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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
For the fiscal year ended December 31, 2000
or
[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
State of incorporation: Delaware I.R.S. Employer Identification No. 72-1235413
625 E. Kaliste Saloom Road
Lafayette, Louisiana 70508
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (337) 237-0410
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
Common Stock, Par Value $.01 Per Share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
[x] Yes [ ] No
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates
of the registrant was approximately $1,120,872,471 as of March 15, 2001 (based
on the last reported sale price of such stock on the New York Stock Exchange
Composite Tape).
As of March 15, 2001, the registrant had outstanding 25,981,827 shares
of Common Stock, par value $.01 per share.
Document incorporated by reference: Proxy Statement of Stone Energy
Corporation relating to the Annual Meeting of Stockholders to be held on May 17,
2001, which is incorporated into Part III of this Form 10-K.
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TABLE OF CONTENTS
Page No.
PART I
Item 1. Business................................................ 3
Item 2. Properties.............................................. 16
Item 3. Legal Proceedings....................................... 19
Item 4. Submission of Matters to a Vote of Security Holders..... 19
Item 4A. Executive Officers of the Registrant.................... 20
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters.................................. 21
Item 6. Selected Financial Data................................. 22
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................ 23
Item 7A. Quantitative and Qualitative Disclosures About
Market Risk.......................................... 29
Item 8. Financial Statements and Supplementary Data............. 31
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure............................. 31
PART III
Item 10. Directors and Executive Officers of the Registrant...... 31
Item 11. Executive Compensation.................................. 31
Item 12. Security Ownership of Certain Beneficial Owners
and Management....................................... 31
Item 13. Certain Relationships and Related Transactions.......... 31
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K............................................ 31
Index to Financial Statements.......................... F-1
Glossary of Certain Industry Terms..................... G-1
PART I
Where specifically indicated, throughout this document we show combined
operational and financial information to give effect to our merger with Basin
Exploration, which was consummated on February 1, 2001 and was accounted for as
a pooling of interests, as if the two companies were combined on January 1,
2000. These combined results should be used for information purposes only as
they are not necessarily indicative of the results that would have occurred if
the merger had been completed on January 1, 2000.
This section highlights information that is discussed in more detail in the
remainder of the document. Throughout this document we make statements that are
classified as "forward-looking". Please refer to the "Forward-Looking
Statements" section on page 9 of this document for an explanation of these types
of statements. We use the terms "Stone", "Stone Energy", "company", "we", "us"
and "our" to refer to Stone Energy Corporation. We use the terms "Basin" and
"Basin Exploration" to refer to Basin Exploration, Inc. The terms "merger" and
"combined company" are used to refer to the combination of Stone Energy and
Basin Exploration. Certain terms relating to the oil and gas industry are
defined in "Glossary of Certain Terms", which begins on page G-1 of this Form
10-K.
ITEM 1. BUSINESS
OPERATIONAL OVERVIEW
Stone Energy is an independent oil and gas company engaged in the
acquisition, exploration, development and operation of oil and gas properties
located onshore and in shallow waters offshore Louisiana. We have been active in
the Gulf Coast Basin since 1973 and have established extensive geophysical,
technical and operational expertise in this area. As of December 31, 2000, we
had estimated proved reserves of approximately 272.2 Bcf of natural gas and 21.3
MMBbls of oil, or an aggregate of approximately 400.2 Bcfe. As of December 31,
2000, the present value of estimated pre-tax net cash flows of our reserves was
$2 billion (based upon year-end 2000 prices and a discount rate of 10%).
Our business strategy is to increase production, cash flow and reserves
through the acquisition and development of mature properties located in the Gulf
Coast Basin, either onshore or in shallow waters offshore. As a result of the
successful and consistent application of this strategy, since our initial public
offering in 1993, we have increased production 502%, cash flow from operations
before working capital changes 1,014% and proved reserves 321%.
Since implementing our acquisition and exploitation strategy in 1990, we
have acquired interests in 21 producing fields and two primary term leases in
the Gulf Coast Basin, excluding the merger with Basin, from major and
independent oil and gas companies. At December 31, 2000, we served as operator
on all of these properties, which enables us to better control the timing and
cost of field rejuvenation activities. We believe that there will continue to be
numerous attractive opportunities to acquire properties in the Gulf Coast Basin
due to the increased focus by major and large independent companies on projects
in deeper waters and in foreign countries.
We seek to acquire properties that have the following characteristics:
o Gulf Coast Basin location;
o mature properties with an established production history and
infrastructure;
o multiple productive sands and reservoirs;
o low current production levels with significant identified proven and
potential reserve opportunities; and
o the opportunity for us to obtain a controlling interest and serve as
operator.
We believe significant reserves remain to be discovered on properties in the
shallow waters of the Gulf Coast Basin that satisfy our acquisition
characteristics. We also believe that we can exploit these reserves by applying
our technical expertise and patient approach in the evaluation and acquisition
of such properties.
Prior to acquiring a property, we perform a thorough geological, geophysical
and engineering analysis of the property to formulate a comprehensive
development plan. To formulate this plan, we utilize the expertise of our
technical team of 12 geologists, 7 geophysicists and 16 engineers. We also
employ our extensive technical database, which includes 3-D seismic data on all
of our current properties and some of the properties that we are evaluating for
acquisition. After acquisition, we seek to increase cash flow from existing
reserves and to establish additional proved reserves through the drilling of new
wells, workovers and recompletions of existing wells and the application of
other techniques designed to increase production. Our geographic focus,
state-of-the-art equipment and high level of operated properties have enabled us
to maintain low operating costs as evidenced by our per unit lease operating
expense of $0.41 per Mcfe in 2000.
FINANCIAL OVERVIEW
We completed our initial public offering of common stock in July 1993 and
our shares are listed on the New York Stock Exchange under the symbol "SGY".
Additional offerings of common stock were completed in November 1996 and July
1999.
In September 1997, we completed an offering of $100 million principal amount
of 8-3/4% Senior Subordinated Notes. These notes are due to mature in September
2007 and as of March 15, 2001 carried credit ratings by Moody's and Standard and
Poor's of B2 and B, respectively. We also have a $200 million revolving credit
agreement that as of December 31, 2000 had a borrowing base availability of
$192.5 million with no outstanding draws.
We have maintained consistent, profitable growth since our initial public
offering in 1993. We have generated net income in all calendar quarters except
the fourth quarter of 1998, which included a non-cash ceiling test write-down of
our oil and gas properties. The production increases discussed above combined
with our focus on maintaining low lease operating and general and administrative
costs on a per Mcfe basis have enabled us to increase EBITDA by 1,003% since
1993. Our per share net cash flow from operations has also grown 501% since 1993
and 75% over 1999.
MERGER WITH BASIN EXPLORATION
On February 1, 2001, the stockholders of Stone Energy Corporation and Basin
Exploration, Inc. voted in favor of, and thereby consummated, the combination,
through a pooling of interests, of the two companies in a tax-free,
stock-for-stock transaction. In connection with the approval of the merger,
stockholders of Stone Energy also approved a proposal to increase the authorized
shares of Stone common stock from 25 million to 100 million shares. Under the
merger agreement, Basin stockholders received 0.3974 of a share of Stone common
stock for each share of Basin common stock they owned. As such, Stone issued
approximately 7.4 million shares of common stock which, based upon Stone's
closing price of $53.70 on February 1, 2001, resulted in total equity value
related to the transaction of approximately $400 million. In addition, Stone
assumed, and subsequently retired with cash on hand, approximately $48 million
of Basin bank debt. The expenses incurred in relation to the merger are
currently estimated to total $27 million and will be a non-recurring item
recorded in the first quarter of 2001.
The combined company, called Stone Energy Corporation, had a total market
capitalization of approximately $1.3 billion as of March 15, 2001. The following
table compares Stone's 2000 stand-alone results to the combined company's 2000
results assuming the merger had occurred on January 1, 2000. These combined
results should be used for information purposes only as they are not necessarily
indicative of the results that would have occurred if the merger had been
completed on January 1, 2000.
SELECTED COMPARATIVE FINANCIAL AND OPERATIONAL DATA
YEAR ENDED DECEMBER 31, 2000
-----------------------------------------------
STONE COMBINED
------------------ --------------------
(in thousands, except per share and per unit amounts)
FINANCIAL HIGHLIGHTS
Total Revenues................................... $260,379 $386,166
Net Income....................................... 84,945 127,973
Per Share..................................... 4.51 4.86
Net Cash Flow from Operations (1)................ 198,886 300,097
Per Share (1)................................. 10.57 11.40
Working Capital.................................. 53,421 53,065
Oil and Gas Properties, net...................... 444,631 747,573
Total Assets..................................... 602,431 944,103
Long-Term Debt................................... 100,000 148,000
Stockholders' Equity............................. 356,743 592,231
Weighted Average Shares Outstanding - Diluted.... 18,824 26,335
OPERATIONAL HIGHLIGHTS
Production:
Oil (MBbls)................................... 3,334 4,449
Gas (MMcf).................................... 46,480 72,239
Oil and Gas (MMcfe)........................... 66,484 98,933
Average Sales Prices (2):
Oil (per Bbl)................................. $25.82 $26.66
Gas (per Mcf)................................. 3.66 3.64
Oil and Gas (per Mcfe)........................ 3.86 3.86
Estimated Proved Reserves:
Oil (MBbls)................................... 21,319 33,625
Gas (MMcf).................................... 272,238 398,524
Oil and Gas (MMcfe)........................... 400,152 600,274
Present Value of Estimated Future
Pre-Tax Net Cash Flows ...................... $2,029,374 $2,941,790
(1) Before working capital changes.
(2) Includes the effects of hedging.
