UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 1999
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the transition period from to
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
State of incorporation: Delaware I.R.S. Employer Identification No. 72-1235413
625 E. Kaliste Saloom Road
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (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 $728,070,912 as of March 15, 2000 (based on
the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
As of March 15, 2000, the registrant had outstanding 18,362,458 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 18,
2000, 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.................................................. 14
Item 3. Legal Proceedings........................................... 17
Item 4. Submission of Matters to a Vote of Security Holders......... 17
Item 4A. Executive Officers of the Registrant........................ 17
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters...................................... 18
Item 6. Selected Financial and Operating Data....................... 19
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.................................... 20
Item 7A. Quantitative and Qualitative Disclosures Regarding
Market Risks................................................ 27
Item 8. Financial Statements and Supplementary Data................. 27
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure..................................... 27
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 27
Item 11. Executive Compensation...................................... 27
Item 12. Security Ownership of Certain Beneficial Owners
and Management........................................... 27
Item 13. Certain Relationships and Related Transactions.............. 27
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K.................................................... 28
Index to Financial Statements............................... F-1
Glossary of Certain Industry Terms.......................... G-1
<PAGE>
PART I
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 8 of this document for an explanation of these types
of assertions. We also use the terms "Stone", "Stone Energy", "Company", "we",
"us", and "our" to refer to Stone Energy Corporation. 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, 1999, we
had estimated proved reserves of approximately 251.6 Bcf of natural gas and 22.6
MMBbls of oil, or an aggregate of approximately 387.4 Bcfe. As of December 31,
1999, the present value of estimated pre-tax net cash flows of our reserves was
$561.3 million (based upon year-end 1999 prices which included the effect of
hedges and a discount rate of 10%). In 1999, we increased production rates 17%
from 1998, we replaced reserves at a rate of 157% and we achieved a drilling
success rate of 93% based on wells completed during the year.
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 433%, cash flow from operations
before working capital changes 468% and proved reserves 308%.
Since implementing our acquisition and exploitation strategy in 1990, we have
acquired interests in 19 fields in the Gulf Coast Basin from major and large
independent oil and gas companies. At December 31, 1999, we served as operator
on all of our 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 15 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 evaluate 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 $0.38 per Mcfe in 1999.
<PAGE>
We have a substantial inventory of exploration and development projects that
we believe provides us with a significant opportunity to increase our reserves
and production from our existing properties. For the year ending December 31,
2000, we have budgeted exploration and development expenditures of $124.3
million, which includes plans to drill 30 new wells, conduct 39
workovers/recompletions on existing wells and, depending upon the success of
specific development activities, install two new offshore production platforms.
Our capital expenditures for 1999 totaled $123.9 million, of which $31 million
related to the evaluation and acquisition of oil and gas properties.
FINANCIAL OVERVIEW
We completed our initial public offering of common stock in July 1993 (the
"Initial Public Offering"), 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, 2000 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, 1999 had a borrowing base availability of
$132.5 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 507% since 1993.
Our net cash flow from operations has also grown consistently since our initial
public offering resulting in per share growth of 241% since 1993 and 18% over
1998.
OIL AND GAS MARKETING
Our oil and natural gas condensate production is sold at current market
prices under short-term contracts providing for variable or market sensitive
prices. From time to time, we may enter into transactions hedging the price of
oil, natural gas and natural gas condensate. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Liquidity and Capital Resources."
COMPETITION AND MARKETS
Competition in the Gulf Coast Basin is intense, particularly with respect to
the acquisition of producing properties and proved undeveloped acreage. We
compete with the major oil companies and other independent producers of varying
sizes, all of which are engaged in the acquisition of properties and the
exploration and development of such properties. Many of 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."
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 these wells would 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 in the Gulf of Mexico, which were
granted by the federal government and are administered by the United States
Department of the Interior Minerals Management Service (the "MMS"). For offshore
operations, lessees must obtain MMS approval 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 United States Environmental Protection Agency (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. On
March 15, 2000, the MMS issued a final rule, to be effective June 1, 2000,
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 areawide bonds have been
required of lessees taking certain actions with regard to OCS leases. Operators
in the OCS waters of the Gulf of Mexico were required to increase their areawide
bonds and individual lease bonds to $3 million and $1 million, respectively,
unless the MMS allowed exemptions or reduced amounts. We currently have an
areawide right-of-way bond for $0.3 million and an areawide operator's bond
totaling $3.0 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.
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 as of 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 the regulations promulgated
thereunder by the FERC. In the past, the Federal government has regulated the
prices at which gas could be sold. While sales by producers of natural gas can
currently be made at uncontrolled market prices, Congress could reenact price
controls in the future. Deregulation of wellhead natural gas sales began with
the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA
price and non-price controls affecting wellhead sales of natural gas effective
January 1, 1993.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B, and
636-C (collectively, "Order No. 636"), which require interstate pipelines to
provide transportation separate, or "unbundled," from the pipelines' sales of
gas. Also, Order No. 636 requires pipelines to provide open-access
transportation on a basis that is equal for all gas suppliers. Although Order
No. 636 does not directly regulate 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 particular, the FERC has recently begun a broad
review of its transportation regulations, including how they operate in
conjunction with state proposals for retail gas market restructuring, whether to
eliminate cost-of-service rates for short-term transportation, whether to
allocate all short-term capacity on the basis of competitive auctions, and
whether changes to its long-term transportation policies may also be appropriate
to avoid a market bias toward short-term contracts.
While any additional FERC action on these matters would affect us only
indirectly, any new rules and policy statements may have the effect of enhancing
competition in natural gas markets by, among other things, encouraging
non-producer natural gas marketers to engage in certain purchase and sale
transactions. We cannot predict what action the FERC will take on these matters,
nor can we accurately predict whether the FERC's actions will achieve the goal
of increasing competition in markets in which our natural gas is sold. However,
we do not believe that 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. To date, the FERC has opted not to
impose the regulations of Order No. 509, in which the FERC implemented the OCSLA
with respect to interstate pipelines, on gatherers and other entities not
subject to the FERC's NGA jurisdiction. The FERC has the authority under the
OCSLA to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the OCS. The FERC recently proposed to
adopt certain reporting requirements applicable (with limited exceptions) to
both gatherers and pipelines operating on the OCS concerning their rates and
terms and conditions of service. The purpose of the proposed requirements is to
provide regulators and other interested parties with sufficient information to
detect, and then seek to remedy, discriminatory conduct in such operations. We
cannot predict the outcome of this proposal or what effect, if any, it may have
on us. If the FERC were to apply Order No. 509 to gatherers in the OCS, and
eliminate the exemption of gathering lines, then these acts could result in a
reduction in available pipeline space for existing shippers in the Gulf of
Mexico.
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. 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. 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.
The Oil Pollution Act ("OPA") and regulations thereunder impose a variety of
regulations on "responsible parties" related to the prevention of oil spills and
liability for damages resulting from such spills in United States waters. A
"responsible party" includes the owner or operator of an onshore facility,
pipeline or vessel, or the lessee or permittee of the area in which an offshore
facility is located. OPA assigns liability to each responsible party for oil
cleanup costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75 million in other damages. Few defenses exist
to the liability imposed by OPA.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties of covered offshore facilities that have
a worst case oil spill of more than 1,000 barrels to demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in federal outer continental shelf waters, with
higher amounts of up to $150 million if a formal risk assessment indicates that
a higher amount should be required based on specific risks posed by the
operations or if the worst case oil-spill discharge volume possible at the
facility may exceed the applicable threshold volumes specified under the MMS's
final rule. On August 11, 1998, the MMS enacted a final rule implementing these
financial responsibility requirements. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under OPA.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
that are considered to be responsible for the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that transported
or disposed or arranged for the transport or disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources, and it is
not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
The EPA has indicated that 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 Federal Water Pollution Control Act ("FWPCA") imposes restrictions and
strict controls regarding the discharge of produced waters and other oil and gas
wastes into navigable waters. Permits must be obtained to discharge pollutants
to waters and to conduct construction activities in waters and wetlands. The
FWPCA and similar state laws provide for civil, criminal and administrative
penalties for any unauthorized discharges of pollutants and unauthorized
discharges of reportable quantities of oil and other hazardous substances. Many
state discharge regulations and the Federal National Pollutant Discharge
Elimination System general permits prohibit the discharge of produced water and
sand, drilling fluids, drill cuttings and certain other substances related to
the oil and gas industry 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.
OPERATIONAL RISKS AND INSURANCE
Our operations are subject to the usual hazards incidental to the drilling
of oil and gas wells, such as cratering, explosions, uncontrollable flows of
oil, gas or well fluids, fires, pollution and other environmental risks. Our
activities are also subject to perils peculiar to marine operations, such as
capsizing, collision, and damage or loss from severe weather. These hazards can
cause personal injury and loss of life, severe damage to and destruction of
property and equipment, pollution or environmental damage and suspension of
operations.
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 is calculated on
estimated annual production volumes at insured prices of $19.00 per barrel of
oil and $2.40 per Mcf of gas. 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. Amounts in excess of base coverages 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 coverage,
which provides coverage for the care, custody and control of wells drilled
and/or completed plus redrill and pollution coverage. The exact amount of
coverage for each well is dependent upon its depth and location.
The occurrence of a significant event, not fully insured or indemnified
against, could materially and adversely affect our financial condition and
operations. Moreover, no assurance can be given that we will be able to maintain
adequate insurance in the future at rates we consider reasonable.
Production from the E and D Platforms at our South Pelto Block 23 Field
accounted for approximately 19% and 18%, respectively, of our total oil and gas
production volumes during 1999. Production from this field accounted for
approximately 39% of our total production for the year.
EMPLOYEES
At March 15, 2000, we had 129 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 publically 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.
In addition, 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, 1999, approximately 20% of our estimated proved reserves were
undeveloped. Undeveloped reserves, by their nature, are less certain. Recovery
of undeveloped reserves requires significant capital expenditures and successful
drilling operations. The reserve data assumes that we will make significant
capital expenditures to develop our reserves. Although we
<PAGE>
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. The effective interest rate at various times and
the risks associated with us or the oil and gas industry in general will affect
the accuracy of the 10% 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 sale 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 $123.9 million during 1999, $158.9 million during
1998 and $148.8 million during 1997. We estimate that our total capital
expenditures for 2000 will be approximately $124.3 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. 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.
<PAGE>
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. 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 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. This
development plan is 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.
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 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.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.
As of December 31, 1999, our long-term debt was $100 million and we had $132.5
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 Oil Pollution
Act of 1990 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, owners and operators of certain defined 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. 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 can be hedged. In addition, such hedges shall not be
longer than one year in duration. These arrangements may include future
contracts on the New York Mercantile Exchange. While intended to reduce the
effects of volatile oil and gas prices, such transactions 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 future 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 collectively own 9% of the working interest
in certain wells drilled on Section 19 on the east flank of the Weeks Island
Field. These interests were acquired at the same time as our predecessor
acquired its interests in the Weeks Island Field. In their capacity as working
interest owners, they are required to pay their proportional share of all costs
and are entitled to receive their proportional share of revenues.
Prior to our Initial Public Offering in 1993, The Stone Petroleum
Corporation had formed partnerships to acquire and manage oil and gas
properties. James H. Stone and Joe R. Klutts both participated in these
partnerships. On December 31, 1999, the partnerships were dissolved and the
working interests were transferred to Stone Energy Corporation. All participants
in the partnerships, including James H. Stone and Joe R. Klutts, received
overriding royalty interests in the related properties in exchange for their
partnership interests.
