
2000 1999 1998 1997
--------- ---------- --------- --------
Acquisition costs................ $14,298 $4,517 $6,693 $2,701 $387
Exploration costs................ 6,229 6,229 - - -
-------------------- --------- ---------- -------- ---------
Total unevaluated costs...... $20,527 $10,746 $6,693 $2,701 $387
==================== ========= ========== ======== =========
NOTE 5 -- INCOME TAXES:
We follow the provisions of SFAS No. 109, "Accounting For Income Taxes,"
which provides for recognition of deferred taxes for deductible temporary timing
differences, operating loss carryforwards, statutory depletion carryforwards and
tax credit carryforwards net of a "valuation allowance." An analysis of our
deferred tax liability follows:
Year Ended December 31,
---------------------------
2000 1999
---------- ---------
Net operating loss carryforward............. $1,758 $5,579
Statutory depletion carryforward............ 3,921 4,181
Contribution carryforward................... 112 80
Capital loss carryforward................... 43 -
Alternative minimum tax credit carryforward. 864 420
Temporary differences:
Oil and gas properties-- full cost..... (50,530) (11,150)
Other.................................. 187 224
Valuation allowance.................... - (80)
---------- ----------
($43,645) ($746)
========== ==========
For tax reporting purposes, operating loss carryforwards totaled $5,024 at
December 31, 2000. If not utilized, such carryforwards would begin expiring in
2012 and would completely expire by the year 2020. In addition, we had $12,222
in statutory depletion deductions available for tax reporting purposes that may
be carried forward indefinitely. Recognition of a deferred tax asset associated
with these carryforwards is dependent upon our evaluation that it is more likely
than not that the asset will ultimately be realized.
During 1999, our provision for income taxes was net of a $1,460 reduction in
deferred taxes relative to estimates of tax basis that were resolved during
1999. Reconciliations between the statutory federal income tax expense rate and
our effective income tax expense rate as a percentage of income before income
taxes were as follows:
Year Ended December 31,
-------------------------------
2000 1999 1998
---- ---- ----
Income tax expense (benefit) computed at the
statutory federal income tax rate...... 35% 35% (35%)
Reduction in deferred taxes................ - (4%) -
----- ---- ----
Effective income tax rate.................. 35% 31% (35%)
===== ==== ====
NOTE 6-- PRODUCTION PAYMENTS:
In June 1999, we acquired a 100% working interest in the Lafitte Field by
executing an agreement that included a dollar-denominated production payment to
be satisfied through the sale of production from the purchased property. At that
time, we recorded a production payment of $4,600 representing the estimated
discounted present value of production payments to be made. As provided for in a
separate agreement, on September 23, 1999, Goodrich Petroleum Company, L.L.C.
exercised its option to participate for a 49% working interest in the Lafitte
Field resulting in a reduction of the production payment to $2,346 at September
30, 1999. At December 31, 2000, the production payment associated with this
transaction totaled $1,943.
In July 1999, we acquired an additional working interest in East Cameron
Block 64 and a 100% working interest in West Cameron Block 176 in exchange for a
volumetric production payment. This agreement requires that 7.3 MMcf of gas per
day be delivered to the seller from South Pelto Block 23 until 8 Bcf of gas have
been distributed. At the transaction date, we recorded a volumetric production
payment of $17,926 representing the estimated discounted cash flows associated
with the specific production volumes to be delivered. We amortize the volumetric
production payment as specified deliveries of gas are made to the seller and
recognize non-cash revenue in the form of gas production revenue. At December
31, 2000, the volumetric production payment was $8,963 and $5,975 had been
recognized as gas revenue during 2000.
NOTE 7 -- LONG-TERM DEBT:
At December 31, 2000 and 1999, long-term debt consisted of $100,000 8-3/4%
Senior Subordinated Notes due 2007 and there were no minimum principal payments
due for the next five years.
In September 1997, we completed an offering of $100,000 principal amount
8-3/4% Senior Subordinated Notes (the "Notes") due September 15, 2007 with
interest payable semiannually. At December 31, 2000, $2,601 had been accrued in
connection with the March 2001 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 our bank credit facility
and for other general corporate purposes. There are no sinking fund requirements
on the Notes and they are redeemable at our option, in whole or in part, at
104.375% of their principal amount beginning September 15, 2002, and thereafter
at prices declining annually to 100% on and after September 15, 2005. Provisions
of the Notes include, without limitation, restrictions on liens, indebtedness,
asset sales, dividend payments and other restricted payments.
