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Stone Energy 10-K 2006 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K/A
(Mark One)
For the fiscal year ended December 31, 2005
or
For the transition period from to
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact Name of Registrant as Specified in Its Charter)
Registrant’s Telephone Number, Including Area Code: (337) 237-0410
Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule
405 of the Securities Act.
o Yes þ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act.
o Yes þ No
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.
þ Yes o 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.o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated
filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ Accelerated filer o Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act).
o Yes þ No
The aggregate market value of the voting stock held by non-affiliates of the registrant was
approximately $1,043,487,711 as of June 30, 2005 (based on the last reported sale price of such
stock on the New York Stock Exchange Composite Tape on that day).
As of March 1, 2006, the registrant had outstanding 27,161,626 shares of Common Stock, par
value $.01 per share.
Document incorporated by reference: Portions of the Definitive Proxy Statement of Stone Energy
Corporation relating to the Annual Meeting of Stockholders to be held on May 18, 2006 are
incorporated by reference into Part III of this Form 10-K.
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EXPLANATORY NOTES – FORM 10-K/A
We are filing this amendment in response to comments received from the Securities and Exchange
Commission in their letters dated April 26, 2006 and July 31, 2006 regarding our Annual Report on
Form 10-K for the fiscal year ended December 31, 2005 that was originally filed on March 13, 2006.
This report revises the following disclosures:
Part I
Part II
Part IV
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This report continues to speak as of the date of the original filing, and we have not updated
the disclosure in this report to speak as of a later date. All information contained in this
report and the original filing is subject to updating and supplementing as provided in our periodic
reports filed with the SEC.
EXPLANATORY NOTES — FORM 10-K
Reserves Restatement – On October 6, 2005, as a result of reservoir level reviews conducted during
August 2005 through early October 2005, we announced a downward revision of 171 billion cubic feet
of natural gas equivalent (“Bcfe”) of proved reserves. After additional analysis and consultation
with outside engineering firms, the revision was increased to 237 Bcfe. Subsequently, after an
internal review of the causes of this revision, we decided to restate the unaudited oil and gas
reserve disclosures previously included in the footnotes accompanying our financial statements
contained in the original Form 10-K filed for the years ended December 31, 2004, 2003, 2002 and
2001 to give effect to the removal of 157 Bcfe of those volumes to the periods in which they did
not represent proved reserves within the applicable rules of the Securities and Exchange Commission
(“SEC”).
Please refer to pages F-8 to F-31 for additional information regarding the reserves restatement.
Financial Restatement – In view of the overstatement of proved reserves, it was determined to
restate the financial statements of the Company for the years ended December 31, 2004, 2003, 2002
and 2001 and the quarters ended March 31, 2005 and June 30, 2005. This overstatement of proved
reserves had the effect of understating the write-down of oil and gas properties for 2001 and
depreciation, depletion and amortization expense (“DD&A”) for all the periods to be restated which
in turn caused the overstatement of various reported amounts.
Additionally, in the process of the preparation of the Company’s Form 10-Q for September 30, 2005,
it was determined that approximately $9.8 million of unevaluated oil and gas property costs were
inappropriately classified and should have been reclassified to proved oil and gas property costs
in 2002. The Financial Restatement includes the effect of this revision for the years ended
December 31, 2004, 2003 and 2002. The total cumulative impact of the restatements on stockholders’
equity as of June 30, 2005 was a reduction of approximately $89.8 million, which includes a
reduction in beginning stockholders’ equity as of January 1, 2002 of approximately $45.3 million.
Please refer to pages F-8 to F-31 for additional information regarding the financial restatement.
The information herein reflects the restatements described above unless the context provides
otherwise.
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PART I
This section highlights information that is discussed in more detail in the remainder of the
document. Throughout this document we make statements that are classified as “forward-looking.”
Please refer to the “Forward-Looking Statements” section beginning on page 8 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. Certain terms relating to the oil and
gas industry are defined in “Glossary of Certain Industry Terms”, which begins on page G-1 of this
Form 10-K/A.
ITEM 1. BUSINESS
The Company
Stone Energy is an independent oil and gas company engaged in the acquisition and subsequent
exploration, development, operation and production of oil and gas properties located in the
conventional shelf of the Gulf of Mexico (the “GOM”), the deep shelf of the GOM, the deepwater of
the GOM, Rocky Mountain Basins and the Williston Basin. Our corporate headquarters are located at
625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508.
Available Information
We make available free of charge on our Internet web site (www.stoneenergy.com) our Annual
Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings
pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such
filings, as soon as reasonably practicable after each are electronically filed with, or furnished
to, the Securities and Exchange Commission (the “SEC”). In addition, the public may read and copy
any materials filed by us with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW,
Washington, D.C. 20549. You may obtain information on the operation of the public reference room
by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (http://www.sec.gov) that
contains reports, proxy and information statements, and other information regarding issuers that
file electronically with the SEC. We also make available on our Internet web site our Code of
Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation and
Nominating and Governance Committee Charters, respectively, which have been approved by our board
of directors. We will make immediate disclosure by a Current Report on Form 8-K and on our web
site of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal
executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also
available, free of charge by writing us at: Chief Financial Officer, Stone Energy Corporation,
P.O. Box 52807, Lafayette, LA 70505. The annual CEO certification required by Section 303A.12 of
the New York Stock Exchange Listed Company Manual was submitted on June 6, 2005.