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 employees and officers with respect to the drilling of additional wells
or other development operations.
<PAGE>
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 oil companies. During 1999,
we acquired working interests in four new fields and increased our ownership
interests in three existing fields. As a result, at December 31, 1999, we
operated all of our 19 properties, twelve of which are in the Gulf of Mexico
offshore Louisiana, and seven of which are onshore Louisiana. On December 31,
1999, we dissolved eight partnerships that were formed prior to our Initial
Public Offering and owned less than 5% of our assets.
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, 1999. Net revenue and net cash flow amounts include
the effects of hedging contracts. The proved natural gas reserves at December
31, 1999 excluded 6.7 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 $16.6 million and $14.8 million,
respectively.
All information in this Form 10-K relating to estimated oil and gas reserves
and the estimated future net cash flows attributable thereto is based upon the
reserve reports (the "Reserve Reports") prepared as of December 31, 1999 by
Atwater Consultants, Ltd. and Cawley, Gillespie & Associates, Inc., both
independent petroleum engineers. Using the information contained in the Reserve
Reports, the average 1999 year-end product prices, including the effects of
hedging, for all of our properties were $25.07 per barrel of oil and $2.47 per
Mcf of gas. All product pricing and cost estimates used in the Reserve Reports
are in accordance with the rules and regulations of the Securities and Exchange
Commission, and, except as otherwise
<PAGE>
indicated, the reported amounts give no effect to federal or state income taxes
otherwise attributable to estimated future cash flows from the sale of oil and
gas. The present value of estimated future net cash flows has been calculated
using a discount factor of 10%.
<TABLE>
<CAPTION>
PERCENT
PROVED PROVED TOTAL PROVED
DEVELOPED UNDEVELOPED PROVED DEVELOPED
------------------- ------------------- ---------------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Oil (MBbls).............................. 17,729 4,907 22,636 78%
Gas (MMcf)............................... 205,345 46,269 251,614 82%
Total oil and gas (MMcfe)................ 311,719 75,711 387,430 80%
Estimated future net cash flows before
income taxes........................... $671,265 $131,065 $802,330 84%
Present value of estimated future
net cash flows before income taxes..... $481,982 $79,321 $561,303 86%
</TABLE>
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein 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 on the total reserves
attributable to wells which it operates, without regard to ownership (i.e.,
reserves are reported on a gross operated basis, rather than on a net interest
basis) and disregarding 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.
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------
1999 1998 1997
---------------- ------------------- ---------------
(In thousands)
<S> <C> <C> <C>
Acquisition costs............................................ $31,046 $17,748 $43,791
Development costs............................................ 53,463 54,889 43,762
Exploratory costs............................................ 32,117 81,765 57,770
---------------- ------------------- ---------------
Subtotal............................................... 116,626 154,402 145,323
Capitalized general and administrative costs and
interest, net of fees and reimbursements 7,284 4,480 3,457
---------------- ------------------- ---------------
Total additions to oil and gas properties (1)............ $123,910 $158,882 $148,780
================ =================== ===============
</TABLE>
(1) Total additions to oil and gas properties during 1999 included
non-cash additions of $20.3 million related to acquisitions made
through production payments.
PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain
statistics regarding the number of productive wells and developed and
undeveloped acreage as of December 31, 1999.
Gross Net
------------------ -----------------
Productive Wells:
Oil (1)........................ 87.00 62.46
Gas (2)........................ 64.00 52.17
------------------ -----------------
Total........................ 151.00 114.63
================== =================
Developed Acres:
Onshore Louisiana.............. 3,913.31 3,108.15
Offshore Louisiana............. 11,907.31 9,765.01
------------------ -----------------
Total........................ 15,820.62 12,873.16
================== =================
Undeveloped Acres (3):
Onshore Louisiana.............. 25,265.13 19,096.30
Offshore Louisiana............. 64,505.68 54,825.15
------------------ -----------------
Total........................ 89,770.81 73,921.45
================== =================
(1) 3 gross wells each have dual completions.
(2) 10 gross wells each have dual completions.
(3) Leases covering approximately 1% of our undeveloped acreage will
expire in 2000, 4% in 2001, 3% in 2002, 1% in 2003 and 0% in 2004.
Leases covering the remainder of our undeveloped gross acreage
(91%) are held by production.
DRILLING ACTIVITY. The following table sets forth our drilling activity for
the periods indicated.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------------
1999 1998 1997
--------------------- ---------------------- -------------------------
GROSS NET GROSS NET GROSS NET
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive................. 8.00 5.16 6.00 5.33 10.00 8.70
Nonproductive.............. 1.00 0.31 4.00 3.35 - -
Development Wells:
Productive................. 6.00 4.89 3.00 2.63 2.00 1.26
Nonproductive.............. - - 1.00 0.98 - -
</TABLE>
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.
<PAGE>
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.
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
None.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names, ages (as of
March 15, 2000) and positions held by each of our executive officers. Our
executive officers serve at the discretion of the Board of Directors.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
James H. Stone.................................. 74 Chairman of the Board and Chief Executive Officer
D. Peter Canty.................................. 53 President, Chief Operating Officer and Director
James H. Prince................................. 57 Vice President, Chief Financial Officer and Treasurer
Phillip T. Lalande.............................. 50 Vice President - Engineering
J. Kent Pierret................................. 44 Vice President - Accounting and Controller
Andrew L. Gates, III............................ 52 Vice President - Legal, Secretary and General Counsel
E. J. Louviere.................................. 51 Vice President - Land
Craig L. Glassinger............................. 52 Vice President - Acquisitions
</TABLE>
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.
James H. Stone has served as Chairman of the Board and Chief Executive
Officer since March 1993, as Chairman of the Board of TSPC from 1981 to 1997 and
as President of TSPC from September 1992 to July 1993. Mr. Stone is currently a
director of Newpark Resources, Inc.
D. Peter Canty was named President of the Company in March 1994. He
previously served as Executive Vice President for one year. 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 and was its Chief Geologist from 1987 to
1994.
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 August 1999.
Phillip T. Lalande has served as Vice President - Engineering since March
1995. He served as Operations Manager from July 1993 to March 1995, and as a
consulting engineer to TSPC from 1988 to July 1993.
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.
Andrew L. Gates, III has served as Vice President - Legal, Secretary and
General Counsel since August 1995. Previously, he was a partner in the law firm
of Ottinger, Gates, Hebert & Sikes from 1987 to August 1995.
E. J. Louviere has served as Vice President - Land since June 1995.
Previously, he served as Land Manager of TSPC and us from July 1981 to
June 1995.
Craig L. Glassinger has served as Vice President - Acquisitions since
December 1995. From October 1992 to December 1995 he served TSPC, and us, as
Acquisitions Manager. Prior to joining TSPC, he was a division geologist for
Forest Oil Corporation for approximately ten years.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since July 9, 1993, 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
---------- ---------
1998
First Quarter........................... $39 3/8 $28 9/16
Second Quarter.......................... 40 3/16 31
Third Quarter........................... 36 5/16 20 1/16
Fourth Quarter.......................... 36 7/8 25 3/4
1999
First Quarter........................... $33 1/16 $22 3/4
Second Quarter.......................... 45 31 3/8
Third Quarter........................... 55 5/8 42
Fourth Quarter.......................... 50 15/16 33 3/4
2000
First Quarter (through March 15, 2000).. $50 1/4 $32 1/4
On March 15, 2000, the last reported sales price on the New York Stock
Exchange Composite Tape was $48.00 per share. As of that date there were
approximately 156 holders of record of our Common Stock.
DIVIDEND RESTRICTIONS
We have not in the past, and 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.
<PAGE>
ITEM 6. SELECTED FINANCIAL AND OPERATING DATA
SELECTED HISTORICAL FINANCIAL INFORMATION
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,
1999. This information is derived from our consolidated 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."
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
(In thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil production revenue.................................. $56,969 $38,527 $31,082 $27,788 $24,775
Gas production revenue.................................. 89,950 76,070 37,997 28,051 13,918
Other revenue........................................... 2,215 2,023 1,908 2,126 1,858
------- ------- ------ ------ ------
Total revenues......................................... 149,134 116,620 70,987 57,965 40,551
------- ------- ------ ------ ------
Expenses:
Normal lease operating expenses......................... 22,625 18,042 10,123 8,625 6,294
Major maintenance expenses.............................. 1,115 1,278 1,844 427 446
Production taxes........................................ 2,019 2,083 2,215 3,399 3,057
Depreciation, depletion and amortization................ 65,803 68,187 28,739 19,564 15,719
Write-down of oil and gas properties.................... - 89,135 - - -
Interest expense........................................ 12,840 12,950 4,916 3,574 2,191
General and administrative costs........................ 4,671 4,293 3,903 3,509 3,298
Incentive compensation plan............................. 1,510 763 833 928 85
------- -------- ------ ------ ------
Total expenses......................................... 110,583 196,731 52,573 40,026 31,090
------- -------- ------ ------ ------
Net income (loss) before income taxes.................. 38,551 (80,111) 18,414 17,939 9,461
------- -------- ------ ------ ------
Income tax provision (benefit):
Current................................................. 25 - - 208 131
Deferred................................................ 12,036 (28,480) 6,495 6,698 3,514
------- -------- ------- ------- ------
Total income taxes..................................... 12,061 (28,480) 6,495 6,906 3,645
------- -------- ------- ------- ------
Net income (loss)........................................ $26,490 ($51,631) $11,919 $11,033 $5,816
======= ======== ======= ======= ======
Earnings and dividends per common share:
Basic net income (loss) per common share ............... $1.61 ($3.43) $0.79 $0.90 $0.49
===== ======= ===== ===== =====
Diluted net income (loss) per common share ............. $1.58 ($3.43) $0.78 $0.90 $0.49
===== ======= ===== ===== =====
Cash dividends declared................................. - - - - -
CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes)............. $101,348 $77,211 $47,153 $37,295 $25,049
Net cash provided by operating
activities.............................................. 78,850 85,633 32,679 32,751 27,650
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital ......................................... $22,887 $9,884 $8,328 $6,683 $5,379
Oil and gas properties, net.............................. 353,141 293,824 291,420 171,396 111,248
Total assets ............................................ 441,738 366,390 354,144 209,406 139,460
Long-term debt, less current portion..................... 100,000 209,936 132,024 26,172 47,754
Stockholders' equity .................................... 265,587 105,332 156,637 144,441 66,927
</TABLE>
<PAGE>
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, 1999. Our financial statements and the notes thereto
contain detailed information that should be referred to in conjunction with the
following discussion. See "Item 8. Financial Statements and Supplementary Data."
GENERAL
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. 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.
OPERATING ENVIRONMENT
Our revenue, profitability and future rate of growth are substantially
dependent upon the prevailing prices of, and demand for, oil and natural gas.
Beginning in late 1997 and continuing throughout 1998 and the first quarter of
1999, the oil and gas industry experienced a trend of declines in natural gas
and crude oil prices. The decline in natural gas prices was attributable to
milder-than-normal weather conditions resulting in excess domestic supplies,
while oil prices declined because of higher world supplies coupled with an
anticipated decrease in demand resulting from the overall outlook of the global
economy.