On August 3, 1999, we used a portion of the net proceeds from a stock
offering (See Note 10) to repay the outstanding borrowings under our credit
facility. At December 31, 2000, the borrowing base under the facility had no
outstanding borrowings and outstanding letters of credit totaling $7,522 had
been issued pursuant to the facility. In February 2000, our bank group increased
our credit facility from $150,000 to $200,000 and extended the maturity date
from July 30, 2001 to July 30, 2005. The borrowing base limitation is
re-determined periodically and is based on a borrowing base amount established
by the banks for our oil and gas properties. The terms of this agreement
contain, among other provisions, requirements for maintaining defined levels of
working capital and tangible net worth.
NOTE 8 -- TRANSACTIONS WITH RELATED PARTIES:
James H. Stone and Joe R. Klutts, both directors of Stone Energy,
collectively own 9% of the working interest in certain wells drilled on Section
19 on the east flank of Weeks Island Field. These interests were acquired at the
same time that our predecessor company acquired its interests in Weeks Island
Field. In their capacity as working interest owners, they are required to pay
their proportional share of all costs and are entitled to receive their
proportional share of revenues.
Our interests in certain oil and gas properties are burdened by various net
profit interests granted at the time of acquisition to certain of our officers
and other employees. Such net profit interest owners do not receive any cash
distributions until we have recovered all acquisition, development, financing
and operating costs. We believe the estimated value of these interests at the
time of acquisition is not material to our financial position or results of
operations. Effective January 1, 2001, we acquired the net profit interests from
our employees through a final settlement payment and discontinued this benefit
program. Certain of our officers remain net profit interest owners.
We received certain fees as a result of our function as managing partner of
certain partnerships. These partnerships were dissolved on December 31, 1999.
All participants in the partnerships, including two of our directors, James H.
Stone and Joe R. Klutts, received overriding royalty interests in the related
properties in exchange for their partnership interests. For the years ended
December 31, 1999 and 1998, management fees and overhead reimbursements from
partnerships totaled $224 and $834, respectively, the majority of which was
treated as a reduction of our investment in oil and gas properties.
NOTE 8-- TRANSACTIONS WITH RELATED PARTIES: (Continued)
Until their dissolution, we collected and distributed production revenue as
managing partner for the partnerships' interests in oil and gas properties.
In June 2000, we purchased property, that adjoins our Lafayette office, from
StoneWall Associates for an independently appraised value of approximately $540.
Two of our directors, James H. Stone and Joe R. Klutts, are partners of
StoneWall Associates.
The law firm of Gordon, Arata, McCollam, Duplantis and Eagan, of which B.J.
Duplantis, one of our directors and Audit Committee members, is a Senior
Partner, provided legal services for us during 2000. The value of these services
totaled approximately $9.
Laborde Marine Lifts, Inc., a company in which John P. Laborde, one of our
directors and Audit Committee members, is Chairman of, provided services to us
during 2000. The value of these services was approximately $75.
NOTE 9 -- HEDGING ACTIVITIES:
We enter into futures contracts to hedge a portion of our production
volumes. These futures contracts are considered to be hedging activities and, as
such, monthly settlements of these contracts are reflected in revenue from oil
and gas production. Under generally accepted accounting principals in effect at
year-end 2000, in order to consider these futures contracts as hedges, (i) we
must designate the futures contract as a hedge of future production and (ii) the
contract must reduce our 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, we will record the market value of the contract at the end of each
month and recognize a related increase or decrease in oil and gas revenue. Any
proceeds received or paid related to terminated contracts or contracts that have
been sold are amortized over the original contract period and reflected in
revenue from oil and gas production. We enter into hedging transactions to
secure 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 our exposure to the possibility of declining oil and gas prices during
the term of the hedge. We do not enter into hedging transactions for trading
purposes.
At December 31, 2000, the only hedging contracts we had in place were oil
puts. Put contracts are not costless; they are purchased at a rate per unit of
hedged production that fluctuates with the commodity futures market. The
historical cost of the put contracts represents our maximum cash exposure. We
are not obligated to make any further payments under the put contracts
regardless of future commodity price fluctuations. Our oil puts were reflected
as assets in our December 31, 2000 balance sheet at a historical cost of $3,587.