2001 OUTLOOK
The merger with Basin, which was effective February 1, 2001, increased our
property base to 79 producing properties by adding 25 Gulf Coast Basin and 33
Rocky Mountain properties. Our estimated 2001 capital expenditures budget of
approximately $253 million is expected to be allocated approximately 90% to Gulf
Coast operations and 10% to Rocky Mountain activities. The 2001 planned
investment in the Rockies represents over a 200% increase from the investments
made by Basin in the region during 2000. We expect to drill 77 gross wells
during 2001, 43 in the onshore and shallow water offshore regions of the Gulf
Coast Basin and 34 in the Rocky Mountains. Approximately 65% of the estimated
drilling costs are expected to be dedicated to exploratory targets with the
remaining 35% allocated to the development of existing reserves. While the 2001
capital expenditures budget does not include any projected acquisitions, we
continue to seek growth opportunities that fit our specific acquisition profile.
Based on our commodity price and production projections, we expect to
finance our 2001 capital expenditures budget with cash flows from operations.
Our production goal for 2001 is to increase production 15% over 2000's combined
production of 98.9 Bcfe.
OIL AND GAS MARKETING
Our oil, natural gas and natural gas condensate production is sold at
current market prices under short-term contracts providing for variable or
market sensitive prices. Since alternative purchasers of oil and gas are readily
available, we believe that the loss of any of our major purchasers would not
result in a material adverse effect on our ability to market future oil and gas
production. From time to time, we may enter into transactions that hedge the
price of oil, natural gas and natural gas condensate. See "Item 7A. Quantitative
and Qualitative Disclosures About Market Risk - Commodity Price Risk."
COMPETITION AND MARKETS
Competition in the Gulf Coast Basin and the Rocky Mountains is intense,
particularly with respect to the acquisition of producing properties and proved
undeveloped acreage. We compete with major oil companies and other independent
producers of varying sizes, all of which are engaged in the acquisition of
properties and the exploration and development of such properties. Many of our
competitors have financial resources and exploration and development budgets
that are substantially greater than ours, which may adversely affect our ability
to compete. See "Risk Factors - Competition within our industry may adversely
affect our operations."
The availability of a ready market for and the price of any hydrocarbons
produced will depend on many factors beyond our control, including but not
limited to the amounts of domestic production and imports of foreign oil, the
marketing of competitive fuels, the proximity and capacity of natural gas
pipelines, the availability of transportation and other market facilities, the
demand for hydrocarbons, the effect of federal and state regulation of allowable
rates of production, taxation, the conduct of drilling operations and federal
regulation of natural gas. In addition, the restructuring of the natural gas
pipeline industry virtually eliminated the gas purchasing activity of
traditional interstate gas transmission pipeline buyers. See "Regulation-Federal
Regulation of Sales and Transportation of Natural Gas." Producers of natural gas
have therefore been required to develop new markets among gas marketing
companies, end users of natural gas and local distribution companies. All of
these factors, together with economic factors in the marketing area, generally
may affect the supply and/or demand for oil and gas and thus the prices
available for sales of oil and gas.
REGULATION
REGULATION OF PRODUCTION. In all areas where we conduct activities, there
are statutory provisions regulating the production of oil and natural gas under
which administrative agencies may enforce rules in connection with the location,
spacing, drilling, operation and production of both oil and gas wells, determine
the reasonable market demand for oil and gas and establish allowable rates of
production. These regulatory orders can limit the number of wells or the
location where wells may be drilled. Regulations can also restrict the rate of
production below the rate that these wells would otherwise produce in the
absence of such regulatory orders. Any of these actions could negatively impact
the amount or timing of revenues.
FEDERAL LEASES. We have oil and gas leases both onshore and in the Gulf of
Mexico which were granted by the federal government. Operations on onshore
federal leases must be conducted in accordance with permits issued by the Bureau
of Land Management and are subject to a number of other regulatory restrictions,
such as winter game restrictions and drilling limitations imposed by resource
management plans. Moreover, on certain federal leases, prior approval of
drillsite locations must be obtained from the Environmental Protection Agency
(the "EPA"). On large-scale projects, lessees may be required to perform
Environmental Impact Statements to assess the environmental effects of potential
development, which can delay project implementation or result in the imposition
of environmental restrictions that could have a material impact on the cost or
scope of such project.
Offshore leases are administered by the United States Department of the
Interior Minerals Management Service (the "MMS"). Offshore lessees must obtain
MMS approval of exploration, development and production plans prior to the
commencement of these operations. In addition to permits required from other
agencies (such as the Coast Guard, the Army Corps of Engineers and the EPA),
lessees must obtain a permit from the MMS prior to the commencement of drilling.
The MMS has enacted regulations requiring offshore production facilities located
on the Outer Continental Shelf ("OCS") to meet stringent engineering,
construction and safety specifications. The MMS also has regulations restricting
the flaring or venting of natural gas, and prohibiting the flaring of liquid
hydrocarbons and oil without prior authorization. Similarly, the MMS has enacted
other regulations governing the plugging and abandoning of wells located
offshore and the removal of all production facilities. Lessees must also comply
with detailed MMS regulations governing the calculation of royalty payments and
the valuation of production and permitted cost deductions for that purpose. In
2000, the MMS issued a final rule modifying the valuation procedures for the
calculation of royalties owed for crude oil sales. When oil production sales are
not in arms-length transactions, the new royalty calculation will base the
valuation of oil production on spot market prices instead of the posted prices
that were previously utilized. We are currently selling our crude oil under
arm's-length transactions in a manner that we believe to be acceptable to the
MMS under its new rule. As such, we believe that the effect, if any, of this new
rule will not have a material adverse effect on our results of operations.
With respect to any operations conducted on offshore federal leases,
liability may generally be imposed under the Outer Continental Shelf Lands Act
(the "OCSLA") for costs of clean-up and damages caused by pollution resulting
from these operations, other than damages caused by acts of war or the
negligence of third parties. To cover the various obligations of lessees on the
OCS, the MMS generally requires that lessees post substantial bonds or other
acceptable assurances that these obligations will be met. The cost of bonds or
other surety can be substantial and there is no assurance that bonds or other
surety can be obtained in all cases.
Since November 26, 1993, new levels of lease and area-wide bonds have been
required of lessees taking certain actions with regard to OCS leases. Operators
in the OCS waters of the Gulf of Mexico were required to increase their
area-wide bonds and individual lease bonds to $3 million and $1 million,
respectively, unless the MMS allowed exemptions or reduced amounts. We currently
have an area-wide right-of-way bond for $0.3 million and an area-wide lessee's
and operator's bond totaling $3 million issued in favor of the MMS for our
existing offshore properties. The MMS also has discretionary authority to
require supplemental bonding in addition to the foregoing required bonding
amounts but this authority is only exercised on a case-by-case basis at the time
of filing an assignment of record title interest for MMS approval. Based upon
certain financial parameters, we have been granted exempt status by the MMS,
which exempts us from the supplemental bonding requirements. There is no
assurance, however, that such exemption will be maintained. Under certain
circumstances, the MMS may require any of our operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially and
adversely affect our financial condition and operations.
OIL PRICE CONTROLS AND TRANSPORTATION RATES. Sales of crude oil, condensate
and gas liquids are not currently regulated and are made at negotiated prices.
Effective January 1, 1995, the Federal Energy Regulatory Commission (the "FERC")
implemented regulations establishing an indexing system for transportation rates
for oil that allowed for an increase in the cost of transporting oil to the
purchaser. The implementation of these regulations has not had a material
adverse effect on our results of operations.
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS. Historically,
the transportation and sale for resale of natural gas in interstate commerce
have been regulated pursuant to the Natural Gas Act of 1938 (the "NGA"), the
Natural Gas Policy Act of 1978 (the "NGPA") and regulations promulgated
thereunder by the FERC. In the past, the Federal government has regulated the
prices at which gas could be sold. While sales by producers of natural gas can
currently be made at uncontrolled market prices, Congress could reenact price
controls in the future. Deregulation of wellhead natural gas sales began with
the enactment of the NGPA. In 1989, Congress enacted the Natural Gas Wellhead
Decontrol Act (the "Decontrol Act"). The Decontrol Act removed all NGA and NGPA
price and non-price controls affecting wellhead sales of natural gas effective
January 1, 1993.
Commencing in 1992, the FERC issued Order No. 636 and subsequent orders
(collectively, "Order No. 636"), which require interstate pipelines to provide
transportation separate, or "unbundled," from the pipelines' sales of gas. Also,
Order No. 636 requires pipelines to provide open-access transportation on a
basis that is equal for all shippers. Although Order No. 636 does not directly
regulate our activities, the FERC has stated that it intends for Order No. 636
to foster increased competition within all phases of the natural gas industry.
The implementation of these orders has not had a material adverse effect on our
results of operations. The courts have largely affirmed the significant features
of Order No. 636 and numerous related orders pertaining to the individual
pipelines, although certain appeals remain pending and the FERC continues to
review and modify its open access regulations.
In 2000, the FERC issued Order No. 637 and subsequent orders (collectively,
"Order No. 637"), which imposed a number of additional reforms designed to
enhance competition in natural gas markets. Among other things, Order No. 637
revised the FERC pricing policy by waiving price ceilings for short-term
released capacity for a two year period, and effected changes in FERC
regulations relating to scheduling procedures, capacity segmentation, pipeline
penalties, rights of first refusal and information reporting. Most major aspects
of Order No. 637 are pending judicial review. We cannot predict whether and to
what extent FERC's market reforms will survive judicial review and, if so,
whether the FERC's actions will achieve the goal of increasing competition in
markets in which our natural gas is sold. However, we do not believe that we
will be affected by any action taken materially differently than other natural
gas producers and marketers with which we compete.
The OCSLA requires that all pipelines operating on or across the OCS provide
open-access, non-discriminatory service. Commencing in April 2000, the FERC
issued Order Nos. 639 and 639-A (collectively, "Order No. 639"), which imposed
certain reporting requirements applicable to "gas service providers" operating
on the OCS concerning their prices and other terms and conditions of service.