As a result of the worldwide decline in the supply of crude oil caused by
OPEC's self imposed oil production reductions, since the first quarter of 1999,
the price for crude oil has improved significantly. In addition, the price for
natural gas has increased from the first quarter of 1999 because of the market's
perception of lower than normal supplies combined with the expected increase in
future demand. The average prices we received for our production during the
fourth quarter of 1999 totaled $20.95 per barrel and $2.50 per Mcf, as compared
to average prices received during the fourth quarter of 1998 of $11.72 per
barrel and $2.12 per Mcf. All unit pricing amounts include the effects of
hedging.
The demand for and the costs of drilling rigs and related products and
services fluctuates with the prices of oil and natural gas. Therefore, with the
recovery of oil and natural gas prices, the demand for and the costs of drilling
rigs and related services have started to rise and could increase further. In an
attempt to hedge against rising drilling costs, we have in the past entered into
long-term, fixed rate contracts for drilling rigs that are capable of drilling
on all our properties. We expect to be able to finance our 2000 budgeted
operations and development activities with cash flows from operations. If the
costs of drilling related products and services increase substantially from
current levels, we believe that the available borrowings under our credit
facility will be sufficient to fund any capital expenditures in excess of cash
flows from operations.
As a result of fluctuating oil and gas prices and the related effects on oil
and gas companies, there has been an increase in the number of properties
available for acquisition in the Gulf Coast Basin. In addition, the recent
merger and acquisition transactions among both major and independent oil and gas
companies, coupled with the move of many companies to the deep-water region of
the Gulf of Mexico, should increase the supply of properties available for
acquisition in our area of operations. These trends should provide us with
significant opportunities to acquire properties that fit our specific
acquisition profile. While generally it is more expensive to buy properties at
times when oil and natural gas prices have increased, we are somewhat insulated
by our preference to acquire properties with low production rates and cash flows
at the time of purchase.
At present, we do not expect that changes in the rates of overall economic
growth or inflation will significantly impact product prices in the short-term.
Furthermore, because most of the factors that affect the prices we receive for
our production are beyond our control, our marketing efforts are devoted to
achieving the best price available in each geographic location and entering into
a limited amount of fixed price sales and hedging transactions to take advantage
of short-term prices we believe to be attractive.
<PAGE>
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."
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998 1997
------------------ ----------------- -----------------
<S> <C> <C> <C>
PRODUCTION:
Oil (MBbls).................................................... 3,469 2,876 1,585
Gas (MMcf)
Produced excluding volumetric production payment............ 36,780 33,281 14,183
Volumetric production payment............................... 1,333 - -
------------------ ----------------- -----------------
Total gas volumes produced.................................. 38,113 33,281 14,183
Oil and gas (MMcfe)
Produced excluding volumetric production payment............ 57,594 50,537 23,693
Volumetric production payment............................... 1,333 - -
------------------ ----------------- -----------------
Total volumes produced...................................... 58,927 50,537 23,693
AVERAGE SALES PRICES:
Oil (per Bbl).................................................. $16.42 $13.40 $19.61
Gas (per Mcf)
Price excluding volumetric production payment............... $2.36 $2.29 $2.68
Volumetric production payment............................... 2.24 - -
Net average price........................................... 2.36 2.29 2.68
Oil and gas (per Mcfe)
Price excluding volumetric production payment............... $2.50 $2.27 $2.92
Volumetric production payment............................... 2.24 - -
Net average price........................................... 2.49 2.27 2.92
AVERAGE COSTS (PER MCFE):
Normal operating costs........................................... $0.38 $0.36 $0.43
General and administrative....................................... 0.08 0.08 0.16
Depreciation, depletion and amortization......................... 1.10 1.33 1.19
RESERVES AT DECEMBER 31:
Oil (MBbls)...................................................... 22,636 18,476 17,763
Gas (MMcf)....................................................... 251,614 243,270 189,239
Oil and gas (MMcfe).............................................. 387,430 354,126 295,817
Present value of estimated future net cash flows before
income taxes (in thousands)................................. $561,303 $286,098 $368,930
</TABLE>
1999 COMPARED TO 1998. We recognized net income for the year ended December
31, 1999 totaling $26.5 million, or $1.58 per share, as compared to 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 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, as 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 have 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 as compared to net increases of $0.28 per
barrel of oil and $0.10 per Mcf of gas during 1998.
OIL AND GAS REVENUES. Oil and gas revenues reached a record high during
1999. The favorable increases in oil and gas production rates combined with
higher commodity prices resulted in oil and gas revenues increasing 28% to
$146.9 million, compared to oil and gas revenues 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 as 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 operate as a result of the acquisitions of the 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
revenues 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 will
receive in early 2000, a production tax refund of $1 million.
General and administrative expenses for 1999 increased in total to $4.7
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.
Depreciation, depletion and amortization (DD&A) expense on our oil and gas
properties decreased to $64.6 million ($1.10 per Mcfe) compared to $67.3 million
($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.
As a result of the July 1999 stock offering and the subsequent repayment of
all outstanding borrowings under our bank credit facility, interest expense for
1999 decreased to $12.8 million, compared to $13 million during 1998.
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. Oil reserves increased to 22.6 MMBbls
at the end of 1999 from 18.5 MMBbls at the beginning of the year, and 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 reserves were primarily
attributable to drilling results and acquisitions made during the year. The
reserve estimates were prepared by independent petroleum consultants in
accordance with the 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.
1998 COMPARED TO 1997. We recognized a net loss for the year ended December
31, 1998 totaling $51.6 million, or $3.43 per share, as compared to 1997 net
income of $11.9 million, or $0.78 per share. The 1998 results included an
after-tax, non-cash ceiling test write-down of $57.4 million or $3.82 per share.
During December 1997, we initiated production from the D Platform at our
South Pelto Block 23 Field. Production from this structure, together with
production increases at a number of our other fields, generated record levels of
production volumes during 1998. Production volumes during 1998 increased 113%,
on a Mcfe basis, over the previous record 1997 production levels. Production
volumes of both oil and gas during 1998, compared to 1997, rose 81% and 135%,
respectively, totaling 2.9 MMBbls of oil and 33.3 Bcf of gas. Despite a 22%
decrease in the average price received per Mcfe, the growth in production
volumes during 1998 resulted in oil and gas revenues rising to $114.6 million, a
66% increase from 1997 oil and gas revenues of $69.1 million. The average prices
received, net of the effects of hedging contracts, for our production during
1998 were $13.40 per barrel of oil and $2.29 per Mcf of gas, as compared to
$19.61 per barrel and $2.68 per Mcf during 1997.
Normal operating costs increased during 1998 to $18 million compared to
$10.1 million in 1997. The increase was attributable to an increase in the
number of properties and significantly higher production rates. However, on a
unit basis, these costs declined 16% during 1998 to $0.36 per Mcfe from $0.43
per Mcfe in 1997.
Total DD&A expense attributable to oil and gas properties increased during
1998 because of higher production rates, an increased investment in the
properties and lower quarter-end prices. DD&A on oil and gas properties
increased to $67.3 million, or $1.33 per Mcfe, in 1998 from $28.1 million, or
$1.19 per Mcfe, in 1997.
We follow the full cost method of accounting for our oil and gas properties.
Securities and Exchange Commission regulations require that companies using full
cost accounting value their proved year-end reserves based on oil and gas prices
in effect at December 31. As a result of the low oil and gas price environment
at year-end 1998, during the fourth quarter we recognized a ceiling test
write-down on our oil and gas properties totaling $89.1 million, which on an
after-tax basis was $57.4 million. We anticipate that the write-down will
provide a positive impact on future earnings resulting from lower future unit
depreciation expense.
To finance a portion of our 1998 capital expenditures budget, we increased our
borrowings under our bank credit facility during 1998. As a result of these
borrowings and the bond offering closed in September 1997, interest expense
increased to $13 million during 1998, compared to $4.9 million in 1997. Because
of the continued increase in our level of operations during 1998, general and
administrative costs increased in total to $4.3 million. However, on a unit
basis, general and administrative costs declined 50% to $0.08 per Mcfe, compared
with $0.16 per Mcfe in 1997.
At December 31, 1998, our reserves totaled 354.1 Bcfe, a 20% increase from
December 31, 1997 reserves of 295.8 Bcfe. Oil reserves increased to 18.5 MMBbls
at the end of 1998 from 17.8 MMBbls at the beginning of the year, and gas
reserves grew to 243.3 Bcf at December 31, 1998 compared to 189.2 Bcf at
year-end 1997. As a result of the decline in oil and gas prices, the estimated
discounted cash flows from our proved reserves declined 22% from 1997.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Pending the use of proceeds from the stock
offering, in August 1999 we repaid all of the outstanding borrowings under our
revolving credit facility. Net cash flow from operations before working capital
changes for 1999 was $101.3 million, or $6.04 per share, compared to $77.2
million, or $5.12 per share, reported for 1998. Working capital at December 31,
1999 totaled $22.9 million.
CAPITAL EXPENDITURES. Capital expenditures during 1999 totaled $123.9 million
and primarily consisted of exploration and development expenditures at many of
our fields including Eugene Island Block 243, East Cameron Block 64 and
Vermilion Block 255 in addition to acquisition costs primarily for an additional
interest in East Cameron Block 64 and a 100% working interest in West Cameron
Block 176. Capital expenditures for 1999 included $7 million of capitalized
general and administrative costs and $0.3 million of capitalized interest. These
investments were financed by a combination of cash flows from operations and
production payments.
ACQUISITION COSTS. During 1999, we acquired additional interests in three of
our existing fields and completed the acquisition of four new fields. Adjacent
to our South Pelto Block 23, we farmed in a 100% working interest on South
Timbalier Block 71. In May 1999, we acquired an additional 32% working interest
in a portion of the Weeks Island Field for $4.8 million. In June 1999, we
acquired a majority interest and control of operations in the Lafitte Field for
$6.1 million in cash and a production payment to be satisfied through the sale
of production from the purchased property. During September 1999, Goodrich
Petroleum Company, L.L.C. exercised its option to participate for a 49% working
interest in the Lafitte Field resulting in a cash reimbursement to us of
approximately $3 million and a proportional reduction in the production payment.
In June 1999, we acquired from other interest owners their residual interests in
certain formation rights and farmin interests on a 29% working interest and a
24.24% net revenue interest in the Eugene Island Block 243 Field for $0.5
million. In July 1999, we acquired a 62.5% working interest in the East Cameron
Block 64 Field and a 100% working interest in the West Cameron Block 176 Field,
as well as control of operations for both fields, in exchange for a volumetric
production payment of 8 Bcf of gas to be delivered over a three-year period from
the South Pelto Block 23 Field. The accounting for this volumetric production
payment resulted in the recording of a $17.9 million asset based upon the
estimated discounted cash flow associated with the specific production volumes
to be delivered. Finally, in November 1999, we acquired a 100% working interest
in East Cameron Block 46 Field for $1 million. With the 1999 acquisitions, we
now serve as operator on all of our 19 properties.
DEVELOPMENT COSTS. During 1999, we completed numerous development drilling,
workover and recompletion operations and facilities installations in an effort
to develop our property base and to increase cash flow from proved reserves.
During 1999, our development drilling program achieved a 100% success rate
consisting of the Eugene Island Block 243 No. D-1 Well, the OCS-G 1152 No. H-5
and OCS-G 1153 No. D-3 wells at Vermilion Block 255, the Clovelly Corporation
No. 41 and Dereda Thomas No. 1 wells at Clovelly Field and the OCS-G 0775 No. 18
Well at Vermilion Block 131. The year's most significant workover projects
included the OCS-G 0079 No. 1 Well at Vermilion Block 46, the OCS-G 0089 No.