Under put contracts, monthly payments are made to us if NYMEX prices fall
below the agreed upon floor price, while allowing us to fully participate in
commodity prices above that floor. Oil contracts typically settle using the
average of the daily closing prices for a calendar month. Since our properties
are located in the Gulf Coast Basin, we believe that fluctuations in NYMEX
prices will closely match changes in market prices for our production.
At December 31, 2000, our open hedge positions were:
Puts
----------------------------------------
Oil
----------------------------------------
Volume
(Bbls) Floor Cost
------------ ------------ ----------
2001................... 912,500 $25.00 $1,329
2002................... 912,500 $24.00 $2,258
At December 31, 2000, the fair market value of these put contracts was
$5,478 resulting in an unrealized gain of $1,891. This gain was not reflected in
our financial statements at December 31, 2000 because we did not adopt SFAS No.
133, "Accounting for Derivative Instruments and Hedging Activities," until
January 1, 2001.
For the years ended December 31, 2000, 1999 and 1998, we realized net
increases (decreases) in oil and gas revenue related to hedging transactions of
($36,254), ($4,329) and $4,265, respectively.
For information regarding our combined hedging position at February 23, 2001
see "Note 16 - Supplemental Combined Hedging Position - Unaudited".
NOTE 10 -- COMMON STOCK:
In connection with the Basin merger, our stockholders approved a proposal on
February 1, 2001 to amend our certificate of incorporation in order to increase
the number of authorized shares of our common stock from 25,000,000 to
100,000,000.
On July 28, 1999, we completed an offering of 3,162,500 shares of our common
stock at a price to the public of $43.75 per share. After payment of the
underwriting discount and estimated expenses, we received net proceeds of
$130,760. The proceeds were used to fund specifically identified exploration and
development activities, to finance property acquisitions and for other general
corporate purposes. We reduced indebtedness under our credit facility pending
such uses.
During 1998, our Board of Directors authorized the adoption of a stockholder
rights plan to protect and advance our interests and those of our stockholders
in the event of a proposed takeover. The plan provides for the issuance of one
right for each outstanding share of common stock. The rights will become
exercisable only if a person or group acquires 15% or more of our outstanding
voting stock or announces a tender or exchange offer that would result in
ownership of 15% or more of our voting stock. The rights were issued on October
26, 1998 to stockholders of record on that date, and expire on September 30,
2008.
NOTE 11 -- COMMITMENTS AND CONTINGENCIES:
We currently lease office facilities in New Orleans, Louisiana and Houston,
Texas under the terms of long-term, non-cancelable leases expiring on April 4,
2003 and May 31, 2006, respectively. We also lease automobiles under the terms
of non-cancelable leases expiring at various dates through 2003. The minimum net
annual commitments under all leases, subleases and contracts noted above at
December 31, 2000 were as follows:
2001........................... $465
2002........................... 463
2003........................... 386
2004........................... 380
2005........................... 391
Thereafter..................... 98
Payments related to our lease obligations for the years ended December 31,
2000, 1999 and 1998 were approximately $415, $268 and $132, respectively.
Until December 31, 1999, we were the managing general partner of eight
partnerships and are contingently liable for any recourse debts and other
liabilities that resulted from their operations until dissolution. We are not
aware of the existence of any such liabilities that would have a material impact
on future operations.
In August 1989, we were advised by the EPA that it believed we were 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 we 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 cleanup
costs on 23 of the PRP's, including us, who had not previously settled with the
EPA. Since that time we, together with other PRPs, have been negotiating the
settlement of our respective liability for environmental conditions at this site
with the U.S. Department of Justice. Given the number of PRP's at this site and
the current satisfactory progress of these negotiations, we do not believe that
any liability for this site would have a material adverse affect on our
financial condition. A tentative settlement has been reached with the U.S.
Department of Justice regarding our potential liability at this site. The amount
of this tentative settlement is immaterial to our financial statements and was
not accrued at December 31, 2000. However, the settlement has not been formally
approved by all parties, and we cannot assure you that a settlement will be
formally approved.
We are contingently liable to a surety insurance company in the aggregate
amount of $14,846 relative to bonds issued on our behalf to the MMS and certain
third parties from which we purchased oil and gas working interests. The bonds
represent guarantees by the surety insurance company that we 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 agreements.
We are also named as a defendant in certain lawsuits and are a party to
certain regulatory proceedings arising in the ordinary course of business. We do
not expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
NOTE 11-- COMMITMENTS AND CONTINGENCIES: (Continued)
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and the MMS's August 1998 final rule,
responsible parties of offshore facilities must 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. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
For information regarding the combined company's commitments and
contingencies see "Note 17 - Supplemental Combined Commitments and Contingencies
- - Unaudited."