The purpose of Order No. 639 is to provide regulators and other interested
parties with sufficient information to detect and to remedy discriminatory
conduct by such service providers. The FERC has stated that these reporting
rules apply to OCS gatherers and has clarified that they may also apply to other
OCS service providers including platform operators performing dehydration,
compression, processing and related services for third parties. Judicial review
of Order No. 639 is currently pending. We cannot predict whether and to what
extent these regulations will survive such review, and what effect, if any, they
may have on us. The rules, if allowed to stand, may increase the frequency of
claims of discriminatory service, may decrease competition among OCS service
providers and may lessen the willingness of OCS gathering companies to provide
service on a discounted basis.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
ENVIRONMENTAL REGULATIONS. Our operations are subject to numerous laws and
regulations governing the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations may
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas and impose substantial liabilities for
pollution resulting from our operations. Failure to comply with these laws and
regulations may result in the assessment of administrative, civil and criminal
penalties or the imposition of injunctive relief. Changes in environmental laws
and regulations occur frequently, and any changes that result in more stringent
and costly waste handling, storage, transport, disposal or cleanup requirements
could materially adversely affect our operations and financial position, as well
as those of the oil and gas industry in general. While we believe that we are in
substantial compliance with current applicable environmental laws and
regulations and that continued compliance with existing requirements would not
have a material adverse impact on us, there is no assurance that this trend will
continue in the future.
The Oil Pollution Act, as amended ("OPA"), and regulations thereunder impose
a variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United States
waters. A "responsible party" includes the owner or operator of an onshore
facility, pipeline or vessel, or the lessee or permittee of the area in which an
offshore facility is located. OPA assigns liability to each responsible party
for oil cleanup costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or to cooperate fully
in the cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75 million in other damages. Few defenses exist
to the liability imposed by OPA.
OPA imposes ongoing requirements on a responsible party, including the
preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in
connection with an oil spill. Under OPA and a final rule adopted by the MMS in
August 1998, responsible parties of covered offshore facilities that have a
worst case oil spill of more than 1,000 barrels must demonstrate financial
responsibility in amounts ranging from at least $10 million in specified state
waters to at least $35 million in OCS waters, with higher amounts of up to $150
million in certain limited circumstances where the MMS believes such a level is
justified by the risks posed by the operations, or if the worst case oil-spill
discharge volume possible at the facility may exceed the applicable threshold
volumes specified under the MMS's final rule. We do not anticipate that we will
experience any difficulty in continuing to satisfy the MMS's requirements for
demonstrating financial responsibility under the current OPA and MMS's August
1998 final rule.
The Comprehensive Environmental Response, Compensation and Liability Act, as
amended ("CERCLA"), also known as the "Superfund" law, imposes liability,
without regard to fault or the legality of the original conduct, on certain
classes of persons that are considered to be responsible for the release of a
"hazardous substance" into the environment. These persons include the owner or
operator of the disposal site or sites where the release occurred and companies
that transported or disposed or arranged for the transport or disposal of the
hazardous substances found at the site. Persons who are or were responsible for
releases of hazardous substances under CERCLA may be subject to joint and
several liability for the costs of cleaning up the hazardous substances that
have been released into the environment and for damages to natural resources,
and it is not uncommon for neighboring landowners and other third parties to
file claims for personal injury and property damage allegedly caused by the
hazardous substances released into the environment. The EPA has indicated that
we may be potentially responsible for costs and liabilities associated with
alleged releases of hazardous substances at one site. See "Item 3. Legal
Proceedings-Environmental."
The Resource Conservation and Recovery Act, as amended ("RCRA"), generally
does not regulate most wastes generated by the exploration and production of oil
and gas. RCRA specifically excludes from the definition of hazardous waste
"drilling fluids, produced waters and other wastes associated with the
exploration, development or production of crude oil, natural gas or geothermal
energy." However, legislation has been proposed in Congress from time to time
that would reclassify certain oil and gas exploration and production wastes as
"hazardous wastes," which would make the reclassified wastes subject to much
more stringent handling, disposal and clean-up requirements. If such legislation
were to be enacted, it could have a significant impact on our operating costs,
as well as the oil and gas industry in general. Moreover, ordinary industrial
wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils,
may be regulated as hazardous waste.
We currently own or lease, and have in the past owned or leased, onshore
properties that for many years have been used for or associated with the
exploration and production of oil and gas. Although we have utilized operating
and disposal practices that were standard in the industry at the time,
hydrocarbons or other wastes may have been disposed of or released on or under
the properties owned or leased by us on or under other locations where such
wastes have been taken for disposal. In addition, most of these properties have
been operated by third parties whose treatment and disposal or release of
hydrocarbons or other wastes was not under our control. These properties and the
wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.
Under such laws, we could be required to remove or remediate previously disposed
wastes (including waste disposed of or released by prior owners or operators) or
property contamination (including groundwater contamination by prior owners or
operators), or to perform remedial plugging or closure operations to prevent
future contamination.
The Federal Water Pollution Control Act, as amended ("FWPCA"), imposes
restrictions and strict controls regarding the discharge of produced waters and
other oil and gas wastes into navigable waters. Permits must be obtained to
discharge pollutants to waters and to conduct construction activities in waters
and wetlands. The FWPCA and similar state laws provide for civil, criminal and
administrative penalties for any unauthorized discharges of pollutants and
unauthorized discharges of reportable quantities of oil and other hazardous
substances. Many state discharge regulations and the Federal National Pollutant
Discharge Elimination System general permits prohibit the discharge of produced
water and sand, drilling fluids, drill cuttings and certain other substances
related to the oil and gas industry into coastal waters. Although the costs to
comply with zero discharge mandates under federal or state law may be
significant, the entire industry is expected to experience similar costs and we
believe that these costs will not have a material adverse impact on our results
of operations or financial position. The EPA has adopted regulations requiring
certain oil and gas exploration and production facilities to obtain permits for
storm water discharges. Costs may be associated with the treatment of wastewater
or developing and implementing storm water pollution prevention plans.
EMPLOYEES
At March 15, 2001, the combined company had 200 full time employees. We
believe that our relationships with our employees are satisfactory. None of our
employees are covered by a collective bargaining agreement. From time to time we
utilize the services of independent contractors to perform various field and
other services.
FORWARD-LOOKING STATEMENTS
This Form 10-K and the information incorporated by reference contain
statements that constitute "forward-looking statements" within the meaning of
Section 27A of the Securities Act and Section 21E of the Securities Exchange
Act. The words "expect", "project", "estimate", "believe", "anticipate",
"intend", "budget", "plan", "forecast", "predict" and other similar expressions
are intended to identify forward-looking statements. These statements appear in
a number of places and include statements regarding our plans, beliefs or
current expectations, including the plans, beliefs and expectations of our
officers and directors with respect to, among other things:
o earnings growth;
o budgeted capital expenditures;
o increases in oil and gas production;
o future project dates;
o our outlook on oil and gas prices;
o estimates of our oil and gas reserves;
o our future financial condition or results of operations; and
o our business strategy and other plans and objectives for future
operations.
When considering any forward-looking statement, you should keep in mind the
risk factors and other cautionary statements in this Form 10-K that could cause
our actual results to differ materially from those contained in any
forward-looking statement. Furthermore, the assumptions that support our
forward-looking statements are based upon information that is currently
available and is subject to change. We specifically disclaim all responsibility
to publicly update any information contained in a forward-looking statement or
any forward-looking statement in its entirety and therefore disclaim any
resulting liability for potentially related damages.
All forward-looking statements attributable to Stone Energy Corporation are
expressly qualified in their entirety by this cautionary statement.
RISK FACTORS
Our business is subject to a number of risks including, but not limited to,
those described below:
OIL AND GAS PRICE DECLINES AND VOLATILITY COULD ADVERSELY AFFECT OUR REVENUES,
CASH FLOWS AND PROFITABILITY.
Our revenues, profitability and future rate of growth depend substantially
upon the market prices of oil and natural gas, which fluctuate widely. Factors
that can cause this fluctuation include:
o relatively minor changes in the supply of and demand for oil and
natural gas;
o market uncertainty;
o the level of consumer product demand;
o weather conditions;
o domestic and foreign governmental regulations;
o the price and availability of alternative fuels;
o political and economic conditions in oil producing countries,
particularly those in the Middle East;
o the foreign supply of oil and natural gas;
o the price of oil and gas imports; and
o overall economic conditions.
We cannot predict future oil and natural gas prices. At various times,
excess domestic and imported supplies have depressed oil and gas prices.
Declines in oil and natural gas prices may adversely affect our financial
condition, liquidity and results of operations. Lower prices may reduce the
amount of oil and natural gas that we can produce economically and may also
create ceiling test write-downs of our oil and gas properties. Substantially all
of our oil and natural gas sales are made in the spot market or pursuant to
contracts based on spot market prices, not long-term fixed price contracts.
In an attempt to reduce our price risk, we periodically enter into hedging
transactions with respect to a portion of our expected future production. We
cannot assure you that such transactions will reduce the risk or minimize the
effect of any decline in oil or natural gas prices. Any substantial or extended
decline in the prices of or demand for oil or natural gas would have a material
adverse effect on our financial condition and results of operations.
THE MARKETABILITY OF STONE'S PRODUCTION DEPENDS MOSTLY UPON THE AVAILABILITY,
PROXIMITY AND CAPACITY OF GAS GATHERING SYSTEMS, PIPELINES AND PROCESSING
FACILITIES.
The marketability of our production depends upon the availability, operation
and capacity of gas gathering systems, pipelines and processing facilities. The
unavailability or lack of capacity of these systems and facilities could result
in the shut-in of producing wells or the delay or discontinuance of development
plans for properties. Federal and state regulation of oil and gas production and
transportation, general economic conditions and changes in supply and demand
could adversely affect our ability to produce and market our oil and natural
gas. If market factors changed dramatically, the financial impact on us could be
substantial. The availability of markets and the volatility of product prices
are beyond our control and represent a significant risk.
ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE.
This Form 10-K contains estimates of our proved oil and gas reserves and the
estimated future net revenues from such reserves. These estimates are based upon
various assumptions, including assumptions required by the Securities and
Exchange Commission relating to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of
estimating oil and gas reserves is complex. This process requires significant
decisions and assumptions in the evaluation of available geological,
geophysical, engineering and economic data for each reservoir. Therefore, these
estimates are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves will most likely vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves
set forth in this document and the information incorporated by reference. Our
properties may also be susceptible to hydrocarbon drainage from production by
other operators on adjacent properties. In addition, we may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing oil and gas prices and other factors, many of which are
beyond our control. Actual production, revenues, taxes, development expenditures
and operating expenses with respect to our reserves will likely vary from the
estimates used. Such variances may be material.