F-6, OCS-G 0089 No. 9 and OCS-G 0089 No. 7 wells at East Cameron Block 64 and
the LL&E No. 189 and Rigolets No. 161 wells at Lafitte Field, four of which were
successful. We also drilled and completed for saltwater injection the Dereda
Thomas No. 2 SWD Well at Clovelly Field and upgraded the production facilities
at several fields to accommodate additional production from discoveries.
EXPLORATORY COSTS. In an effort to provide additions to our existing oil
and gas reserve base, during 1999, we completed drilling operations on nine
exploratory wells, eight of which were successful. These eight wells included
the OCS-G 2899 No. A-7 Well at Eugene Island Block 243's Orca 2 Prospect, the
OCS-G 0775 No. 19 Well at Vermilion Block 131's Skate Prospect, the OCS-G 3135
No. 2 Well at Vermilion Block 255's Pylos Prospect, the OCS-G 1152 No. H-4 Well
at Vermilion Block 255's Slide Prospect, the OCS-G 14519 No. 1 Well at South
Timbalier Block 71's Triggerfish Prospect, the OCS-G 1152 No. A-7 STK Well at
Vermilion Block 255's Bubble Prospect and two wells under a joint venture
drilling project at Weeks Island Field: the Myles Salt No. 46 Well (formerly
named the Myles Salt No. 1 Well) and the Meridian State Lease 500 No. 1 Well.
BUDGETED CAPITAL EXPENDITURES AND LONG-TERM FINANCING. For the year 2000,
we have budgeted what would be a record year for drilling wells with 30 new
wells scheduled, including 17 wells on properties acquired during 1999. We have
budgeted $124.3 million for our 2000 exploration and development plans including
$33.1 million for drilling on properties acquired during 1999. Approximately 50%
of our capital expenditures budget has been allocated for activities at the
Vermilion Block 255, Eugene Island Block 243, South Timbalier Block 8, West
Cameron Block 176 and Lafitte Fields.
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 2000
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 the capital expenditures in
excess of operating cash flows.
We believe that the opportunity for acquisitions in our area of operations
remains strong due to the general exodus from the shallow water and shelf region
of the Gulf. 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 and contrast the cost of debt financing with the
potential dilution of equity offerings to determine the appropriate financing
vehicle to maximize stockholder value.
HEDGING. Our production is sold on month-to-month contracts at prevailing
prices. From time to time, however, we have entered into hedging transactions
for our oil and gas production. The primary objective of these transactions is
to reduce our exposure to future oil and gas price declines during the term of
the hedge. This hedging policy provides that, unless prices increase by more
than 50% of the prices utilized in our most recent budget, 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 any swap agreement regardless of the prices available.
We currently utilize two forms of hedging contracts: fixed price swaps and
collars. Fixed price swaps typically provide for monthly payments by us (if
prices rise) or to us (if prices fall) based on the difference between the
strike price and the agreed-upon average of NYMEX prices. For collars, monthly
payments are made by us if NYMEX prices rise above the ceiling price and to us
if NYMEX prices fall below the floor price. Oil contracts typically settle using
the average of the daily closing prices for a calendar month. Natural gas
contracts typically settle using the average closing prices for near month NYMEX
futures contracts for the three days prior to the settlement date. Because 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.
During 1999, we realized a net reduction in revenues from our hedging
transactions of $4.3 million. Swap contracts totaled 1,363.1 MBbls of oil and
16,440 BBtus of gas, which represented approximately 39% and 47%, respectively,
of our oil and gas production for the year. As of March 15, 2000, we had hedged
oil and gas prices for the applicable periods, quantities and average prices as
follows:
<TABLE>
<CAPTION>
Fixed Price Swaps
-------------------------------------------------------------------
Gas Oil
------------------------------- ------------------------------
Volume Volume
(BBtus) Price (Bbls) Price
----------- ------------- ------------ ---------
<S> <C> <C> <C> <C>
First Quarter, 2000 4,550 $2.528 409,500 $19.31
Second Quarter, 2000 1,820 $2.518 409,500 $19.31
Third Quarter, 2000 1,840 $2.518 230,000 $19.21
Fourth Quarter, 2000 1,840 $2.518 230,000 $19.21
</TABLE>
<TABLE>
<CAPTION>
Collars
--------------------------------------------------------------------------------------
Gas Oil
---------------------------------------- -----------------------------------
Volume Volume
(BBtus) Floor Ceiling (Bbls) Floor Ceiling
---------- ------- --------- -------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Second Quarter, 2000 3,640 $2.60 $3.50 - - -
Third Quarter, 2000 3,680 $2.60 $3.50 230,000 $21.00 $27.53
Fourth Quarter, 2000 3,680 $2.60 $3.50 230,000 $21.00 $27.53
</TABLE>
The net increase in revenues from hedging transactions for 1998 was $4.3
million. Swap contracts totaled 144 MBbls of oil and 9,580 BBtus of gas, which
represented approximately 5% and 30%, respectively, of our oil and gas
production for that year.
HISTORICAL FINANCING SOURCES. Since our Initial Public Offering in July
1993, we have financed our activities primarily with both debt and equity
offering proceeds, cash flows from operations, production payments and
borrowings under our bank credit facility.
In November 1995, we executed a term loan agreement with Bank One in the
original principal amount of $3.3 million for the purchase of the RiverStone
office building, the majority of which is used by us for our Lafayette office.
During 1999, the loan was repaid with borrowings under our bank credit facility.
In September 1997, we completed an offering of $100 million principal amount
of 8-3/4% Senior Subordinated Notes (the "Notes") due September 15, 2007 with
interest payable semiannually. 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 and other restricted payments.
On July 28, 1999, we completed an offering of 3.16 million shares of our
common stock at a price to the public of $43.75 per share. After payment of the
underwriting discount and expenses, we received net proceeds of $130.8 million.
On August 3, 1999, we used a portion of the net proceeds from our stock offering
to repay the outstanding borrowings under our credit facility. This reduced
long-term debt to $100 million, representing our Senior Subordinated Notes. The
proceeds from the stock offering will ultimately be used to fund specifically
identified exploration and development activities, to finance potential property
acquisitions and for other general corporate purposes.
During 1999, our bank group increased the borrowing base under our credit
facility from $120 million to $140 million. The borrowing base limitation is
based on a borrowing base amount established by the banks for our oil and gas
properties. At December 31, 1999, we had no outstanding borrowings under our
borrowing base and had outstanding letters of credit totaling $7.5 million. In
February 2000, our bank group increased our credit facility from $150 million to
$200 million and extended the maturity date from July 30, 2001 to July 30, 2005.
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.
Since November 26, 1993, new levels of lease and areawide bonds have been
required of lessees taking certain actions with regard to OCS leases. Operators
in the OCS waters of the Gulf of Mexico were required to increase their areawide
bonds and individual lease bonds to $3 million and $1 million, respectively,
unless the MMS allowed exemptions or reduced amounts. We currently have an
areawide right-of-way bond for $0.3 million and an areawide operator's bond
totaling $3.0 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. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties of covered offshore facilities that have
a worst case oil spill of more than 1,000 barrels to demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in federal outer continental shelf waters, with
higher amounts of up to $150 million if a formal risk assessment indicates that
a higher amount should be required based on specific risks posed by the
operations or if the worst case oil-spill discharge volume possible at the
facility may exceed the applicable threshold volumes specified under the MMS's
final rule. On August 11, 1998, the MMS enacted a final rule implementing these
financial responsibility requirements. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under OPA.
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.
YEAR 2000 COMPLIANCE. The year 2000 ("Y2K") issue was the result of
concern that computerized systems would not be able to store and process the
year portion of dates from and after January 1, 2000 without critical systems
failure. During 1998 and 1999, we implemented and completed a plan to evaluate
the potential Y2K risks of our critical Information Technology ("IT") and Non-IT
Systems and replaced or made modifications to computer hardware and software
that were deemed necessary for Y2K compliance. Costs expensed during the year
related to Y2K compliance totaled $10,000. In addition, we capitalized $1.6
million of computer hardware and software costs that were necessary due to the
growth in our number of employees and level of operations over the past 24
months.
As of March 15, 2000, we have not experienced any noticeable Y2K related
systems failures or disruptions in the supply of materials or services provided
by third parties.
<PAGE>
FORWARD-LOOKING STATEMENTS
Certain of the statements set forth under this Item and elsewhere in this
Form 10-K are forward-looking and are based upon assumptions and anticipated
results that are subject to numerous risks and uncertainties. See "Item 1.
Business --Forward-Looking Statements" and " --Risk Factors."
ACCOUNTING MATTERS
BASIS OF PRESENTATION. The consolidated financial statements include our
accounts, our proportionate share of certain partnerships, TSPC and TSPC's
proportionate share of certain partnerships. In June 1997, TSPC was dissolved
after the majority of its assets, including its proportionate share of certain
partnerships, were transferred to us. On December 31, 1999, the partnerships
were also dissolved after their assets were transferred to us. All intercompany
balances and transactions that existed prior to these dissolutions have been
eliminated.
FULL COST METHOD. We use the full cost method of accounting for our oil
and gas properties. Under this method, all acquisition and development costs,
including certain related employee costs and general and administrative costs
(less any reimbursements for such costs) incurred for the purpose of acquiring
and finding oil and gas are capitalized. We amortize our investment in oil and
gas properties 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, 1999, we had a net deferred
tax liability of $0.7 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 REGARDING MARKET RISKS
Our revenues are derived from the sale of crude oil and natural gas
production. From time to time, we enter into hedging transactions. These hedges
reduce our exposure to decreases in commodity prices and limit the benefit we
might otherwise have received from any increases in commodity prices on the
hedged volumes.
Based on projected annual sales volumes for 2000, a 10% decline in the
prices we are projecting to receive for our crude oil and natural gas production
would have an approximate $8.3 million impact on our annual revenues. This
hypothetical impact of the decline in oil and gas prices is net of the
incremental increase in revenues that we would realize, upon a decline in
prices, from the oil and gas hedging contracts in place as of March 15, 2000.
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 18,
2000, which will be filed with the Securities and Exchange Commission and is
incorporated herein by reference. For information concerning Item 10, see Part I
- - Item 4A. Executive Officers of the Registrant.
<PAGE>
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-21 of this Form 10-K.
Report of Independent Public Accountants
Consolidated Balance Sheet as of December 31, 1999 and 1998
Consolidated Statement of Operations for the three years in the period
ended December 31, 1999
Consolidated Statement of Cash Flows for the three years in the period ended
December 31, 1999
Consolidated Statement of Changes in Equity for the three years in the
period ended December 31, 1999
Notes to the Consolidated Financial Statements
2. FINANCIAL STATEMENT SCHEDULES:
All schedules are omitted because the required information is inapplicable
or the information is presented in the Financial Statements or the notes
thereto.
3. EXHIBITS:
3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1
(Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as of
October 15, 1998, between the Company and ChaseMellon Shareholder
Services, L.L.C., as Rights Agent (incorporated by reference to
Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A
(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)).
+10.1 -- Stone Energy Corporation 1993 Nonemployee Directors' Stock Option
Plan (incorporated by reference to Exhibit 10.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
+10.2 -- Deferred Compensation and Disability Agreements between TSPC and
D. Peter Canty dated July 16, 1981, and between TSPC and Joe R.
Klutts and James H. Prince dated August 23, 1981 and September 20,
1981, respectively (incorporated by reference to Exhibit 10.8 to
the Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
+10.3 -- Conveyances of Net Profits Interests in certain properties to
D. Peter Canty and James H. Prince (incorporated by reference to
Exhibit 10.9 to the Registrant's Registration Statement on Form
S-1 (Registration No. 33-62362)).