NOTE 12 -- EMPLOYEE BENEFIT PLANS:
We have entered into deferred compensation and disability agreements with
certain of our employees whereby we have purchased split-dollar life insurance
policies to provide certain retirement and death benefits for our employees and
death benefits payable to us. The aggregate death benefit of the policies was
$3,204 at December 31, 2000, of which $1,975 was payable to employees or their
beneficiaries and $1,229 was payable to us. Total cash surrender value of the
policies, net of related surrender charges at December 31, 2000, was
approximately $1,021. Additionally, the benefits under the deferred compensation
agreements vest after certain periods of employment, and at December 31, 2000,
the liability for such vested benefits was approximately $847. The difference
between the actuarial determined liability for retirement benefits or the vested
amounts, where applicable, and the net cash surrender value has been recorded as
an other long-term asset.
We have adopted a series of incentive compensation plans designed to align
the interests of our directors and employees with those of our stockholders. The
following is a brief description of each of the plans:
i. The Annual Incentive Compensation Program provides for an annual cash
incentive bonus that ties incentives to the annual return on our common
stock, to a comparison of the price performance of our common stock to
the average quarterly returns on the shares of stock of a peer group of
companies with which we compete and to the growth in our net earnings,
net cash flows and net asset value. Incentive bonuses are awarded to
participants based upon individual performance factors.
ii. The Nonemployee Directors' Stock Option Plan provides for the issuance
of up to 275,000 shares of common stock upon the exercise of such
options granted pursuant to this 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 2000 Amended and Restated Stock Option Plan provides for 2,500,000
shares of common stock to be reserved for issuance pursuant to this
plan. Under this plan, we may grant both incentive stock options
qualifying under Section 422 of the Internal Revenue Code and options
that are not qualified as incentive stock options to all employees. 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 we may,
at our discretion, match a portion or all of the employee's deferral.
The amounts held under the plan are invested in various investment
funds maintained by a third party in accordance with the directions of
each employee. An employee is 20% vested in matching contributions (if
any) for each year of service and is fully vested upon five years of
service. For the years ended December 31, 2000, 1999 and 1998, we
contributed $445, $313 and $270, respectively, to the plan.
During the third quarter of 1998, our Board of Directors elected to reprice
all non-Director employee stock options that 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.
NOTE 12-- EMPLOYEE BENEFIT PLANS: (Continued)
In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation," which became effective with respect to us in 1996. Under SFAS No.
123, companies can either record expense based on the fair value of stock-based
compensation upon issuance or elect to remain under the current Accounting
Principles Board Opinion No. 25 ("APB 25") method whereby no compensation cost
is recognized upon grant if certain requirements are met. We have continued to
account for our stock-based compensation under APB 25. However, disclosures as
if we adopted the cost recognition requirements under SFAS No. 123 are presented
below.
If the compensation cost for stock-based compensation plans had been
determined consistent with SFAS No. 123, our 2000, 1999 and 1998 net income
(loss) and basic and diluted earnings (loss) per common share would have
approximated the pro forma amounts below:
Year Ended December 31,
-------------------------------------------------------------------------------------
2000 1999 1998
------------------------- ------------------------- -------------------------
As Reported Pro Forma As Reported Pro Forma As Reported Pro Forma
------------- ----------- ------------- ----------- ------------- -----------
Net income (loss)............. $84,945 $81,260 $26,490 $24,599 ($51,631) ($53,141)
Earnings (loss) per common
share:
Basic................... $4.60 $4.40 $1.61 $1.49 ($3.43) ($3.53)
Diluted................. $4.51 $4.32 $1.58 $1.47 ($3.43) ($3.53)
A summary of stock options as of December 31, 2000, 1999 and 1998 and
changes during the years ended on those dates is presented below.
Year Ended December 31,
--------------------------------------------------------------------------------------------
2000 1999 1998
---------------------------- ---------------------------- --------------------------
Wgtd. Wgtd. Wgtd.
Number Avg. Number Avg. Number Avg.
of Exer. of Exer. of Exer.