At December 31, 2000, approximately 19% of our estimated proved reserves
were undeveloped and approximately 23% of the combined company's estimated
proved reserves were undeveloped. Undeveloped reserves, by their nature, are
less certain. Recovery of undeveloped reserves requires significant capital
expenditures and successful drilling operations. The reserve data assumes that
we will make significant capital expenditures to develop our reserves. Although
we have prepared estimates of our oil and gas reserves and the costs associated
with these reserves in accordance with industry standards, we cannot assure you
that the estimated costs are accurate, that development will occur as scheduled
or that the actual results will be as estimated.
You should not assume that the present value of future net revenues referred
to in this Form 10-K and the information incorporated by reference is the
current fair value of our estimated oil and gas reserves. In accordance with
Securities and Exchange Commission requirements, the estimated discounted future
net cash flows from proved reserves are generally based on prices and costs as
of the date of the estimate. Actual future prices and costs may be materially
higher or lower than the prices and costs as of the date of the estimate. Any
changes in consumption by gas purchasers or in governmental regulations or
taxation will also affect actual future net cash flows. The timing of both the
production and the expenses from the development and production of oil and gas
properties will affect the timing of actual future net cash flows from proved
reserves and their present value. In addition, the 10% discount factor, which is
required by the Securities and Exchange Commission to be used in calculating
discounted future net cash flows for reporting purposes, is not necessarily the
most accurate discount factor.
LOWER OIL AND GAS PRICES MAY CAUSE US TO RECORD CEILING TEST WRITE-DOWNS.
We use the full cost method of accounting to account for our oil and gas
operations. Accordingly, we capitalize the cost to acquire, explore for and
develop oil and gas properties. Under full cost accounting rules, the net
capitalized costs of oil and gas properties may not exceed a "ceiling limit"
which is based upon the present value of estimated future net cash flows from
proved reserves, discounted at 10%, plus the lower of cost or fair value of
unproved properties. If net capitalized costs of oil and gas properties exceed
the ceiling limit, we must charge the amount of the excess to earnings. This is
called a "ceiling test write-down." This charge does not impact cash flow from
operating activities, but does reduce our stockholders' equity. The risk that we
will be required to write down the carrying value of oil and gas properties
increases when oil and gas prices are low or volatile. In addition, write-downs
may occur if we experience substantial downward adjustments to our estimated
proved reserves. Due to low oil and gas prices at the end of 1998, in December
1998 we recorded an after-tax write-down of $57.4 million ($89.1 million
pre-tax). We cannot assure you that we will not experience ceiling test
write-downs in the future.
WE MAY NOT BE ABLE TO OBTAIN ADEQUATE FINANCING TO EXECUTE OUR OPERATING
STRATEGY.
We have historically addressed our long-term liquidity needs through the use
of bank credit facilities, the issuance of debt and equity securities and the
use of cash provided by operating activities. We continue to examine the
following alternative sources of long-term capital:
o bank borrowings or the issuance of debt securities;
o the issuance of common stock, preferred stock or other equity
securities;
o joint venture financing; and
o production payments.
The availability of these sources of capital will depend upon a number of
factors, some of which are beyond our control. These factors include general
economic and financial market conditions, oil and natural gas prices and our
market value and operating performance. We may be unable to execute our
operating strategy if we cannot obtain capital from these sources.
WE MAY NOT BE ABLE TO FUND OUR PLANNED CAPITAL EXPENDITURES.
We spend and will continue to spend a substantial amount of capital for the
development, exploration, acquisition and production of oil and gas reserves.
Our capital expenditures were $164.7 million during 2000, $123.9 million during
1999 and $158.9 million during 1998. We estimate that capital expenditures for
the combined company in 2001 will be approximately $253 million. If low oil and
natural gas prices, operating difficulties or other factors, many of which are
beyond our control, cause our revenues or cash flows from operations to
decrease, we may be limited in our ability to spend the capital necessary to
complete our drilling program. After utilizing our available sources of
financing, we may be forced to raise additional debt or equity proceeds to fund
such expenditures. We cannot assure you that additional debt or equity financing
or cash generated by operations will be available to meet these requirements.
WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES.
In general, the volume of production from oil and gas properties declines as
reserves are depleted. The decline rates depend on reservoir characteristics.
Gulf of Mexico reservoirs tend to experience steep declines, while declines in
other regions tend to be relatively slow. A significant portion of our
production is from Gulf of Mexico reservoirs. Our reserves will decline as they
are produced unless we acquire properties with proved reserves or conduct
successful development and exploration activities. Our future natural gas and
oil production is highly dependent upon our level of success in finding or
acquiring additional reserves.
Our recent growth, including our recent acquisition of Basin, is due in part
to acquisitions of producing properties. The successful acquisition of producing
properties requires an assessment of a number of factors beyond our control.
These factors include recoverable reserves, future oil and gas prices, operating
costs and potential environmental and other liabilities, title issues and other
factors. Such assessments are inexact and their accuracy is inherently
uncertain. In connection with such assessments, we perform a review of the
subject properties, which we believe is generally consistent with industry
practices. However, such a review will not reveal all existing or potential
problems. In addition, the review will not permit a buyer to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. We cannot assure you that we will be able to acquire properties at
acceptable prices because the competition for producing oil and gas properties
is intense and many of our competitors have financial and other resources which
are substantially greater than those available to us.
Our strategy includes increasing our production and reserves by the
implementation of a carefully designed field-wide development plan. These
development plans are often formulated prior to the acquisition of a property.
However, we cannot assure you that our future development, acquisition and
exploration activities will result in additional proved reserves or that we will
be able to drill productive wells at acceptable costs.
OUR OPERATIONS ARE SUBJECT TO NUMEROUS RISKS OF OIL AND GAS DRILLING AND
PRODUCTION ACTIVITIES.
Oil and gas drilling and production activities are subject to numerous
risks, including the risk that no commercially productive oil or natural gas
reservoirs will be found. The cost of drilling and completing wells is often
uncertain. Oil and gas drilling and production activities may be shortened,
delayed or canceled as a result of a variety of factors, many of which are
beyond our control. These factors include:
o unexpected drilling conditions;
o pressure or irregularities in formations;
o equipment failures or accidents;
o weather conditions;
o shortages in experienced labor; and
o shortages or delays in the delivery of equipment.
The prevailing prices of oil and natural gas also affect the cost of and the
demand for drilling rigs, production equipment and related services.
We cannot assure you that the new wells we drill will be productive or that
we will recover all or any portion of our investment. Drilling for oil and
natural gas may be unprofitable. Drilling activities can result in dry wells and
wells that are productive but do not produce sufficient net revenues after
operating and other costs to recoup drilling costs.
OUR INDUSTRY EXPERIENCES NUMEROUS OPERATING RISKS.
The exploration, development and operation of oil and gas properties
involves a variety of operating risks including the risk of fire, explosions,
blowouts, pipe failure, abnormally pressured formations and environmental
hazards. Environmental hazards include oil spills, gas leaks, pipeline ruptures
or discharges of toxic gases. If any of these industry operating risks occur, we
could have substantial losses. Substantial losses may be caused by injury or
loss of life, severe damage to or destruction of property, natural resources and
equipment, pollution or other environmental damage, clean-up responsibilities,
regulatory investigation and penalties and suspension of operations.
Additionally, our offshore operations are subject to the additional hazards of
marine operations, such as capsizing, collision and adverse weather and sea
conditions. In accordance with industry practice, we maintain insurance against
some, but not all, of the risks described above.
We currently maintain loss of production insurance to protect against
uncontrollable disruptions in production operations. The policy covers the
majority of our anticipated production volumes from selected offshore properties
on an individual facility basis. The value of lost production would be
calculated using the average of the last 45 days' revenue from the facility
prior to the loss. We currently maintain coverage of up to $75 million per
occurrence that becomes effective after 30 consecutive days of lost production.
We also maintain additional insurance of various types to cover our
operations, including maritime employer's liability and comprehensive general
liability. Coverage amounts are provided by primary and excess umbrella
liability policies with ultimate limits of $50 million. In addition, we maintain
up to $50 million in operator's extra expense insurance, which provides coverage
for the care, custody and control of wells drilled and/or completed plus redrill
and pollution coverage. The exact amount of coverage for each well is dependent
upon its depth and location.
We cannot assure you that our insurance will be adequate to cover losses or
liabilities. Also, we cannot predict the continued availability of insurance at
premium levels that justify its purchase. The occurrence of a significant event,
not fully insured or indemnified against, could materially and adversely affect
our financial condition and operations.
A PORTION OF OUR PRODUCTION, REVENUES AND CASH FLOWS ARE DERIVED FROM ASSETS
THAT ARE CONCENTRATED IN A GEOGRAPHIC AREA.
Production from South Pelto Block 23 and Eugene Island Block 243 accounted
for approximately 26% and 23%, respectively, of our total oil and gas production
volumes during 2000. On a combined basis, production from South Pelto Block 23
and Eugene Island Block 243 accounted for approximately 18% and 16%,
respectively, of the combined company's production volumes during 2000.
LEVERAGE MATERIALLY AFFECTS OUR OPERATIONS.
As of December 31, 2000, our long-term debt was $100 million and we had
$192.5 million of available borrowing capacity under our bank credit facility
with no outstanding draws. The borrowing base limitation on our credit facility
is periodically redetermined based on an evaluation of our reserves. Upon a
redetermination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our bank debt. We may not
have sufficient funds to make such repayments.
Our level of debt affects our operations in several important ways,
including the following:
o a large portion of our cash flow from operations may be used to pay
interest on borrowings;
o the covenants contained in the agreements governing our debt limit our
ability to borrow additional funds or to dispose of assets;
o the covenants contained in the agreements governing our debt may
affect our flexibility in planning for, and reacting to, changes in
business conditions;
o a high level of debt may impair our ability to obtain additional
financing in the future for working capital, capital expenditures,
acquisitions, general corporate or other purposes;
o our leveraged financial position may make us more vulnerable to
economic downturns and may limit our ability to withstand competitive
pressures;
o any debt that we incur under our credit facility will be at variable
rates which makes us vulnerable to increases in interest rates; and
o a high level of debt will affect our flexibility in planning for or
reacting to changes in market conditions.