+10.4 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.12 to the Registrant's Registration
Statement on Form S-1 (Registration No. 33-62362)).
+10.5 -- Stone Energy Corporation Annual Incentive Compensation Plan
(incorporated by reference to Exhibit 10.14 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1993
(File No. 001-12074)).
10.6 -- Third Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and
NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997
(incorporated by reference to Exhibit 10.6 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 001-12074)).
+10.7 -- Deferred Compensation and Disability Agreement between TSPC and
E. J. Louviere dated July 16, 1981 (incorporated by reference to
Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1995 (File No. 001-12074)).
10.8 -- Term Loan Agreement, dated November 30, 1995, between the
Registrant and First National Bank of Commerce (incorporated by
reference to Exhibit 10.11 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1995
(File No. 001-12074)).
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended and
Restated Effective as of May 15, 1997 (incorporated by reference
to Exhibit 10.9 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1997 (File No. 001-12074)).
10.10 -- First Amendment and Restatement of the Third Amended and Restated
Credit Agreement between the Registrant, the financial
institutions named therein and NationsBank of Texas, N.A., as
Agent, dated as of March 31, 1998 (incorporated by reference to
Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q
for the quarter ended March 31, 1998 (File No. 001-12074)).
21.1 -- Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1995 (File No. 001-12074)).
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Financial Data Schedule
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
(B) REPORTS ON FORM 8-K
None.
<PAGE>
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 27th day of March 2000.
STONE ENERGY CORPORATION
By: /s/ JAMES H. STONE
------------------------------
James H. Stone
Chairman of the Board and
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act, this Form 10-K
has been signed by the following persons in the capacities and on the dates
indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
/s/ James H. Stone Chief Executive Officer March 27, 2000
- ---------------------------------------- and Chairman of the Board
James H. Stone (principal executive officer)
/s/ Joe R. Klutts Vice Chairman of the Board March 27, 2000
- ----------------------------------------
Joe R. Klutts
/s/ D. Peter Canty President, Chief Operating Officer March 27, 2000
- ---------------------------------------- and Director
D. Peter Canty
/s/ James H. Prince Vice President, Chief Financial Officer March 27, 2000
- ---------------------------------------- and Treasurer
James H. Prince (principal financial officer)
/s/ J. Kent Pierret Vice President - Accounting March 27, 2000
- ---------------------------------------- and Controller
J. Kent Pierret (principal accounting officer)
/s/ Robert A. Bernhard Director March 27, 2000
- ----------------------------------------
Robert A. Bernhard
/s/ B.J. Duplantis Director March 27, 2000
- ----------------------------------------
B.J. Duplantis
/s/ Raymond B. Gary Director March 27, 2000
- ----------------------------------------
Raymond B. Gary
/s/ John P. Laborde Director March 27, 2000
- ----------------------------------------
John P. Laborde
/s/ Richard A. Pattarozzi Director March 27, 2000
- ----------------------------------------
Richard A. Pattarozzi
/s/ David R. Voelker Director March 27, 2000
- ----------------------------------------
David R. Voelker
</TABLE>
INDEX TO FINANCIAL STATEMENTS
Report of Independent Public Accountants................................ F-2
Consolidated Balance Sheet of Stone Energy Corporation as of
December 31, 1999 and 1998........................................... F-3
Consolidated Statement of Operations of Stone Energy Corporation
for the years ended December 31, 1999, 1998 and 1997................. F-4
Consolidated Statement of Cash Flows of Stone Energy Corporation
for the years ended December 31, 1999, 1998 and 1997................. F-5
Consolidated Statement of Changes in Equity of Stone Energy Corporation
for the years ended December 31, 1999, 1998 and 1997................. F-6
Notes to Consolidated Financial Statements.............................. F-7
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders of
Stone Energy Corporation:
We have audited the accompanying consolidated balance sheets of Stone Energy
Corporation (a Delaware corporation) and subsidiary as of December 31, 1999 and
1998, and the related consolidated statements of operations, changes in equity
and cash flows for each of the three years in the period ended December 31,
1999. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Stone Energy Corporation and
subsidiary as of December 31, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 6, 2000
F-2
<PAGE>
STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Dollar amounts in thousands, except per share amounts)
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------
ASSETS 1999 1998
------ ----------------- ----------------
<S> <C> <C>
Current assets:
Cash and cash equivalents........................................................ $13,874 $10,550
Marketable securities, at market................................................. 34,906 16,853
Accounts receivable.............................................................. 29,729 26,803
Other current assets............................................................. 297 184
----------------- -----------------
Total current assets............................................................ 78,806 54,390
Oil and gas properties--full cost method of accounting:
Proved, net of accumulated depreciation, depletion and
amortization of $375,360 and $310,767, respectively............................. 335,959 286,098
Unevaluated...................................................................... 17,182 7,726
Building and land, net of accumulated depreciation of $355 and
$255, respectively.............................................................. 3,864 3,559
Fixed assets, net of accumulated depreciation of $1,239 and $2,013,
respectively.................................................................... 2,850 1,336
Other assets, net of accumulated depreciation and amortization
of $1,157 and $791, respectively................................................ 3,077 3,460
Deferred tax asset................................................................. - 9,821
----------------- -----------------
Total assets.................................................................... $441,738 $366,390
================= =================
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
Current liabilities:
Current portion of long-term debt................................................ $ - $88
Accounts payable to vendors...................................................... 36,060 27,583
Undistributed oil and gas proceeds............................................... 13,130 11,579
Other accrued liabilities........................................................ 6,729 5,256
----------------- -----------------
Total current liabilities....................................................... 55,919 44,506
Long-term debt..................................................................... 100,000 209,936
Production payments................................................................ 17,284 -
Deferred tax liability............................................................. 746 -
Other long-term liabilities........................................................ 2,202 6,616
----------------- -----------------
Total liabilities............................................................... 176,151 261,058
----------------- -----------------
Common Stock, $.01 par value; authorized 25,000,000 shares;
issued and outstanding 18,336,458 and 15,070,408 shares, respectively............ 183 151
Paid-in capital.................................................................... 252,941 119,208
Retained earnings (deficit)........................................................ 12,463 (14,027)
----------------- -----------------
Total stockholders' equity...................................................... 265,587 105,332
----------------- -----------------
Total liabilities and stockholders' equity...................................... $441,738 $366,390
================= =================
The accompanying notes are an integral part of this consolidated balance sheet.
F-3
</TABLE>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------
1999 1998 1997
--------------- ----------------- ----------------
<S> <C> <C> <C>
Revenues:
Oil and gas production............................................... $146,919 $114,597 $69,079
Overhead reimbursements and management fees.......................... 766 634 531
Other income......................................................... 1,449 1,389 1,377
----------------- ----------------- -------------
Total revenues...................................................... 149,134 116,620 70,987
----------------- ----------------- -------------
Expenses:
Normal lease operating expenses...................................... 22,625 18,042 10,123
Major maintenance expenses........................................... 1,115 1,278 1,844
Production taxes..................................................... 2,019 2,083 2,215
Depreciation, depletion and amortization............................. 65,803 68,187 28,739
Write-down of oil and gas properties................................. - 89,135 -
Interest............................................................. 12,840 12,950 4,916
Salaries and other employee costs.................................... 2,960 2,697 2,329
Incentive compensation plan.......................................... 1,510 763 833
General and administrative costs..................................... 1,711 1,596 1,574
----------------- ----------------- -------------
Total expenses...................................................... 110,583 196,731 52,573
----------------- ----------------- -------------
Net income (loss) before income taxes ................................. 38,551 (80,111) 18,414
----------------- ----------------- -------------
Income tax provision (benefit):
Current.............................................................. 25 - -
Deferred............................................................. 12,036 (28,480) 6,495
---------------- ---------------- --------------
Total income taxes.................................................. 12,061 (28,480) 6,495
---------------- ---------------- --------------
Net income (loss)...................................................... $26,490 ($51,631) $11,919
================ ================ =============
Earnings (loss) per common share:
Basic earnings (loss) per share...................................... $1.61 ($3.43) $0.79
================= ================= =============
Diluted earnings (loss) per share ................................... $1.58 ($3.43) $0.78
================= ================= =============
Average shares outstanding........................................... 16,469 15,066 15,024
================= ================= =============
Average shares outstanding assuming dilution......................... 16,789 15,066 15,230
================= ================= =============
</TABLE>
The accompanying notes are an integral part of this consolidated statement.
F-4
<PAGE>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Dollar amounts in thousands)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------
1999 1998 1997
------------------ ----------------- ----------------
<S> <C> <C> <C>
Cash flows from operating activities:
Net income (loss).................................................... $26,490 ($51,631) $11,919
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Depreciation, depletion and amortization.......................... 65,803 68,187 28,739
Deferred income tax provision (benefit)........................... 12,036 (28,480) 6,495
Non-cash effect of production payments............................ (2,981) - -
Write-down of oil and gas properties.............................. - 89,135 -
------------------ ----------------- ----------------
101,348 77,211 47,153
(Increase) decrease in marketable securities...................... (18,053) 3,088 (9,609)
Increase in accounts receivable................................... (2,926) (4,072) (9,795)
Increase in lease inventory and other current assets.............. (140) (96) (116)
Increase in other accrued liabilities............................. 3,024 4,887 3,133
Other............................................................. (4,403) 4,615 1,913
------------------ ----------------- ----------------
Net cash provided by operating activities.............................. 78,850 85,633 32,679
------------------ ----------------- ----------------
Cash flows from investing activities:
Investment in oil and gas properties................................. (95,168) (164,092) (133,638)
Sale of oil and gas properties....................................... - 9 623
Building additions and renovations................................... (405) (110) (235)
(Increase) decrease in other assets.................................. (2,226) 722 (1,830)
------------------ ----------------- ----------------
Net cash used in investing activities.................................. (97,799) (163,471) (135,080)
------------------ ----------------- ----------------
Cash flows from financing activities:
Proceeds from borrowings............................................. 13,000 89,000 112,000
Repayment of debt.................................................... (123,024) (11,081) (106,143)
Proceeds from issuance of 8-3/4% Notes............................... - - 100,000
Deferred financing costs............................................. - (160) (3,293)
Proceeds from stock offering......................................... 131,139 - -
Expenses for stock offering.......................................... (379) - (111)
Proceeds from exercise of stock options.............................. 1,537 325 388
------------------ ----------------- ----------------
Net cash provided by financing activities.............................. 22,273 78,084 102,841
------------------ ----------------- ----------------
Net increase in cash and cash equivalents.............................. 3,324 246 440
Cash and cash equivalents beginning of year............................ 10,550 10,304 9,864
------------------ ----------------- ----------------
Cash and cash equivalents end of year.................................. $13,874 $10,550 $10,304
================== ================= ================
Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest (net of amount capitalized)............................... $13,058 $12,745 $2,606
Income taxes....................................................... 25 - 100
</TABLE>
The accompanying notes are an integral part of this consolidated statement.