Options Price Options Price Options Price
--------------- -------- --------------- --------- ------------ ----------
Outstanding at beginning of year.... 1,277,700 $25.54 1,035,000 $19.90 960,000 $18.62
Granted............................. 385,000 56.38 369,250 38.17 100,000 30.43
Expired............................. (13,000) 23.95 (23,000) 22.29 - -
Exercised........................... (207,417) 18.42 (103,550) 14.86 (25,000) 13.00
--------------- --------------- ------------
Outstanding at end of year.......... 1,442,283 $34.81 1,277,700 $25.54 1,035,000 $19.90
Options exercisable at year-end..... 579,933 21.78 552,650 18.11 481,800 16.01
Options available for future grant.. 957,750 299,750 346,000
Weighted average fair value of
options granted during the year.. $30.20 $24.01 $21.23
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
45.43%, 41.59% and 43.90% in the years 2000, 1999 and 1998, respectively, (c)
risk-free interest rate of 6.78%, 6.32% and 5.50% in the years 2000, 1999 and
1998, respectively and (d) expected life of six years for employee options and
four years for director options.
NOTE 12-- EMPLOYEE BENEFIT PLANS: (Continued)
The following table summarizes information regarding stock options
outstanding at December 31, 2000:
Options Outstanding Options Exercisable
------------------------------------------------ ------------------------
Range of Options Wgtd. Avg. Wgtd. Avg. Options Wgtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/00 Contractual Life Price at 12/31/00 Price
------ ------------ ---------------- ----- ----------- -----
$11 - $20 209,033 3.9 years $12.54 209,033 $12.54
20 - 30 464,750 6.0 years 24.01 281,350 23.50
30 - 40 322,000 7.9 years 35.99 73,550 36.04
40 - 50 81,250 8.7 years 45.25 14,000 45.67
50 - 61.93 365,250 8.9 years 57.95 2,000 53.00
------------- -----------
1,442,283 7.0 years 34.81 579,933 21.78
============= ===========
After converting Basin's outstanding stock options to Stone stock options at
the exchange ratio of 0.3974 of a share of Stone common stock for each share of
Basin common stock, Stone assumed approximately 348,000 stock options with a
weighted average exercise price of $33.15 per share. These converted stock
options are not reflected in the tables above.
NOTE 13 -- OIL AND GAS RESERVE INFORMATION - UNAUDITED:
The majority of our net proved oil and gas reserves at December 31, 2000
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the market value of the oil and gas properties or the
cost that would be incurred to obtain equivalent reserves.
NOTE 13-- OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
The following table sets forth an analysis of the estimated quantities of
net proved and proved developed oil (including condensate) and natural gas, all
of which are located onshore and offshore the continental United States:
Oil in Natural Gas
MBbls in MMcf
------------- -------------
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
Revisions of previous estimates......................................... 871 2,479
Extensions, discoveries and other additions............................. 1,828 24,048
Purchase of producing properties........................................ 4,930 18,597
Production (1).......................................................... (3,469) (36,780)
------------- -------------
Proved reserves as of December 31, 1999..................................... 22,636 251,614
Revisions of previous estimates......................................... (1,838) 11,744
Extensions, discoveries and other additions............................. 3,801 45,299
Purchase of producing properties........................................ 54 7,394
Production (1).......................................................... (3,334) (43,813)
------------- -------------
Proved reserves as of December 31, 2000..................................... 21,319 272,238
============= =============
Proved developed reserves:
as of December 31, 1998................................................. 15,242 200,973
============= =============
as of December 31, 1999................................................. 17,729 205,345
============= =============
as of December 31, 2000................................................. 17,073 221,433
============= =============
(1) Excludes gas production volumes related to the volumetric production
payment. See "Note 6 - Production Payments."
The following tables present the standardized measure of future net cash
flows related to proved oil and gas reserves together with changes therein, as
defined by the FASB. You should not assume that the future net cash flows or the
discounted future net cash flows, referred to in the table below, represent the
fair value of our estimated oil and gas reserves. As required by the SEC, we
determine future cash flows using market prices for oil and gas on the last day
of the fiscal period. The average 2000 year-end product prices for all of our
properties were $28.01 per barrel of oil and $10.13 per Mcf of gas. During the
first quarter of 2001, the market prices for oil and gas have generally
decreased, which would result in a reduction of future cash flows if recomputed.
Future production and development costs are based on current costs with no
escalations. Estimated future cash flows net of future income taxes have been
discounted to their present values based on a 10% annual discount rate.