In addition, we may significantly alter our capitalization in order to make
future acquisitions or develop our properties. These changes in capitalization
may significantly increase our level of debt. A higher level of debt increases
the risk that we may default on our debt obligations. Our ability to meet our
debt obligations and to reduce our level of debt depends on our future
performance. General economic conditions and financial, business and other
factors affect our operations and our future performance. Many of these factors
are beyond our control.
If we are unable to repay our debt at maturity out of cash on hand, we could
attempt to refinance such debt, or repay such debt with the proceeds from an
equity offering. We cannot assure you that we will be able to generate
sufficient cash flow to pay the interest on our debt or that future borrowings
or equity financing will be available to pay or refinance such debt. The terms
of our debt, including our credit facility and the indenture, may also prohibit
us from taking such actions. Factors that will affect our ability to raise cash
through an offering of our capital stock or a refinancing of our debt include
financial market conditions and our market value and operating performance at
the time of such offering or other financing. We cannot assure you that any such
offering or refinancing can be successfully completed.
COMPETITION WITHIN OUR INDUSTRY MAY ADVERSELY AFFECT OUR OPERATIONS.
We operate in a highly competitive environment. We compete with major and
independent oil and gas companies for the acquisition of desirable oil and gas
properties and the equipment and labor required to develop and operate such
properties. Many of these competitors have financial and other resources
substantially greater than ours.
OUR OIL AND GAS OPERATIONS ARE SUBJECT TO VARIOUS U.S. FEDERAL, STATE AND LOCAL
GOVERNMENTAL REGULATIONS THAT MATERIALLY AFFECT OUR OPERATIONS.
Our oil and gas operations are subject to various U.S. federal, state and
local governmental regulations. These regulations may be changed in response to
economic or political conditions. Regulated matters include permits for
discharges of wastewaters and other substances generated in connection with
drilling operations, bonds or other financial responsibility requirements to
cover drilling contingencies and well plugging and abandonment costs, reports
concerning operations, the spacing of wells and unitization and pooling of
properties and taxation. At various times, regulatory agencies have imposed
price controls and limitations on oil and gas production. In order to conserve
supplies of oil and gas, these agencies have restricted the rates of flow of oil
and gas wells below actual production capacity. In addition, the OPA requires
operators of offshore facilities to prove that they have the financial
capability to respond to costs that may be incurred in connection with potential
oil spills. Under such law and other federal and state environmental statutes,
including CERCLA and RCRA, owners and operators of certain defined onshore and
offshore facilities are strictly liable for spills of oil and other regulated
substances, subject to certain limitations. A substantial spill from one of our
facilities could have a material adverse effect on our results of operations,
competitive position or financial condition. Federal, state and local laws
regulate production, handling, storage, transportation and disposal of oil and
gas, by-products from oil and gas and other substances, and materials produced
or used in connection with oil and gas operations. We cannot predict the
ultimate cost of compliance with these requirements or their effect on our
operations.
THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE.
Our operations are dependent upon a relatively small group of key management
and technical personnel. We cannot assure you that such individuals will remain
with us for the immediate or foreseeable future. We do not have employment
contracts with any of these individuals. The unexpected loss of the services of
one or more of these individuals could have a detrimental effect on us.
HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS.
In order to manage our exposure to price risks in the marketing of our oil
and gas, we enter into oil and gas price hedging arrangements with respect to a
portion of our expected production. Our hedging policy provides that, without
prior approval of our board of directors, generally not more than 50% of our
production quantities may be hedged. These arrangements may include futures
contracts on the New York Mercantile Exchange. While intended to reduce the
effects of volatile oil and gas prices, such transactions, depending on the
hedging instrument used, may limit our potential gains if oil and gas prices
were to rise substantially over the price established by the hedge. In addition,
such transactions may expose us to the risk of financial loss in certain
circumstances, including instances in which:
o our production is less than expected;
o there is a widening of price differentials between delivery points for
our production and the delivery point assumed in the hedge arrangement;
o the counterparties to our futures contracts fail to perform the
contracts; or
o a sudden, unexpected event materially impacts oil or gas prices.
OWNERSHIP OF WORKING INTERESTS IN CERTAIN OF OUR PROPERTIES BY CERTAIN OF OUR
OFFICERS AND DIRECTORS MAY CREATE CONFLICTS OF INTEREST.
James H. Stone and Joe R. Klutts, both directors of Stone Energy,
collectively own 9% of the working interest in certain wells drilled on Section
19 on the east flank of Weeks Island Field. These interests were acquired at the
same time that our predecessor company acquired its interests in Weeks Island
Field. In their capacity as working interest owners, they are required to pay
their proportional share of all costs and are entitled to receive their
proportional share of revenues.
Certain of our officers were granted net profits interests in some of our
oil and gas properties acquired prior to 1993. The recipients of net profits
interests are not required to pay capital costs incurred on the properties
burdened by such interests.
As a result of these transactions, a conflict of interest may exist between
us and such directors and officers with respect to the drilling of additional
wells or other development operations.
WE DO NOT PAY DIVIDENDS.
We have never declared or paid any cash dividends on our common stock and
have no intention to do so in the near future. The restrictions on our present
or future ability to pay dividends are included in the provisions of the
Delaware General Corporation Law and in certain restrictive provisions in the
indenture executed in connection with our 8-3/4% Senior Subordinated Notes due
2007. In addition, we have entered into a credit facility that contains
provisions that may have the effect of limiting or prohibiting the payment of
dividends.
OUR CERTIFICATE OF INCORPORATION AND BYLAWS HAVE PROVISIONS THAT DISCOURAGE
CORPORATE TAKEOVERS AND COULD PREVENT SHAREHOLDERS FROM REALIZING A PREMIUM ON
THEIR INVESTMENT.
Certain provisions of our Certificate of Incorporation, Bylaws and
shareholders' rights plan and the provisions of the Delaware General Corporation
Law may encourage persons considering unsolicited tender offers or other
unilateral takeover proposals to negotiate with our board of directors rather
than pursue non-negotiated takeover attempts. Our Bylaws provide for a
classified board of directors. Also, our Certificate of Incorporation authorizes
our board of directors to issue preferred stock without stockholder approval and
to set the rights, preferences and other designations, including voting rights
of those shares, as the board may determine. Additional provisions include
restrictions on business combinations and the availability of authorized but
unissued common stock. These provisions, alone or in combination with each other
and with the rights plan described below, may discourage transactions involving
actual or potential changes of control, including transactions that otherwise
could involve payment of a premium over prevailing market prices to stockholders
for their common stock.
During 1998, our board of directors adopted a shareholder rights agreement,
pursuant to which uncertificated stock purchase rights were distributed to our
stockholders at a rate of one right for each share of common stock held of
record as of October 26, 1998. The rights plan is designed to enhance the
board's ability to prevent an acquirer from depriving stockholders of the
long-term value of their investment and to protect stockholders against attempts
to acquire us by means of unfair or abusive takeover tactics. However, the
existence of the rights plan may impede a takeover not supported by our board,
including a takeover that may be desired by a majority of our stockholders or
involving a premium over the prevailing stock price.
ITEM 2. PROPERTIES
We have grown principally through the acquisition and subsequent development
and exploitation of properties purchased from major and independent oil
companies. During 2000, we acquired working interests in two new producing
fields bringing the total number of producing properties that we operate to 21.
Of these properties, 13 are located in the Gulf of Mexico and eight are onshore
Louisiana. In addition to acquiring producing properties, in May 2000, we were
awarded primary term leases at West Cameron Block 177 and Vermilion Block 276.
The merger with Basin Exploration added 58 producing properties to our asset
base increasing the number of producing properties in which we have a working
interest to 79, 46 of which are located in the Gulf Coast Basin and 33 are in
the Rocky Mountains. Of the 79 producing properties, we operate 52.
OIL AND GAS RESERVES
The following table sets forth our estimated net proved oil and gas reserves
and the present value of estimated future pre-tax net cash flows related to such
reserves as of December 31, 2000. The proved natural gas reserves at December
31, 2000 excluded 4 Bcf of gas dedicated to a production payment. Also excluded
are the related estimated future net cash flows and the present value of
estimated future net cash flows of $9 million and $8.5 million, respectively.
The information in this Form 10-K relating to Stone's estimated oil and gas
reserves and the estimated future net cash flows attributable thereto is based
upon the reserve reports (the "Reserve Reports") prepared as of December 31,
2000 by Atwater Consultants, Ltd. and Cawley, Gillespie & Associates, Inc., both
independent petroleum engineers. All product pricing and cost estimates used in
the Reserve Reports are in accordance with the rules and regulations of the
Securities and Exchange Commission, and, except as otherwise indicated, the
reported amounts give no effect to federal or state income taxes otherwise
attributable to estimated future cash flows from the sale of oil and gas. The
present value of estimated future net cash flows has been calculated using a
discount factor of 10%.
You should not assume that the estimated future net cash flows or the
present value of estimated future net cash flows, referred to in the table
below, represent the fair value of our estimated oil and gas reserves. As
required by the SEC, we determine estimated future net cash flows using market
prices for oil and gas on the last day of the fiscal period. Using the
information contained in the Reserve Reports, the average 2000 year-end product
prices for all of our properties were $28.01 per barrel of oil and $10.13 per
Mcf of gas. During the first quarter of 2001, market prices for oil and gas have
generally decreased, which would result in a reduction of estimated future net
cash flows and the present value of estimated future net cash flows if
recomputed.