F-5
<PAGE>
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
(Dollar amounts in thousands)
<TABLE>
<CAPTION>
Retained
Common Paid-In Earnings
Stock Capital (Deficit)
------------------- ------------------- -------------------
<S> <C> <C> <C>
Balance, December 31, 1996..................................... $150 $118,606 $25,685
Net income................................................... - - 11,919
Expenses from common stock offering.......................... - (111) -
Exercise of stock options.................................... - 388 -
------------------- --------------------- -------------------
Balance, December 31, 1997..................................... 150 118,883 37,604
Net loss .................................................... - - (51,631)
Exercise of stock options.................................... 1 325 -
------------------- --------------------- -------------------
Balance, December 31, 1998..................................... 151 119,208 (14,027)
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
====================== ===================== =================
</TABLE>
The accompanying notes are an integral part of this consolidated statement.
F-6
<PAGE>
STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollar amounts in thousands, except per share 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 19 properties that comprise our
asset base including twelve offshore and seven onshore Louisiana. 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 consolidated financial statements is set forth below:
CONSOLIDATION:
The consolidated financial statements include our accounts and our
proportionate interest in certain partnerships: The Stone Petroleum Corporation
("TSPC"), a wholly owned subsidiary organized in June 1981 and TSPC's
proportionate share of managed limited partnerships. TSPC was dissolved during
1997 and the limited partnerships were dissolved on December 31, 1999. All
intercompany balances at December 31, 1999 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, 1999. The fair value of
the 8-3/4% Notes totaled $96,500 at December 31, 1999 and the cost to unwind our
hedging contracts in place at December 31, 1999 was $3,107.
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.
MARKETABLE SECURITIES:
We retain a third-party investment firm to manage our portfolio of
short-term marketable securities, which are actively and frequently bought and
sold with the primary objective of generating profits on the short-term
differences in prices. Thus, the related security investments are classified as
trading securities, which are marked to market in accordance with Statement of
Financial Accounting Standards No. 115 ("SFAS No. 115"). All realized and
unrealized gains and losses are included in current operating results. The net
unrealized loss on the portfolio for the year ended December 31, 1999 was
immaterial. The securities included in the portfolio are primarily U.S. Treasury
obligations and mortgage-backed securities with an average maturity of not more
than 360 days.
F-7
<PAGE>
NOTE 1--ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
OIL AND GAS PROPERTIES:
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.
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 the estimated net cash flows from proved reserves (based on current commodity
prices) to the net capitalized costs of proved oil and gas properties. If the
net capitalized costs of the proved oil and gas properties exceed the estimated
discounted 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 $17,182 and $7,726 of unevaluated properties
and related costs that were not being amortized at December 31, 1999 and 1998,
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, 1999 will be evaluated within
one to 24 months. The excluded costs and related proved reserves will be
included in the amortization base as the properties are evaluated and proved
reserves are established or impairment is determined. Interest capitalized on
unevaluated properties during the years ended December 31, 1999 and 1998 was
$320 and $606, respectively.
BUILDING AND LAND:
Building and land are recorded at cost. Our 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, 1999 and 1998 included approximately $1,900 and
$1,022, 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, 1999 and 1998 included approximately $2,910 and
$3,183, 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.
F-8
<PAGE>
NOTE 1--ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: (Continued)
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 employees. There were 320,000 dilutive shares for the twelve-month
period ending December 31, 1999, and there were no dilutive shares during 1998
and 206,000 dilutive shares during 1997.
Options that were considered antidilutive because the exercise price of the
stock exceeded the average price for the applicable period totaled approximately
2,806 shares and 562 shares during 1999 and 1997, respectively. All options were
considered antidilutive in 1998 due to our net loss incurred in that year.
GAS PRODUCTION REVENUES:
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 consolidated financial statements.
Revenues relating to net undelivered gas production to which we are entitled
but for which we have not received payment are not recorded in the consolidated
financial statements until compensation is received. These amounts at December
31, 1999, 1998 and 1997 were immaterial.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
From time to time, we utilize hedging activities to reduce the effect of
product price volatility. These transactions are accounted for as increases or
decreases in revenues 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. 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
periods used in accounting for income and costs arising from oil and gas
operations conducted through tax partnerships.
NEW ACCOUNTING STANDARDS:
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." The Statement establishes accounting and
reporting standards that require every derivative instrument (including certain
derivative instruments embedded in other contracts) to be recorded in the
balance sheet as either an asset or liability measured at its fair value and
that changes in the derivative's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. We expect to adopt SFAS No.
133 on January 1, 2001. The adoption may create volatility in equity through
changes in other comprehensive income due to the marking to market of our
hedging contracts (See Note 9); however, we believe these instruments will be
treated as hedges under SFAS No. 133 and thus we do not anticipate that the
standard will have a material impact on our results of operations.
F-9
<PAGE>
NOTE 2 -- ACCOUNTS RECEIVABLE:
In our capacity as operator, manager and/or sponsor for our partners and
other 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,
-----------------------------------------------
1999 1998
--------------------- --------------------
Accounts Receivable:
Managed partnerships........... $ - $1,882
Other co-venturers............. 6,019 5,885
Trade.......................... 23,270 18,716
Officers and employees......... 27 3
Unbilled accounts receivable... 413 317
--------------------- --------------------
$29,729 $26,803
===================== ====================
NOTE 3 -- 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 revenues during each of the twelve-month periods ended:
December 31,
--------------------------------------
1999 1998 1997
---- ---- ----
Amoco Energy Trading Corporation - 14% -
Columbia Energy Services 28% - -
Conoco, Incorporated - 24% -
Engage Energy US LP 12% - -
Genesis Crude Oil LP 12% - 16%
Natural Gas Clearinghouse - - 18%
Northridge Energy Marketing 22% 14% -
Because 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.
F-10
<PAGE>
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:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------
1999 1998 1997
-------------- --------------- ---------------
<S> <C> <C> <C>
Oil and gas properties--
Balance, beginning of year..................................... $604,591 $445,709 $296,929
Costs incurred during year:
Capitalized--
Acquisition costs.............................. .......... 31,046 17,748 43,791
Exploratory drilling...................................... 32,117 81,765 57,770
Development drilling...................................... 53,463 54,889 43,762
General and administrative costs.......................... 7,753 5,416 4,494
Less: overhead reimbursements............................. (469) (936) (1,037)
------------- --------------- --------------
Total costs incurred during year (1)...................... 123,910 158,882 148,780
------------- --------------- --------------
Balance, end of year............................................ 728,501 $604,591 $445,709
============= =============== ==============
Charged to expense--
Operating costs:
Normal lease operating expenses............................... $22,625 $18,042 $10,123
Major maintenance expenses.................................... 1,115 1,278 1,844
-------------- -------------- ---------------
Total operating costs......................................... 23,740 19,320 11,967
Production taxes.............................................. 2,019 2,083 2,215
-------------- -------------- ---------------
$25,759 $21,403 14,182
============== ============== ===============
Unevaluated oil and gas properties--
Costs incurred during year:
Acquisition costs............................................. $10,059 $5,410 $5,442
Exploration costs............................................. 806 - 11,020
Development costs............................................. - - -
-------------- ------------- ----------------
$10,865 $5,410 $16,462
============== ============= ================
Accumulated depreciation, depletion
and amortization--
Balance, beginning of year.................................... ($310,767) ($154,289) ($125,533)
Provision for depreciation, depletion and amortization........ (64,593) (67,334) (28,133)
Write-down of oil and gas properties.......................... - (89,135) -
Sale of reserves.............................................. - (9) (623)
-------------- -------------- ----------------
Balance, end of year............................................ (375,360) (310,767) (154,289)
-------------- -------------- ----------------
Net capitalized costs (proved and unevaluated).................... $353,141 $293,824 $291,420
============== ============== ================
DD&A per Mcfe..................................................... $1.10 $1.33 $1.19
============== ============== ================
</TABLE>
(1) Total costs incurred during 1999 included non-cash additions of $20,272
related to acquisitions made through production
F-11
<PAGE>
NOTE 4--INVESTMENT IN OIL AND GAS PROPERTIES: (Continued)
The following table discloses financial data associated with capitalized
unevaluated costs as of December 31, 1999:
<TABLE>
<CAPTION>
Costs incurred during the
Year Ended December 31,
Balance at ------------------------------------------------------------
December 31, 1999 1999 1998 1997
-------------------- ---------------- ----------------- -----------------
<S> <C> <C> <C> <C>
Acquisition costs $16,376 $10,059 $5,352 $965
Exploration costs 806 806 - -
Development costs - - - -
-------------------- ----------------- ----------------- -----------------
Total unevaluated costs $17,182 $10,865 $5,352 $965
==================== ================= ================= =================
</TABLE>
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 asset (liability) follows:
<TABLE>
<CAPTION>
December 31,
-----------------------------------------
1999 1998
------------------ ---------------
<S> <C> <C>
Net operating loss carryforward $5,579 $6,365
Statutory depletion carryforward 4,181 4,046
Investment tax credit carryforward - 313
Contribution carryforward 80 44
Alternative minimum tax credit carryforward 420 396
Temporary differences:
Oil and gas properties--full cost (11,150) (359)
Other 224 (627)
Valuation allowance (80) (357)
------------------ -----------------
($746) $9,821
================== =================
</TABLE>
For tax reporting purposes, operating loss carryforwards totaled $15,909 at
December 31, 1999. If not utilized, such carryforwards would begin expiring in
2003 and would completely expire by the year 2018. In addition, we had $12,034
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:
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------------------------------
1999 1998 1997
--------------- ------------- -------------
<S> <C> <C> <C>
Income tax expense (benefit) computed at the statutory
federal income tax rate......................................... 35% (35%) 35%
Reduction in deferred taxes....................................... (4%) - -
--------------- ------------- -------------
Effective income tax rate......................................... 31% (35%) 35%
=============== ============= =============
</TABLE>
F-12
<PAGE>
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, 1999, the production payment associated with this
transaction still totaled $2,346.
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
revenues. At December 31, 1999, the volumetric production payment was $14,938
and $2,988 had been recognized as gas revenue during 1999.
NOTE 7--LONG-TERM DEBT:
Long-term debt consisted of the following at:
<TABLE>
<CAPTION>
December 31,
------------------------------
1999 1998
-------- --------
<S> <C> <C>
8-3/4% Senior Subordinated Notes due 2007............................... $100,000 $100,000
Unsecured revolving credit facility with Bank of America
(described below)...................................................... - 107,000
Term Loan Agreement with Bank One with interest at 7.45%................ - 3,024
Less: portion due within one year...................................... - (88)
-------- --------
Total long-term debt.................................................... $100,000 $209,936
======== ========
</TABLE>
At December 31, 1999, 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, 1999, $2,601 had been accrued in
connection with the March 2000 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 and other restricted payments.
On August 3, 1999, we used a portion of the net proceeds from our recent
stock offering (Note 10) to repay the outstanding borrowings under our credit
facility. At December 31, 1999, 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. The borrowing base limitation, which is
currently $140,000, is re-determined periodically and is based on a borrowing
base amount established by the banks for our oil and gas properties. 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 terms of
this agreement contain, among other provisions, requirements for maintaining
defined levels of working capital and tangible net worth.
In November 1995, we executed a term loan agreement with Bank One in the
original principal amount of $3,250 for the purchase of the RiverStone building,
the majority of which we use for our Lafayette office. During 1999, we repaid
this loan with borrowings under our bank credit facility.
F-13
<PAGE>
NOTE 8--TRANSACTIONS WITH RELATED PARTIES:
We received certain fees as a result of our function as managing partner of
certain partnerships. For the years ended December 31, 1999, 1998 and 1997,
management fees and overhead reimbursements from partnerships totaled $224, $834
and $868, respectively, the majority of which was treated as a reduction of the
investment in oil and gas properties. These partnerships were dissolved on
December 31, 1999. All participants in the partnerships, including James H.