NOTE 13-- OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
Standardized Measure
Year Ended December 31,
----------------------------------------------------------
2000 1999 1998
---------------- --------------- ---------------
Future cash flows.............................................. $3,355,621 $1,189,275 $670,361
Future production and development costs........................ (417,055) (386,945) (281,920)
Future income taxes............................................ (961,189) (156,496) (22,409)
---------------- --------------- ---------------
Future net cash flows.......................................... 1,977,377 645,834 366,032
10% annual discount............................................ (595,526) (180,755) (97,584)
---------------- --------------- ---------------
Standardized measure of discounted future net cash flows....... $1,381,851 $465,079 $268,448
================ =============== ===============
Changes in Standardized Measure
Year Ended December 31,
-------------------------------------------------------
2000 1999 1998
-------------- ------------ -----------
Standardized measure at beginning of year...................... $465,079 $268,448 $296,340
Sales and transfers of oil and gas produced, net of
production costs........................................... (247,454) (118,172) (93,194)
Changes in price, net of future production costs............... 1,252,924 246,053 (156,107)
Extensions and discoveries, net of future production
and development costs...................................... 333,185 54,820 111,828
Changes in estimated future development costs, net of
development costs incurred during the period............... 38,679 9,808 22,923
Revisions of quantity estimates................................ 3,873 13,937 (3,548)
Accretion of discount.......................................... 56,130 28,610 36,863
Net change in income taxes..................................... (551,300) (79,789) 55,852
Purchase of reserves in place.................................. 48,752 58,655 10,321
Changes in production rates due to timing and other............ (18,017) (17,291) (12,830)
-------------- ------------ ------------
Standardized measure at end of year............................ $1,381,851 $465,079 $268,448
============== ============ ============
NOTE 14 -- SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
Basic Diluted
Net Earnings Earnings
Revenues Expenses Income Per Share Per Share
------------- ------------- ------------- ------------- -------------
2000
First Quarter........... $48,140 $35,930 $12,210 $0.67 $0.65
Second Quarter.......... 59,635 41,848 17,787 0.97 0.94
Third Quarter........... 72,769 48,500 24,269 1.31 1.29
Fourth Quarter.......... 79,835 49,156 30,679 1.66 1.62
------------- ------------- -------------
$260,379 $175,434 $84,945 4.60 4.51
============= ============= =============
1999
First Quarter........... $30,922 $29,176 $1,746 $0.12 $0.11
Second Quarter.......... 36,273 30,928 5,345 0.35 0.35
Third Quarter........... 41,024 32,736 8,288 0.48 0.47
Fourth Quarter.......... 40,915 29,804 11,111 0.61 0.60
------------- ------------- -------------
$149,134 $122,644 $26,490 1.61 1.58
============= ============= =============
NOTE 15 -- SUPPLEMENTAL COMBINED FINANCIAL STATEMENTS - UNAUDITED:
The following supplemental combined financial statements of Stone and Basin
were prepared using the pooling of interests method of accounting. This
presentation is for information purposes only and does not necessarily reflect
the financial results that would have actually occurred if the two companies had
been combined during this period.
STONE ENERGY CORPORATION
SUPPLEMENTAL COMBINED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)
December 31,
ASSETS 2000
------ -----------------
Current assets:
Cash and cash equivalents................................................... $78,557
Marketable securities, at market............................................ 300
Accounts receivable......................................................... 95,722
Other current assets........................................................ 2,916
Investment in put contracts................................................. 1,847
-----------------
Total current assets...................................................... 179,342
Oil and gas properties, net
Proved...................................................................... 691,882
Unevaluated................................................................. 55,691
Building and land, net.......................................................... 4,914
Fixed assets, net .............................................................. 4,441
Other assets, net............................................................... 4,681
Investment in put contracts..................................................... 3,152
-----------------
Total assets.............................................................. $944,103
=================
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Accounts payable to vendors................................................. $62,802
Undistributed oil and gas proceeds.......................................... 32,858
Other accrued liabilities................................................... 30,617
-----------------
Total current liabilities................................................. 126,277
Long-term debt.................................................................. 148,000
Production payments............................................................. 10,906
Deferred tax liability.......................................................... 64,271
Other long-term liabilities..................................................... 2,418
-----------------
Total liabilities......................................................... 351,872
-----------------
Common stock, $.01 par value; authorized 100,000,000 shares;
issued and outstanding 25,980,590........................................... 260
Paid-in capital................................................................. 440,729