PROVED PROVED TOTAL
DEVELOPED UNDEVELOPED PROVED
--------------------------- ---------------------------- --------------------------------
STONE COMBINED (1) STONE COMBINED (1) STONE COMBINED (1)
---------- ------------- ----------- ------------- ------------ --------------
Oil (MBbls)...................... 17,073 25,374 4,246 8,251 21,319 33,625
Gas (MMcf)....................... 221,433 307,320 50,805 91,204 272,238 398,524
Total oil and gas (MMcfe)........ 323,871 459,564 76,281 140,710 400,152 600,274
Estimated future net
cash flows before income
taxes (in thousands)............$2,421,951 $3,299,865 $516,615 $900,899 $2,938,566 $4,200,764
Present value of estimated
future net cash flows before
income taxes (in thousands).... $1,713,634 $2,365,721 $315,740 $576,069 $2,029,374 $2,941,790
(1) Estimates for Basin Exploration at December 31, 2000 were prepared by the
independent petroleum engineering firm of Ryder Scott Company. Based on
the combined reserve reports, the average 2000 year-end product prices
for the combined company were $27.30 per barrel of oil and $9.97 per Mcf
of gas.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein only represents estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the existence of
development plans. As a result, estimates of reserves made by different
engineers for the same property will often vary. Results of drilling, testing
and production subsequent to the date of an estimate may justify a revision of
such estimates. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately produced. Further, the estimated
future net revenues from proved reserves and the present value thereof are based
upon certain assumptions, including geological success, prices, future
production levels and costs that may not prove to be correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
meaningfulness of these estimates depends on the accuracy of the assumptions
upon which they are based.
As an operator of domestic oil and gas properties, we have filed Department
of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as required by
Public Law 93-275. There are differences between the reserves as reported on
Form EIA-23 and as reported herein. The differences are attributable to the fact
that Form EIA-23 requires that an operator report the total reserves
attributable to wells that it operates, without regard to percentage ownership
(i.e., reserves are reported on a gross operated basis, rather than on a net
interest basis) or non-operated wells in which it owns an interest.
ACQUISITION, PRODUCTION AND DRILLING ACTIVITY
ACQUISITION AND DEVELOPMENT COSTS. The following table sets forth certain
information regarding the costs incurred in our acquisition, development and
exploratory activities during the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
---------- ---------- ----------
(In thousands)
Acquisition costs.................................. $10,803 $31,046 $17,748
Development costs.................................. 57,231 53,463 54,889
Exploratory costs.................................. 87,510 32,117 81,765
---------- ---------- ----------
Subtotal........................................... 155,544 116,626 154,402
Capitalized general and administrative costs and
interest, net of fees and reimbursements........ 9,146 7,284 4,480
---------- ---------- ----------
Total additions to oil and gas properties (1)...... $164,690 $123,910 $158,882
========== ========== ==========
(1) Total additions to oil and gas properties during 1999 included non-cash
additions of $20.3 million related to acquisitions made through production
payments.
COMBINED ACQUISITION AND DEVELOPMENT COSTS. Total additions to oil and gas
properties for the combined company during 2000 were approximately $270 million.
PRODUCTIVE WELL AND ACREAGE DATA. The following table sets forth certain
statistics regarding the number of productive wells and developed and
undeveloped acreage as of December 31, 2000.
STONE COMBINED
---------------------------------------- -----------------------------------------
GROSS NET GROSS NET
---------------- --------------- ---------------- ----------------
Productive Wells:
Oil............................ 87.00 (1) 63.46 368.00 (2) 244.46
Gas............................ 72.00 (3) 55.32 154.00 (4) 94.32
---------------- --------------- ---------------- ----------------
Total...................... 159.00 118.78 522.00 338.78
================ =============== ================ ================
Developed Acres:
Onshore Gulf Coast............. 3,773.71 2,947.50 3,933.71 2,996.25
Gulf of Mexico................. 13,764.64 5,755.87 148,116.82 73,385.67
Rocky Mountain Basin........... - - 48,805.44 28,406.42
---------------- --------------- ---------------- ----------------
Total...................... 17,538.35 8,703.37 200,855.97 104,788.34
================ =============== ================ ================
Undeveloped Acres:
Onshore Gulf Coast............. 27,757.53 17,852.01 39,869.62 23,246.64
Gulf of Mexico................. 83,419.22 70,381.69 257,944.71 213,724.08
Rocky Mountain Basin........... - - 211,213.54 127,885.23
---------------- --------------- ---------------- ----------------
Total...................... 111,176.75 (5) 88,233.70 509,027.87 (6) 364,855.95
================ =============== ================ ================
(1) 6 gross wells each have dual completions.
(2) 47 gross wells each have dual completions.
(3) 9 gross wells each have dual completions.
(4) 18 gross wells each have dual completions.
(5) Leases covering approximately 1% of our undeveloped gross acreage will
expire in 2001, 6% in 2002, 5% in 2003, 1% in 2004 and 10% in 2005. Leases
covering the remainder of our undeveloped gross acreage (77%) are held by
production.
(6) Leases covering approximately 6% of the undeveloped gross acreage will
expire in 2001, 9% in 2002, 17% in 2003, 14% in 2004 and 17% in 2005.
Leases covering the remainder of the undeveloped gross acreage (37%) are
held by production.
DRILLING ACTIVITY. The following table sets forth our drilling activity for
the periods indicated.
YEAR ENDED DECEMBER 31,
-------------------------------------------------------------------------
2000 1999 1998
---------------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
--------- --------- --------- -------- --------- --------
Exploratory Wells:
Productive................... 14.00 10.95 8.00 5.16 6.00 5.33
Nonproductive................ 9.00 6.35 1.00 0.31 4.00 3.35
Development Wells:
Productive................... 8.00 7.28 6.00 4.89 3.00 2.63
Nonproductive................ 1.00 0.82 - - 1.00 0.98
COMBINED DRILLING ACTIVITY. Drilling activity for 2000 for the combined
company was as follows:
YEAR ENDED DECEMBER 31, 2000
------------------------------------
COMBINED COMBINED
GROSS NET
---------------- ----------------
Exploratory Wells:
Productive.................. 30.00 17.35
Nonproductive............... 20.00 10.65
Development Wells:
Productive.................. 24.00 16.68
Nonproductive............... 1.00 0.82
TITLE TO PROPERTIES
We believe that we have satisfactory title on substantially all of our
producing properties in accordance with standards generally accepted in the oil
and gas industry. Our properties are subject to customary royalty interests,
liens for current taxes and other burdens, which we believe do not materially
interfere with the use of or affect the value of such properties. Prior to
acquiring undeveloped properties, we perform a title investigation that is
thorough but less vigorous than that conducted prior to drilling, which is
consistent with standard practice in the oil and gas industry. Before we
commence drilling operations, we conduct a thorough title examination and
perform curative work with respect to significant defects before proceeding with
operations. We have performed a thorough title examination with respect to
substantially all of our producing properties.
ITEM 3. LEGAL PROCEEDINGS
ENVIRONMENTAL
In August 1989, we were advised by the EPA that it believed we were a
potentially responsible party (a "PRP") for the cleanup of an oil field waste
disposal facility located near Abbeville, Louisiana, which was included on
CERCLA's National Priority List (the "Superfund List") by the EPA in March 1989.
Although we did not dispose of wastes or salt water at this site, the EPA
contends that transporters of salt water may have rinsed their trucks' tanks at
this site. By letter dated December 9, 1998, the EPA made demand for cleanup
costs on 23 of the PRP's, including us, who had not previously settled with the
EPA. Since that time we, together with other PRPs, have been negotiating the
settlement of our respective liability for environmental conditions at this site
with the U.S. Department of Justice. Given the number of PRP's at this site and
the current satisfactory progress of these negotiations, we do not believe that
any liability for this site would have a material adverse affect on our
financial condition. A tentative settlement has been reached with the U.S.
Department of Justice regarding our potential liability at this site. The amount
of this tentative settlement is immaterial to our financial statements and was
not accrued at December 31, 2000. However, the settlement has not been formally
approved by all parties, and we cannot assure you that a settlement will be
formally approved.
OTHER PROCEEDINGS
We are named as a defendant in certain lawsuits and are a party to certain
regulatory proceedings arising in the ordinary course of business. We do not
expect these matters, individually or in the aggregate, to have a material
adverse effect on our financial condition.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of our stockholders during the fourth
quarter of 2000.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names, ages (as of
March 15, 2001) and positions held by each of our executive officers. Our
executive officers serve at the discretion of the Board of Directors.
Name Age Position
---- --- --------
D. Peter Canty................................ 54 President, Chief Executive Officer and Director
Andrew L. Gates, III.......................... 53 Vice President, Secretary and General Counsel
Craig L. Glassinger........................... 53 Vice President - Resources
Phillip T. Lalande............................ 51 Vice President - Engineering
E. J. Louviere................................ 52 Vice President - Land
J. Kent Pierret............................... 45 Vice President - Accounting and Controller
James H. Prince............................... 58 Vice President, Chief Financial Officer and Treasurer
The following biographies describe the business experience of our executive
officers for at least the past five years. Stone Energy Corporation was formed
in March 1993 to become a holding company for The Stone Petroleum Corporation
("TSPC") and its subsidiaries. In 1997, TSPC was dissolved after the majority of
its assets were transferred to Stone Energy Corporation.
D. Peter Canty was named Chief Executive Officer on January 1, 2001 and
President in March 1994. He has also served as Chief Operating Officer and as a
Director since March 1993. Mr. Canty was President of TSPC from 1994 to 1997.
Andrew L. Gates, III has served as Vice President, Secretary and General
Counsel since August 1995.
Craig L. Glassinger was named Vice President - Resources in February 2001.
From December 1995 to February 2001 he served as Vice President - Acquisitions.
Phillip T. Lalande has served as Vice President - Engineering since March
1995.
E. J. Louviere has served as Vice President - Land since June 1995.
J. Kent Pierret was named Vice President - Accounting and Controller in June
1999. Prior to rejoining us, he was a partner in the firm of Pierret, Veazey &
Co., CPAs (and its predecessors) from May 1988 to May 1999, which performed a
substantial amount of our financial reporting, tax compliance and financial
advisory services.