Stone and Joe R. Klutts, received overriding royalty interests in the related
properties in exchange for their partnership interests.
Until their dissolution, we collected and distributed production revenues as
managing partner for the partnerships' interests in oil and gas properties.
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.
Certain officers and directors and their affiliates are working interest
owners in properties operated by us and are billed and pay their proportionate
share of drilling and operating costs in the normal course of business.
NOTE 9--HEDGING ACTIVITIES:
We engage in futures contracts with certain of our production volumes. These
futures contracts are considered to be hedging activities and, as such, monthly
settlements on these contracts are reflected in revenues from oil and gas
production. In order to consider these futures contracts as hedges, (i) we must
designate the futures contract as a hedge of future production and (ii) the
contract must reduce 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 revenues. Any
proceeds received or paid relating to terminated contracts or contracts that
have been sold are amortized over the original contract period and reflected in
revenues from oil and gas production. We enter into hedging transactions for the
purpose of securing a price for a portion of future production that is
acceptable at the time the transaction is entered into. The primary objective of
these activities is to reduce the exposure to the possibility of declining oil
and gas prices during the term of the hedge.
We currently utilize two forms of hedging contracts: fixed price swaps and
collars. Fixed price swaps typically provide for monthly payments by us (if
prices rise) or to us (if prices fall) based on the difference between the
strike price and the agreed-upon average of NYMEX prices. For collars, monthly
payments are made by us if NYMEX prices rise above the ceiling price and to us
if NYMEX prices fall below the floor price. Oil contracts typically settle using
the average of the daily closing prices for a calendar month. Natural gas
contracts typically settle using the average closing prices for near month NYMEX
futures contracts for the three days prior to the settlement date. Because 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.
F-14
<PAGE>
NOTE 9--HEDGING ACTIVITIES: (Continued)
As of March 15, 2000, our open hedge positions were:
<TABLE>
<CAPTION>
Fixed Price Swaps
-------------------------------------------------------------------
Gas Oil
------------------------------- ------------------------------
Volume Volume
(BBtus) Price (Bbls) Price
----------- ------------- ------------ ---------
<S> <C> <C> <C> <C>
First Quarter, 2000 4,550 $2.528 409,500 $19.31
Second Quarter, 2000 1,820 $2.518 409,500 $19.31
Third Quarter, 2000 1,840 $2.518 230,000 $19.21
Fourth Quarter, 2000 1,840 $2.518 230,000 $19.21
</TABLE>
<TABLE>
<CAPTION>
Collars
--------------------------------------------------------------------------------------
Gas Oil
---------------------------------------- -----------------------------------
Volume Volume
(BBtus) Floor Ceiling (Bbls) Floor Ceiling
---------- ------- --------- -------- ------- ---------
<S> <C> <C> <C> <C> <C> <C>
Second Quarter, 2000 3,640 $2.60 $3.50 - - -
Third Quarter, 2000 3,680 $2.60 $3.50 230,000 $21.00 $27.53
Fourth Quarter, 2000 3,680 $2.60 $3.50 230,000 $21.00 $27.53
</TABLE>
For the years ended December 31, 1999, 1998 and 1997, we realized net
increases (decreases) in oil and gas revenues related to hedging transactions of
($4,329), $4,265 and ($569), respectively.
NOTE 10--COMMON STOCK:
On July 28, 1999, we completed a secondary offering of 3.16 million 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 will ultimately be used to fund specifically identified
exploration and development activities, to finance potential 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 the 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 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, 2004, respectively. Additionally, we lease automobiles under the
terms of non-cancelable leases expiring at various dates through 2002. The
minimum net annual commitments under all leases, subleases and contracts noted
above at December 31, 1999 are as follows:
2000..................................................................... $421
2001..................................................................... 411
2002..................................................................... 393
2003..................................................................... 324
2004..................................................................... 127
Thereafter............................................................... -
Rent expense for the years ended December 31, 1999, 1998 and 1997 was
approximately $268, $132 and $118, respectively.
F-15
NOTE 11--COMMITMENTS AND CONTINGENCIES: (Continued)
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.
We are contingently liable to a surety insurance company in the aggregate
amount of $14,821 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.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. As amended by the Coast Guard Authorization Act of
1996, OPA requires responsible parties of offshore facilities to provide
financial assurance in the amount of $35,000 to cover potential OPA liabilities.
This amount can be increased up to $150,000 if a formal risk assessment
indicates that an amount higher than $35,000 should be required. We do not
anticipate that we will experience any difficulty in continuing to satisfy the
MMS's requirements for demonstrating financial responsibility under OPA.
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
$3,339 at December 31, 1999, of which $1,975 was payable to employees or their
beneficiaries and $1,364 was payable to us. Total cash surrender value of the
policies, net of related surrender charges at December 31, 1999, was
approximately $1,117. Additionally, the benefits under the deferred compensation
agreements vest after certain periods of employment, and at December 31, 1999,
the liability for such vested benefits was approximately $870. The difference
between the actuarial determined liability for retirement benefits or the vested
amounts, where applicable, and the net cash surrender value has been recorded as
an other long-term liability.
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
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 annual return 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.
F-16
<PAGE>
NOTE 12--EMPLOYEE BENEFIT PLANS: (Continued)
ii. The Nonemployee Directors' Stock Option Plan provides for the issuance
of up to 250,000 shares of Common Stock upon the exercise of such
options granted pursuant to 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 1999 Stock Option Plan provides for 300,000 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 other than officers. 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 1993 Stock Option Plan (as amended and restated) provides for
1,170,000 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. 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.
v. 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, 1999, 1998 and 1997, we
contributed $313, $270 and $207, 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.
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, pro forma
disclosures as if we adopted the cost recognition requirements under SFAS No.
123 are presented below.
If the compensation cost for the 1999, 1998 and 1997 grants for stock-based
compensation plans had been determined consistent with SFAS No. 123, our 1999,
1998 and 1997 net income (loss) and basic and diluted earnings (loss) per common
share would have approximated the pro forma amounts below:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------------------------------
1999 1998 1997
-------------------- --------------------- ---------------------
AS PRO AS PRO AS PRO
REPORTED FORMA REPORTED FORMA REPORTED FORMA
---------- ------- ---------- ------- ---------- -------
<S> <C> <C> <C> <C> <C> <C>
Net income (loss)............... $26,490 $24,599 ($51,631) ($53,141) $11,919 $10,966
Earnings (loss) per common
share:
Basic........................ $1.61 $1.49 ($3.43) ($3.53) $0.79 $0.73
Diluted...................... $1.58 $1.47 ($3.43) ($3.53) $0.78 $0.72
F-17
</TABLE>
NOTE 12--EMPLOYEE BENEFIT PLANS: (Continued)
The effects of applying SFAS No. 123 in this pro forma disclosure are not
indicative of future amounts. SFAS No. 123 does not apply to grants prior to
1995, and additional awards in the future are anticipated.
A summary of stock options as of December 31, 1999, 1998 and 1997 and
changes during the years ended on those dates is presented below. The table
reflects the effects of repricing certain options granted during 1997 and 1998.
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------------------------------------------------
1999 1998 1997
--------------------- ---------------------- ------------------------
WGTD. WGTD. WGTD.
NUMBER AVG. NUMBER AVG. NUMBER AVG.
OF EXER. OF EXER. OF EXER.
OPTIONS PRICE OPTIONS PRICE OPTIONS PRICE
---------- ------- ----------- ------- --------- -------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year 1,035,000 $19.90 960,000 $18.62 735,000 $15.76
Granted 369,250 38.17 100,000 30.43 255,000 26.20
Expired (23,000) 22.29 - - - -
Exercised (103,550) 14.86 (25,000) 13.00 (30,000) 12.95
---------- ----------- ---------
Outstanding at end of year 1,277,700 $25.54 1,035,000 $19.90 960,000 $18.62
Options exercisable at year-end 552,650 18.11 481,800 16.01 309,400 13.93
Options available for future grant 299,750 321,000 403,000
Weighted average fair value of
options granted during the year $24.01 $21.23 $17.05
</TABLE>
The fair value of each option granted during the periods presented is
estimated on the date of grant using the Black-Scholes option-pricing model with
the following assumptions: (a) dividend yield of 0%, (b) expected volatility of
41.59%, 43.90% and 41.20% in the years 1999, 1998 and 1997, respectively, (c)
risk-free interest rate of 6.32%, 5.50% and 6.04% in the years 1999, 1998 and
1997, respectively, and (d) expected life of 10 years for employee options and
five years for director options.
The following table summarizes information regarding stock options
outstanding at December 31, 1999:
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
---------------------------------------------------------- --------------------------------
RANGE OF OPTIONS WGTD. AVG. WGTD. AVG. OPTIONS WGTD. AVG.
EXERCISE OUTSTANDING REMAINING EXERCISE EXERCISABLE EXERCISE
PRICES AT 12/31/99 CONTRACTUAL LIFE PRICE AT 12/31/99 PRICE
-------- ----------- ---------------- ---------- ----------- ---------
<S> <C> <C> <C> <C> <C>
$11-$15 291,700 9.8 years $12.33 261,034 $12.41
17 - 24 277,000 9.5 years 20.27 166,866 20.17
25 - 30 314,750 9.6 years 26.34 112,415 26.32
30 - 38 299,250 9.2 years 35.92 12,335 36.05
39 - 53 95,000 10.0 years 46.16 - -
--------- ---------
1,277,700 9.6 years 25.54 552,650 18.11
========= =========
</TABLE>
F-18
<PAGE>
NOTE 13--OIL AND GAS RESERVE INFORMATION - UNAUDITED:
A majority of our net proved oil and gas reserves at December 31, 1999
have been estimated by independent petroleum consultants in accordance with
guidelines established by the Securities and Exchange Commission ("SEC").
Accordingly, the following reserve estimates are based upon existing economic
and operating conditions at the respective dates.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in providing the future rates of production and timing of
development expenditures. The following reserve data represents estimates only
and should not be construed as being exact. In addition, the present values
should not be construed as the current market value of the oil and gas
properties or the cost that would be incurred to obtain equivalent reserves.
Proved natural gas reserves at December 31, 1999 excluded 6.7 Bcf of gas
dedicated to a production payment. The excluded natural gas reserves were net of
1.3 Bcf of gas that was produced relative to the production payment from July to
December 1999. Also excluded are the related estimated future net cash flows and
the present value of estimated future net cash flows of $16.6 million and $14.8
million, respectively.