Retained earnings............................................................... 151,242
-----------------
Total stockholders' equity................................................ 592,231
-----------------
Total liabilities and stockholders' equity................................ $944,103
=================
NOTE 15-- SUPPLEMENTAL COMBINED FINANCIAL STATEMENTS - UNAUDITED: (Continued)
STONE ENERGY CORPORATION
SUPPLEMENTAL COMBINED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
Year Ended
December 31,
2000
-----------------
Revenues:
Oil and gas production..................................................... $381,938
Other revenue.............................................................. 4,228
----------------
Total revenues........................................................... 386,166
----------------
Expenses:
Normal lease operating expenses............................................ 41,474
Major maintenance expenses................................................. 6,538
Production taxes........................................................... 7,607
Depreciation, depletion and amortization................................... 110,859
Interest................................................................... 9,395
General and administrative costs........................................... 12,217
Incentive compensation plan................................................ 1,722
Stock compensation, net.................................................... 508
Merger expenses............................................................ 1,297
----------------
Total expenses........................................................... 191,617
----------------
Net income before income taxes ................................................ 194,549
----------------
Income tax provision:
Current.................................................................... 450
Deferred................................................................... 66,126
----------------
Total income taxes....................................................... 66,576
----------------
Net income..................................................................... $127,973
================
Earnings per common share:
Basic earnings per share................................................... $4.96
================
Diluted earnings per share ................................................ $4.86
================
Average shares outstanding................................................. 25,804
================
Average shares outstanding assuming dilution............................... 26,335
================
NOTE 16 -- SUPPLEMENTAL COMBINED HEDGING POSITION - UNAUDITED:
The following table shows the hedging position of the combined company as of
February 23, 2001.
Puts
---------------------------------------------------------------------------------------------
Gas Oil
------------------------------------------- ---------------------------------------------
Volume Volume
(BBtus) Floor Cost (Bbls) Floor Cost
----------- ----------- ----------- ----------- ------------- -------------
2001 (1)................. 22,000 $3.50 $1,265 1,277,500 $25.00 $1,847
2002..................... 21,900 $3.50 $5,201 1,277,500 $24.00 $3,152
(1) The hedged volumes related to the 2001 gas put contracts are from April 2001 - December 2001.
Fixed Price Gas Swaps
---------------------------------------
Volume (BBtus) Price
------------------- ---------------
2001..................... 7,300 $2.33
2002..................... 3,650 $2.15
2003..................... 3,650 $2.15
At December 31, 2000, the oil put contracts were recorded in the
Supplemental Combined Balance Sheet at a historical cost of $4,999 and, in
accordance with generally accepted accounting principles in effect at year-end
2000, the fixed price gas swap contracts were not recorded in the Supplemental
Combined Balance Sheet since they were costless. The gas put contracts were
purchased subsequent to year-end and therefore were not reflected in the
December 31, 2000 balance sheet. At December 31, 2000, the fair values of the
combined company's oil put contracts and fixed price gas swaps were $7,669 and
($43,931), respectively.
SFAS No. 133 was adopted on January 1, 2001. Upon adoption of SFAS No. 133,
as amended, the increase in fair value over historical cost of the combined
company's oil put contracts of $2,670 was a transition adjustment that was
recorded as a gain in equity through other comprehensive income. In addition,
the fair market value of the fixed price gas swaps was recorded in the balance
sheet as a liability and the corresponding loss of $43,931 was recorded in
equity through other comprehensive income.
NOTE 17 -- SUPPLEMENTAL COMBINED COMMITMENTS AND CONTINGENCIES - UNAUDITED:
The combined company leases office facilities in New Orleans, Louisiana,
Denver, Colorado and at two locations in Houston, Texas under the terms of
long-term, non-cancelable leases expiring on April 4, 2003, March 15, 2005 and
December 31, 2004 and May 31, 2006, respectively. The combined company also
leases automobiles under the terms of non-cancelable leases expiring at various
dates through 2003. The minimum net annual commitments under all leases,
subleases and contracts noted above at December 31, 2000 were as follows:
2001........................ $1,165
2002........................ 1,269
2003........................ 1,248
2004........................ 1,268
2005........................ 508
Thereafter.................. 98
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
Bbtu. One billion Btus.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
EBITDA. Represents net income attributable to common stock plus interest,
income taxes, depreciation, depletion and amortization and non-cash ceiling test
write-downs of oil and gas properties.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find and produce oil or gas reserves not
classified as proved, to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir or to extend a known reservoir.