James H. Prince was named Chief Financial Officer in August 1999 and
Treasurer in June 1999. He previously served as Chief Accounting Officer and
Controller from 1993 to June 1999.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Since July 9, 1993, our common stock has been listed on the New York Stock
Exchange under the symbol "SGY." The following table sets forth, for the periods
indicated, the high and low closing prices per share of our common stock.
HIGH LOW
------- -------
1999
First Quarter............................... $33.063 $22.750
Second Quarter.............................. 45.000 31.375
Third Quarter............................... 55.625 42.000
Fourth Quarter.............................. 50.938 33.750
2000
First Quarter............................... $50.375 $32.250
Second Quarter.............................. 61.813 44.875
Third Quarter............................... 60.938 47.063
Fourth Quarter.............................. 67.380 50.190
2001
First Quarter (through March 15, 2001)...... $63.750 $50.390
On March 15, 2001, the last reported sales price on the New York Stock
Exchange Composite Tape was $51.50 per share. As of that date, there were
approximately 178 holders of record of our common stock.
DIVIDEND RESTRICTIONS
In the past, we have not paid cash dividends on our common stock, and we do
not intend to pay cash dividends on our common stock in the foreseeable future.
We currently intend to retain earnings, if any, for the future operation and
development of our business. The restrictions on our present or future ability
to pay dividends are included in the provisions of the Delaware General
Corporation Law and in certain restrictive provisions in the indenture executed
in connection with our 8-3/4% Senior Subordinated Notes due 2007. In addition,
we have entered into a credit facility that contains provisions that may have
the effect of limiting or prohibiting the payment of dividends.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial
information for each of the years in the five year period ended December 31,
2000. This information is derived from our Financial Statements and the notes
thereto. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 8. Financial Statements and
Supplementary Data."
For combined financial information regarding the merger with Basin
Exploration, see "Note 15 - Supplemental Combined Financial Statements -
Unaudited" to the Financial Statements.
YEAR ENDED DECEMBER 31,
-------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(In thousands, except per share amounts)
STATEMENT OF OPERATIONS DATA:
Operating revenues:
Oil production revenue............................. $86,083 $56,969 $38,527 $31,082 $27,788
Gas production revenue............................. 170,325 89,950 76,070 37,997 28,051
Other revenue...................................... 3,971 2,215 2,023 1,908 2,126
--------- --------- --------- --------- ---------
Total revenues................................... 260,379 149,134 116,620 70,987 57,965
--------- --------- --------- --------- ---------
Expenses:
Normal lease operating expenses.................... 26,964 22,625 18,042 10,123 8,625
Major maintenance expenses......................... 6,538 1,115 1,278 1,844 427
Production taxes................................... 5,731 2,019 2,083 2,215 3,399
Depreciation, depletion and amortization........... 74,200 65,803 68,187 28,739 19,564
Write-down of oil and gas properties............... - - 89,135 - -
Interest expense................................... 8,534 12,907 12,987 5,004 3,618
General and administrative costs................... 6,005 4,604 4,256 3,815 3,465
Incentive compensation plan........................ 1,722 1,510 763 833 928
--------- --------- --------- --------- ---------
Total expenses................................... 129,694 110,583 196,731 52,573 40,026
--------- --------- --------- --------- ---------
Net income (loss) before income taxes................ 130,685 38,551 (80,111) 18,414 17,939
--------- --------- --------- --------- ---------
Income tax provision (benefit):
Current............................................ 450 25 - - 208
Deferred........................................... 45,290 12,036 (28,480) 6,495 6,698
--------- --------- --------- --------- ---------
Total income taxes............................... 45,740 12,061 (28,480) 6,495 6,906
--------- --------- --------- --------- ---------
Net income (loss).................................... $84,945 $26,490 ($51,631) $11,919 $11,033
========= ========= ========= ========= =========
Earnings and dividends per common share:
Basic net income (loss) per common share .......... $4.60 $1.61 ($3.43) $0.79 $0.90
========= ========= ========= ========= =========
Diluted net income (loss) per common share ........ $4.51 $1.58 ($3.43) $0.78 $0.90
========= ========= ========= ========= =========
Cash dividends declared............................ - - - - -
CASH FLOW DATA:
Net cash provided by operating
activities (before working capital changes)........ $198,886 $101,348 $77,211 $47,153 $37,295
Net cash provided by operating
activities......................................... 213,680 78,850 85,633 32,679 32,751
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital ..................................... $53,421 $22,887 $9,884 $8,328 $6,683
Oil and gas properties, net.......................... 444,631 353,141 293,824 291,420 171,396
Total assets ........................................ 602,431 441,738 366,390 354,144 209,406
Long-term debt, less current portion................. 100,000 100,000 209,936 132,024 26,172
Stockholders' equity ................................ 356,743 265,587 105,332 156,637 144,441
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion is intended to assist in understanding our
financial position and results of operations for each year of the three-year
period ended December 31, 2000. Our Financial Statements and the notes thereto,
which are found elsewhere in this Form 10-K, contain detailed information that
should be referred to in conjunction with the following discussion. See "Item 8.
Financial Statements and Supplementary Data."
OVERVIEW
We are an independent oil and gas company engaged in the acquisition,
exploration, development and operation of oil and gas properties onshore and in
shallow waters offshore Louisiana. We have been active in the Gulf Coast Basin
since 1973, which gives us extensive geophysical, technical and operational
expertise in this area.
Historically, we have sought growth primarily through the acquisition and
development of mature fields with a prolific production history. As commodity
prices increase and provide financial stability through additional cash flow it
becomes more feasible to pursue an aggressive exploratory drilling strategy.
During 2000, we designed a drilling program that provided an acceptable mix of
high and low risk projects in an effort to capitalize on an opportunity to test
certain prospects that have higher reward potential but are too high risk to
drill in periods of low prices. As a result, we drilled a record number of
wells, the majority of which were classified as exploratory wells.
As commodity prices increased, the demand for and the costs of drilling rigs
and related services did as well. In an attempt to hedge against rising drilling
costs, we entered into long-term fixed dayrate contracts for drilling rigs that
are capable of drilling on all our properties and we occasionally entered into
turnkey contracts that require a fixed payment upon the completion of a project
regardless of the number of drilling days.
The current commodity price environment also impacted the property market.
It is generally more expensive to buy properties at times when oil and gas
prices have increased, which is what we witnessed during the year 2000.
Therefore, we pursued stock-for-stock merger targets and non-cash acquisition
opportunities such as farmins, whereby we earned a working interest in desirable
acreage by drilling a well versus buying the field.
From time to time we enter into hedging contracts to reduce our exposure to
the possibility of declining commodity prices. Traditionally, these contracts
have been in the form of fixed price swaps and collars. In response to rising
commodity prices, we sought a hedging instrument that guaranteed a floor on the
prices we would receive for certain production volumes while allowing us to
fully participate in commodity price increases. As such, we purchased put
contracts for a portion of our future production that guarantee what we believe
to be minimum attractive prices for our hedged volumes.
During 2000, we remained focused on our objectives of increasing production,
cash flow and reserves. We set a company record for annual production by
producing 66.5 billion cubic feet of gas equivalent (Bcfe). We also set a record
for annual cash flow before working capital changes with 2000 results of $198.9
million representing a 96% increase over 1999 results. Finally, at December 31,
2000, we reported 400.2 Bcfe of estimated proved reserves, which is the largest
proved reserve base in our history. Our 2000 reserve replacement ratio was 119%,
which marks the seventh consecutive year that we replaced more than our annual
production.
As a result of the Basin merger's impact on our production, cash flow and
our property base and prospect inventory, we currently expect to implement a
significantly expanded capital expenditures program during 2001. With an
estimated budget of approximately $253 million, we have designed a capital
expenditures program that attempts to maximize the potential of our expanded
prospect inventory and can be financed by future cash flow. In addition to
drilling, we expect to seek growth opportunities through acquisitions that
become more feasible in periods of declining prices. We will continue to modify
our operating strategy to meet the demands of our ever-changing industry.
RESULTS OF OPERATIONS
The following table sets forth certain operating information with respect to
our oil and gas operations and summary information with respect to our estimated
proved oil and gas reserves. See "Item 2. Properties - Oil and Gas Reserves."
For combined operating information regarding the merger with Basin
Exploration, see "Selected Comparative Financial and Operational Data" in "Item
1. Business."
Year Ended December 31,
----------------------------------------------
2000 1999 1998
------------ ------------ ------------
PRODUCTION:
Oil (MBbls).................................................. 3,334 3,469 2,876
Gas (MMcf)
Produced excluding volumetric production payment.......... 43,813 36,780 33,281
Volumetric production payment............................. 2,667 1,333 -
------------ ------------ ------------
Total gas volumes produced................................ 46,480 38,113 33,281
Oil and gas (MMcfe)
Produced excluding volumetric production payment.......... 63,817 57,594 50,537
Volumetric production payment............................. 2,667 1,333 -
------------ ------------ ------------
Total volumes produced.................................... 66,484 58,927 50,537
AVERAGE SALES PRICES:
Oil (per Bbl)................................................ $25.82 $16.42 $13.40
Gas (per Mcf)
Price excluding volumetric production payment............. $3.75 $2.36 $2.29
Volumetric production payment............................. 2.24 2.24 -
Net average price......................................... 3.66 2.36 2.29
Oil and gas (per Mcfe)
Price excluding volumetric production payment............. $3.92 $2.50 $2.27
Volumetric production payment............................. 2.24 2.24 -
Net average price......................................... 3.86 2.49 2.27
AVERAGE COSTS (PER MCFE):
Normal operating costs....................................... $0.41 $0.38 $0.36
General and administrative costs............................. 0.09 0.08 0.08
Depreciation, depletion and amortization..................... 1.10 1.10 1.33
RESERVES AT DECEMBER 31:
Oil (MBbls).................................................. 21,319 22,636 18,476
Gas (MMcf)................................................... 272,238 251,614 243,270
Oil and gas (MMcfe).......................................... 400,152 387,430 354,126
Present value of estimated future net cash flows before
income taxes (in thousands)............................... $2,029,374 $561,303 $286,098
2000 COMPARED TO 1999. For the year 2000 we reported record net income
totaling $84.9 million, or $4.51 per share, compared to net income for the year
ended December 31, 1999 of $26.5 million, or $1.58 per share. The favorable
results in net income were due to improvements in the following components:
PRODUCTION. During 2000, production volumes reached a record high totaling
66.5 Bcfe compared to 58.9 Bcfe produced during 1999. Natural gas production
during 2000 increased 22% to approximately 46.5 billion cubic feet compared to
1999 gas production of 38.1 billion cubic feet, while oil production during 2000
totaled approximately 3.3 million barrels compared to 3.5 million barrels
produced during 1999.