The following table sets forth an analysis of the estimated quantities of
net proved and proved developed oil (including condensate) and natural gas, all
located onshore and offshore the continental United States:
<TABLE>
<CAPTION>
NATURAL
OIL IN GAS IN
MBBLS MMCF
------------------- ---------------
<S> <C> <C>
Proved reserves as of December 31, 1996....................................... 12,772 144,316
Revisions of previous estimates............................................. 1,673 (12,252)
Extensions, discoveries and other additions................................. 2,675 45,276
Purchase of producing properties............................................ 2,302 26,409
Sale of reserves............................................................ (74) (327)
Production.................................................................. (1,585) (14,183)
------------------- ----------------
Proved reserves as of December 31, 1997....................................... 17,763 189,239
Revisions of previous estimates............................................. (1,001) 2,162
Extensions, discoveries and other additions................................. 4,353 70,936
Purchase of producing properties............................................ 237 14,214
Production.................................................................. (2,876) (33,281)
-------------------- ---------------
Proved reserves as of December 31, 1998....................................... 18,476 243,270
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.................................................................. (3,469) (36,780)
-------------------- ----------------
Proved reserves as of December 31, 1999....................................... 22,636 251,614
==================== ================
Proved developed reserves:
as of December 31, 1997..................................................... 14,485 141,424
==================== ================
as of December 31, 1998..................................................... 15,242 200,973
==================== ================
as of December 31, 1999..................................................... 17,729 205,345
==================== ================
</TABLE>
The following tables present the standardized measure of future net cash
flows related to proved oil and gas reserves together with changes therein, as
defined by the FASB. The oil, condensate and gas price structure utilized to
project future net cash flows reflects current prices at each year-end and has
been escalated only where known and determinable price changes are provided by
contracts and law. Future production and development costs are based on current
costs with no escalations. Estimated future cash flows net of future income
taxes have been discounted to their present values based on a 10% annual
discount rate.
F-19
<PAGE>
NOTE 13--OIL AND GAS RESERVE INFORMATION - UNAUDITED: (Continued)
<TABLE>
<CAPTION>
STANDARDIZED MEASURE
DECEMBER 31,
------------------------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Future cash flows................................................. $1,189,275 $670,361 $801,647
Future production and development costs........................... (386,945) (281,920) (268,641)
Future income taxes............................................... (156,496) (22,409) (104,521)
------------ ------------ ------------
Future net cash flows............................................. 645,834 366,032 428,485
10% annual discount............................................... (180,755) (97,584) (132,145)
------------ ------------ ------------
Standardized measure of discounted future net cash flows.......... $465,079 $268,448 $296,340
============ ============ ============
</TABLE>
<TABLE>
<CAPTION>
CHANGES IN STANDARDIZED MEASURE
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1999 1998 1997
------------------- ----------------- ---------------
<S> <C> <C> <C>
Standardized measure at beginning of year......................... $268,448 $296,340 $329,338
Sales and transfers of oil and gas produced, net of
production costs................................................ (118,172) (93,194) (54,898)
Changes in price, net of future production costs.................. 246,053 (156,107) (186,615)
Extensions and discoveries, net of future production
and development costs........................................... 54,820 111,828 87,491
Changes in estimated future development costs, net of
development costs incurred during the period.................... 9,808 22,923 26,738
Revisions of quantity estimates................................... 13,937 (3,548) (3,502)
Accretion of discount............................................. 28,610 36,863 32,934
Net change in income taxes........................................ (79,789) 55,852 52,338
Purchase of reserves in place..................................... 58,655 10,321 21,725
Sale of reserves in place......................................... - - 420
Changes in production rates (timing) and other.................... (17,291) (12,830) (9,629)
------------------- ----------------- ---------------
Standardized measure at end of year............................... $465,079 $268,448 $296,340
=================== ================= ===============
</TABLE>
F-20
<PAGE>
NOTE 14--SUMMARIZED QUARTERLY FINANCIAL INFORMATION - UNAUDITED:
<TABLE>
<CAPTION>
Basic Diluted
Earnings Earnings
Net (Loss) (Loss)
Revenues Expenses Income (Loss) Per Share Per Share
-------- -------- ------------- --------- ---------
<S> <C> <C> <C> <C> <C>
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
========= ======== ============= ========= =========
1998
First Quarter.......... $28,795 $25,497 $3,298 $0.22 $0.22
Second Quarter......... 28,474 26,642 1,832 0.12 0.12
Third Quarter.......... 27,412 26,667 745 0.05 0.05
Fourth Quarter......... 31,939 89,445 (a) (57,506)(a) (3.82)(a) (3.82)(a)
--------- -------- ------------- --------- ---------
$116,620 $168,251 ($51,631) ($3.43) ($3.43)
========= ======== ============= ========= =========
</TABLE>
(a) Includes a pre-tax, non-cash ceiling test write-down of $89,135.
F-21
<PAGE>
GLOSSARY OF CERTAIN INDUSTRY TERMS
The definitions set forth below shall apply to the indicated terms as used
in this Form 10-K. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
Bbtu. One billion Btus.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
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 by the Company pursuant to generally accepted
accounting principles, excluding any capitalized general and administrative
expenses.
Gross acreage or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
MBbls/d. One thousand barrels of crude oil or other liquid hydrocarbons per
day.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio
of one barrel of crude oil to six mcf of natural gas.
Mcf/d. One thousand cubic feet of gas per day.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
G-1
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.
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 gross revenues less related production taxes and
transportation costs of the purchased property interest 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 costs of production.
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. The operating interest which gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
G-2
<PAGE>
EXHIBIT INDEX
Exhibit
Number Description
- ------- -----------
3.1 -- Certificate of Incorporation of the Registrant, as amended
(incorporated by reference to Exhibit 3.1 to the Registrant's
Registration Statement on Form S-1
(Registration No. 33-62362)).
3.2 -- Restated Bylaws of the Registrant (incorporated by reference to
Exhibit 3.2 to the Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
4.1 -- Rights Agreement, with exhibits A, B and C thereto, dated as of
October 15, 1998, between the Company and ChaseMellon Shareholder
Services, L.L.C., as Rights Agent (incorporated by reference to
Exhibit 4.1 to the Registrant's Registration Statement on Form 8-A
(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)).
+10.1 -- Stone Energy Corporation 1993 Nonemployee Directors' Stock Option
Plan (incorporated by reference to Exhibit 10.1 to the
Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
+10.2 -- Deferred Compensation and Disability Agreements between TSPC and
D. Peter Canty dated July 16, 1981, and between TSPC and Joe R.
Klutts and James H. Prince dated August 23, 1981 and September 20,
1981, respectively (incorporated by reference to Exhibit 10.8 to
the Registrant's Registration Statement on Form S-1
(Registration No. 33-62362)).
+10.3 -- Conveyances of Net Profits Interests in certain properties to
D. Peter Canty and James H. Prince (incorporated by reference to
Exhibit 10.9 to the Registrant's Registration Statement on Form
S-1 (Registration No. 33-62362)).
+10.4 -- Stone Energy Corporation 1993 Stock Option Plan (incorporated by
reference to Exhibit 10.12 to the Registrant's Registration
Statement on Form S-1 (Registration No. 33-62362)).
+10.5 -- Stone Energy Corporation Annual Incentive Compensation Plan
(incorporated by reference to Exhibit 10.14 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1993
(File No. 001-12074)).
10.6 -- Third Amended and Restated Credit Agreement between the
Registrant, the financial institutions named therein and
NationsBank of Texas, N.A., as Agent, dated as of July 30, 1997
(incorporated by reference to Exhibit 10.6 to the Registrant's
Annual Report on Form 10-K for the year ended December 31, 1997
(File No. 001-12074)).
+10.7 -- Deferred Compensation and Disability Agreement between TSPC and
E. J. Louviere dated July 16, 1981 (incorporated by reference to
Exhibit 10.10 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1995 (File No. 001-12074)).
10.8 -- Term Loan Agreement, dated November 30, 1995, between the
Registrant and First National Bank of Commerce (incorporated by
reference to Exhibit 10.11 to the Registrant's Annual Report on
Form 10-K for the year ended December 31, 1995
(File No. 001-12074)).
+10.9 -- Stone Energy Corporation 1993 Stock Option Plan, As Amended and
Restated Effective as of May 15, 1997 (incorporated by reference
to Exhibit 10.9 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1997 (File No. 001-12074)).
10.10 -- First Amendment and Restatement of the Third Amended and Restated
Credit Agreement between the Registrant, the financial
institutions named therein and NationsBank of Texas, N.A., as
Agent, dated as of March 31, 1998 (incorporated by reference to
Exhibit 10.1 to the Registrant's Quarterly Report on Form 10-Q
for the quarter ended March 31, 1998 (File No. 001-12074)).
21.1 -- Subsidiaries of the Registrant (incorporated by reference to
Exhibit 21.1 to the Registrant's Annual Report on Form 10-K for
the year ended December 31, 1995 (File No. 001-12074)).
*23.1 -- Consent of Arthur Andersen LLP.
*23.2 -- Consent of Atwater Consultants, Ltd.
*23.3 -- Consent of Cawley, Gillespie & Associates, Inc.
*27.1 -- Financial Data Schedule
- ------------
* Filed herewith.
+ Identifies management contracts and compensatory plans or arrangements.
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the
incorporation by reference of our report, dated March 6, 2000, on our audits of
the consolidated financial statements of Stone Energy Corporation as of December
31, 1999 and 1998 and for each of the three years in the period ended December
31, 1999 included in this Annual Report on Form 10-K for the year ended December
31, 1999, into the Company's previously filed Registration Statement on Form S-8
(Registration No. 33-67332).
ARTHUR ANDERSEN LLP
New Orleans, Louisiana
March 15, 2000
<PAGE>
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We do hereby consent to the use of our name in "Item 2. Properties" of the
Annual Report on Form 10-K of Stone Energy Corporation (the "Company") for the
year ended December 31, 1999 (the "Form 10-K"), and the incorporation by
reference of the Form 10-K into the Company's Registration Statement on Form S-8
(Registration No. 33-67332), and the incorporation by reference of the Form 10-K
into the Company's Registration Statement on Form S-3 (Registration No.
33-72236).
ATWATER CONSULTANTS, LTD.
By: /s/ O.R. Carter
---------------------------
O.R. Carter
Co-Chairman, Board of Directors
New Orleans, Louisiana
March 15, 2000
<PAGE>
Exhibit 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We do hereby consent to the use of our name in "Item 2. Properties" of the
Annual Report on Form 10-K of Stone Energy Corporation (the "Company") for the
year ended December 31, 1999 (the "Form 10-K"), the incorporation by reference
of the Form 10-K into the Company's Registration Statement on Form S-8
(Registration No. 33-67332), and the incorporation by reference of the Form 10-K
into the Company's Registration Statement on Form S-3 (Registration No.
33-72236).
Cawley, Gillespie & Associates, Inc.
By: /s/ Aaron Cawley
-------------------------
Aaron Cawley, P.E.
Executive Vice President
Fort Worth, Texas
March 15, 2000
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONDENSED CONSOLIDATED BALANCE SHEET OF STONE ENERGY CORPORATION ("THE
COMPANY")AS OF DECEMBER 31, 1999 AND THE RELATED CONDENDSED CONSOLIDATED
STATEMENT OF OPERATIONS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1999 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. </LEGEND>
<CIK> 0000904080
<NAME> STONE ENERGY CORPORATION
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> Year
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 13,874
<SECURITIES> 34,906
<RECEIVABLES> 29,729
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 78,806
<PP&E> 12,542
<DEPRECIATION> 2,751
<TOTAL-ASSETS> 441,738
<CURRENT-LIABILITIES> 55,919
<BONDS> 100,000
0
0
<COMMON> 183
<OTHER-SE> 265,404
<TOTAL-LIABILITY-AND-EQUITY> 441,738
<SALES> 146,919
<TOTAL-REVENUES> 149,134
<CGS> 0
<TOTAL-COSTS> 91,562
<OTHER-EXPENSES> 6,181
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 12,840
<INCOME-PRETAX> 38,551
<INCOME-TAX> 12,061
<INCOME-CONTINUING> 26,490
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 26,490
<EPS-BASIC> 1.61
<EPS-DILUTED> 1.58
</TABLE>