Farmin or farmout. An agreement under which the owner of a working interest
in an oil and gas lease assigns the working interest or a portion thereof to
another party who desires to drill on the leased acreage. Generally, the
assignee is required to drill one or more wells in order to earn its interest in
the acreage. The assignor usually retains a royalty or reversionary interest in
the lease. The interest received by an assignee is a "farmin" while the interest
transferred by the assignor is a "farmout."
Finding costs. Costs associated with acquiring and developing proved oil and
gas reserves which are capitalized pursuant to generally accepted accounting
principles, excluding any capitalized general and administrative expenses.
Gross acreage or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
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.
GLOSSARY OF CERTAIN INDUSTRY TERMS: (Continued)
MMcfe. One million cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
MMcf/d. One million cubic feet of gas per day.
Net acres or net wells. The sum of the fractional working interests owned in
gross acres or gross wells.
Pooling of Interests. An accounting method for business combinations in
which the financial statements and results of operations are prepared as if the
companies had been combined at the beginning of the earliest period shown. In
addition, the assets and liabilities of the combining companies are carried
forward to the combined entity at book value.
Present value. When used with respect to oil and gas reserves, present
value means the estimated future gross revenue to be generated from the
production of proved reserves, net of estimated production and future
development costs, using prices and costs in effect as of the date of the report
or estimate, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax expense
or to depreciation, depletion and amortization, discounted using an annual
discount rate of 10%.
Production payment. An obligation of the purchaser of a property to pay a
specified portion of future gross revenues, less related production taxes and
transportation costs, to the seller of the property.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production 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 production costs.
Tcf. One trillion cubic feet of gas.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Volumetric production payment. An obligation of the purchaser of a property
to deliver a specific volume of production, free and clear of all costs, to the
seller of the property.
Working interest. An operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and to receive a
share of production.
EXHIBIT INDEX
Exhibit
Number Description
2.1 -- Agreement and Plan of Merger, dated as of October 28, 2000, by
and among Stone Energy Corporation, Partner Acquisition Corp.
and Basin Exploration, Inc. (incorporated by reference to
Exhibit 2.1 to the Registrant's Registration Statement on
Form S-4 (Registration No. 333-51968)).
3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on
Form S-1 (Registration No. 33-62362)).
3.3 -- Certificate of Amendment of the Certificate of Incorporation
of Stone Energy Corporation, dated February 1, 2001 (incorporated
by reference to Exhibit 4.1 to the Registrant's Form 8-K, dated
February 7, 2001).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as
of October 15, 1998, between Stone Energy Corporation and
ChaseMellon Shareholder Services, L.L.C., as Rights Agent
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form 8-A (File No. 001-12074)).
4.2 -- Indenture between Stone Energy Corporation and Texas Commerce
Bank, National Association dated as of September 19, 1997
(incorporated by reference to Exhibit 4.1 to the Registrant's
Registration Statement on Form S-4 dated October 22, 1997 (File
No. 333-38425)).
4.3 -- Amendment No. 1, dated as of October 28, 2000, to Rights
Agreement dated as of October 15, 1998, between Stone Energy
Corporation and ChaseMellon Shareholder Services, L.L.C., as
Rights Agent (incorporated by reference to Exhibit 4.4 to the
Registrant's Registration Statement on Form S-4 (Registration
No. 333-51968)).
+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 -- 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)).
+10.5 -- Deferred Compensation and Disability Agreement between TSPC
and E. J. Louviere dated July 16, 1981 (incorporated by
reference to Exhibit 10.10 to the Registrant's Annual Report
on Form 10-K for the year ended December 31, 1995 (File
No. 001-12074)).
10.6 -- 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)).
+10.7 -- Stone Energy Corporation 2000 Amended and Restated Stock
Option Plan (incorporated by reference to Appendix A to the
Registrant's Definitive Proxy Statement on Schedule 14A for
Stone's 2000 Annual Meeting of Stockholders (File No.
001-12074)).
+10.8 -- Stone Energy Corporation Annual Incentive Compensation Plan
(incorporated by reference to Exhibit 10.14 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1993
(File No. 001-12074)).
*+10.9 -- Stone Energy Corporation Amendment to the Annual Incentive
Compensation Plan dated January 15, 1997.
*21.1 -- Subsidiaries of the Registrant.
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*23.4 -- Consent of Ryder Scott Company.
- -----------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.