The increase in 2000 production rates, compared to 1999, was due to
increases at several of our fields, the most significant of which were Eugene
Island Block 243 and East Cameron Block 64.
PRICES. Prices realized during 2000 averaged $25.82 per barrel of oil and
$3.66 per Mcf of gas. This represents a 55% increase, on an Mcfe basis, over
1999 average realized prices of $16.42 per barrel of oil and $2.36 per Mcf of
gas. All unit pricing amounts include the effects of hedging.
From time to time, we enter into various hedging contracts in order to
reduce our exposure to the possibility of declining oil and gas prices. Due to
increases in commodity prices, hedging transactions reduced the average price we
received during the year for oil by $4.60 per barrel and for gas by $0.48 per
Mcf, compared to a net decrease of $1.42 per barrel and a net increase of $0.02
per Mcf realized during 1999.
OIL AND GAS REVENUE. As a result of higher production rates and realized
prices, oil and gas revenue reached a record high during 2000, increasing 75% to
$256.4 million, compared to 1999 oil and gas revenue of $146.9 million.
EXPENSES. Normal operating costs during 2000 increased to $27 million,
compared to $22.6 million during 1999. On a unit of production basis, 2000
operating costs were $0.41 per Mcfe as compared to $0.38 per Mcfe for 1999. The
increase in operating costs was due primarily to industry-wide increases in the
costs of oil field products and services.
During 2000, we performed significant workover operations on nine wells at
three fields. As a result, major maintenance expenses for the year totaled $6.5
million compared to $1.1 million for 1999.
Due to increased 2000 onshore production volumes combined with higher oil
and gas prices, production revenue from onshore properties increased 108%. As a
result, production tax expense increased to $5.7 million from $2 million in
1999. Included in the 1999 amount was a $1 million production tax refund related
to the abatement of severance taxes for certain wells under Louisiana state law.
Depreciation, depletion and amortization (DD&A) expense on our oil and gas
properties totaled $73.2 million compared to $64.6 million for 1999. However, on
a unit of production basis, this expense was unchanged from the 1999 rate of
$1.10 per Mcfe.
General and administrative expenses for 2000 increased in total to $6
million, or $0.09 per Mcfe, from $4.6 million, or $0.08 per Mcfe, during 1999.
Due to our operational and financial results and our stock price performance
during the year, incentive compensation expense for 2000 increased to $1.7
million compared to $1.5 million in 1999. Both general and administrative and
incentive compensation expenses for 2000 were affected by a 10% increase in our
staff level over 1999.
As a result of the repayment of the borrowings under our bank credit
facility in August 1999, interest expense for 2000 decreased to $8.5 million,
compared to $12.9 million during 1999.
RESERVES. At December 31, 2000, our estimated proved oil and gas reserves
totaled 400.2 Bcfe, compared to December 31, 1999 reserves of 387.4 Bcfe.
Estimated proved gas reserves grew to 272.2 Bcf at the end of 2000 from 251.6
Bcf at year-end 1999, while estimated proved oil reserves declined to 21.3
MMBbls at the end of 2000 from 22.6 MMBbls at the beginning of the year.
The increases in our 2000 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions during the year. The reserve
estimates were prepared by independent petroleum consultants in accordance with
guidelines established by the SEC. Adherence to these guidelines limited us in
booking reserves on certain successfully drilled wells to the extent of the base
of known productive sands. Actual limits of the productive sands will ultimately
be determined through production or additional drilling.
Our present values of estimated future net cash flows before income taxes
were $2 billion and $561.3 million at December 31, 2000 and 1999, respectively.
You should not assume that the present values of estimated future net cash flows
represent the fair value of our estimated oil and gas reserves. As required by
the SEC, we determine the present value of estimated future net cash flows using
market prices for oil and gas on the last day of the fiscal period. The average
year-end oil and gas prices on all of our properties used in determining these
amounts were $28.01 per barrel and $10.13 per Mcf for 2000 and $25.07 per barrel
and $2.47 per Mcf for 1999. During the first quarter of 2001, market prices for
oil and gas have generally decreased, which would result in a reduction of
estimated future net cash flows and the present value of estimated future net
cash flows at December 31, 2000 if recomputed.
1999 COMPARED TO 1998. We recognized net income for the year ended December
31, 1999 totaling $26.5 million, or $1.58 per share, compared to the 1998 net
loss of $51.6 million, or $3.43 per share. The 1998 results included an
after-tax non-cash ceiling test write-down of $57.4 million, or $3.82 per share.
Excluding the write-down, favorable results in 1999 net income versus 1998 were
due to improvements in the following components:
PRODUCTION. Production volumes of oil and gas reached a then record high
during 1999 and, as compared to 1998, rose 21% and 15%, respectively, totaling
3.5 million barrels of oil and 38.1 billion cubic feet of gas. On a thousand
cubic feet of gas equivalent (Mcfe) basis, production rates for 1999 were 17%
higher than 1998 production rates.
The increase in 1999 production rates, compared to 1998, was due primarily
to increases at four of our fields. First, we successfully executed an
aggressive exploration and development program at Vermilion Block 255 by
completing and placing on production three exploratory and two development
wells. At the end of 1998, we began producing two high-pressured gas wells at
the South Pelto Block 23 E Platform, which significantly contributed to 1999's
favorable production rates. From June 1998 through August 1999, we successfully
drilled one exploratory well, three development wells and completed three
workovers to enhance production at Clovelly Field. Finally, in May 1999, we
increased our interest, and therefore our share of production, at Weeks Island
Field through the acquisition of an additional 32% working interest in 11
producing wells.
PRICES. Average realized prices during 1999 were $16.42 per barrel of oil
and $2.36 per Mcf of gas and represented a 10% increase, on an Mcfe basis, over
average prices of $13.40 per barrel of oil and $2.29 per Mcf of gas recognized
during 1998, including the effects of hedging. From time to time, we enter into
various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. During 1999, hedging transactions reduced the
average price we received for oil by $1.42 per barrel and increased the average
gas price received by $0.02 per Mcf compared to net increases of $0.28 per
barrel of oil and $0.10 per Mcf of gas during 1998.
OIL AND GAS REVENUE. Oil and gas revenue reached a then record high during
1999. The favorable increases in oil and gas production rates combined with
higher commodity prices resulted in oil and gas revenue increasing 28% to $146.9
million, compared to oil and gas revenue of $114.6 million during 1998.
EXPENSES. Normal operating costs during 1999 increased to $22.6 million,
compared to $18 million during 1998. On a unit of production basis, 1999
operating costs were $0.38 per Mcfe compared to $0.36 per Mcfe for 1998. The
increase in operating costs was due primarily to a 34% increase in the number of
producing wells that we operated as a result of the acquisitions of Lafitte
Field, West Cameron Block 176 and East Cameron Block 46, the increases in
working interest at East Cameron Block 64, Eugene Island Block 243 and Weeks
Island Field and discoveries at many of our fields including Vermilion Block
255, Vermilion Block 131, Clovelly Field and Eugene Island Block 243.
As a result of increased 1999 production volumes due to acquisitions and
discoveries combined with higher oil and gas prices during the year, production
revenue from onshore properties increased 43% during 1999. Our production tax
expense, however, declined during 1999 to $2 million from $2.1 million in 1998.
This decrease resulted from the abatement of severance taxes for certain wells
under Louisiana state law. Accordingly, we accrued in December 1999, and
received in early 2000, a production tax refund of $1 million.
General and administrative expenses for 1999 increased in total to $4.6
million from $4.3 million during 1998. However, on a unit basis, these costs
were unchanged from the 1998 amount of $0.08 per Mcfe. Due to our operational
results and stock performance during the year, incentive compensation expense
for 1999 increased to $1.5 million compared to $0.8 million in 1998.
DD&A expense on our oil and gas properties decreased to $64.6 million, or
$1.10 per Mcfe, compared to $67.3 million, or $1.33 per Mcfe, for 1998. The
decrease in DD&A expense resulted from a combination of the $89.1 million
non-cash ceiling test write-down of oil and gas properties recorded at the end
of 1998 and the improvement in oil and gas prices throughout 1999.
Our provision for income taxes was $12.1 million for the year ended December
31, 1999 and was net of a $1.5 million reduction in deferred taxes relative to
estimates of tax basis that were resolved during 1999.
RESERVES. At December 31, 1999, our estimated proved oil and gas reserves
totaled 387.4 Bcfe, excluding approximately 6.7 Bcf of gas dedicated to a
production payment associated with certain 1999 acquisitions, compared to
December 31, 1998 reserves of 354.1 Bcfe. Estimated proved oil reserves
increased to 22.6 MMBbls at the end of 1999 from 18.5 MMBbls at the beginning of
the year, and estimated proved gas reserves grew to 251.6 Bcf at December 31,
1999, excluding the 6.7 Bcf of gas dedicated to a production payment, compared
to 243.3 Bcf at year-end 1998.
The increases in our 1999 estimated proved reserve volumes were primarily
attributable to drilling results and acquisitions made during the year. The
reserve estimates were prepared by independent petroleum consultants in
accordance with guidelines established by the SEC. Adherence to these guidelines
limited us in booking reserves on certain successfully drilled wells to the
extent of the base of known productive sands. Actual limits of the productive
sands will ultimately be determined through production or additional drilling.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOW AND WORKING CAPITAL. Net cash flow from operations before working
capital changes for 2000 was $198.9 million, or $10.57 per share, compared to
$101.3 million, or $6.04 per share, reported for 1999. Working capital at
December 31, 2000 t