Strategy and Operational Overview
Since our public offering in 1993, we have been engaged in the acquisition, exploration and
development of mature oil and gas properties in the Gulf Coast Basin, which includes onshore
Louisiana and offshore GOM. During 2004, we broadened our conventional shelf acquisition and
exploitation strategy in order to diversify, extend reserve life and take advantage of a strong oil
and gas market. This broadened growth strategy includes targeting reserves and production in the
deep shelf and deep water of the GOM, furthering our position in the Rocky Mountain Region (Rocky
Mountain Basins and Williston Basin) to complement our existing portfolio of properties in the Gulf
Coast Basin (onshore, shelf and deep shelf) and investigating viable opportunities in other areas
including international areas. Our strategy is driven by increased availability of lease blocks in
the deep water of the GOM, 3D seismic technology improvements in the deep shelf of the GOM,
fracturing technology improvements and horizontal drilling applications in the Rocky Mountain
Region and other areas. As of March 1, 2006, our property portfolio consisted of 58 active
properties and 60 primary term leases in the Gulf Coast Basin and 21 active properties in the Rocky
Mountain Region.
As of December 31, 2005, we had estimated proved reserves of approximately 593 billion cubic
feet of natural gas equivalent (“Bcfe”), 73% of which were classified as proved developed and 58%
of which were natural gas. For the year ended December 31, 2005, we produced an average of 228
million cubic feet of natural gas equivalent (“MMcfe”) per day, which was curtailed due to extended
production downtime associated with Hurricanes Katrina and Rita. During 2005, we generated net
cash flow from operating activities of $461.2 million.
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Gulf of Mexico — Conventional Shelf (Including Onshore Louisiana)
Our conventional shelf strategy is the same acquisition and exploitation combination that we
adopted prior to our initial public offering in 1993. We apply the latest geophysical
interpretation tools to identify underdeveloped properties and the latest production techniques to
increase production attributable to these properties. We seek to acquire properties that have the
following characteristics:
Prior to acquiring a property, we perform a thorough geological, geophysical and engineering
analysis of the property to formulate a comprehensive development plan. We also employ our
extensive technical database, which includes both 3-Dimensional and 4-Component seismic data.
After we acquire a property, we seek to increase cash flow from existing reserves and 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.
Gulf of Mexico — Deep Water
We believe that the deep water of the GOM is an important exploration area, even though it
involves high risk, high costs and substantial lead time to develop infrastructure. We have
assembled a technical team with prior geological, geophysical and engineering experience in the
deep water arena to evaluate potential opportunities. During 2005, we drilled three deep water
wells, none of which were successful. As of yet, we have no production or reserves in the deep
water of the GOM.
Gulf of Mexico — Deep Shelf
Our current property base also contains multiple deep shelf exploration opportunities in the
GOM, which are defined as prospects below 15,000 feet. The deep shelf presents higher risk with
high potential opportunities that have existing infrastructure, which shortens the lead time to
production. We believe our existing property base creates the opportunity for a portfolio approach
to the deep shelf.
Rocky Mountain Basins
Our assets in the Rocky Mountain Basins represented 9% of our total production in 2005 and 16%
of our total estimated proved reserves (on a volumetric basis) at December 31, 2005. Our Rocky
Mountain Basins include positions in the Wind River and Greater Green River Basins in Wyoming and
Uinta Basin in Utah.
Williston Basin
On March 1, 2005, we completed the acquisition of approximately 35,000 net acres in the
Williston Basin of North Dakota and Montana. The acquisition cost, net of purchase price
adjustments, totaled approximately $85.7 million, of which $76.0 million was financed with
borrowings under our bank credit facility. During the remainder of 2005 we drilled 20 wells, all
of which were productive. We also acquired an additional 314,000 net acres for additional
exploration and development in the Williston Basin. Our Williston Basin assets represented 2% of
our total production in 2005 and 8% of our total estimated proved reserves (on a volumetric basis)
at December 31, 2005.
Oil and Gas Marketing
Our oil and natural gas production is sold at current market prices under short-term
contracts. Conoco, Inc., Sequent Energy Management LP and Total Gas & Power North America, Inc.
each accounted for between 10%-12% of oil and natural gas revenue generated during the year ended
December 31, 2005. No other purchaser accounted for 10% or more of our total oil and natural gas
revenue during 2005. 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 and natural gas. See “Item 7A.
Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk.”
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Competition and Markets
Competition in the Gulf Coast Basin and the Rocky Mountain Region is intense, particularly
with respect to the acquisition of producing properties and undeveloped acreage. We compete with
major oil and gas 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 “Item 1A.
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 amount of domestic production
and imports of foreign oil and liquefied natural gas, the marketing of competitive fuels, the
proximity and capacity of oil and natural gas pipelines, the availability of transportation and
other market facilities, the demand for hydrocarbons, the effect of federal and state regulation of
allowable rates of production, taxation and the conduct of drilling operations, and federal
regulation of oil and natural gas. In addition, the restructuring of the natural gas pipeline
industry eliminated the gas purchasing activity of traditional interstate gas transmission pipeline
buyers. 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 arena, generally may affect the supply of
and/or demand for oil and natural gas and thus the prices available for sales of oil and natural
gas.
Regulation
Our oil and gas operations are subject to various U.S. federal, state and local laws and
regulations.
Various aspects of our oil and natural gas operations are regulated by administrative agencies
of the states where such operations are conducted and by certain agencies of the federal government
for operations on federal leases. All of the jurisdictions in which we own or operate producing oil
and natural gas properties have statutory provisions regulating the exploration for and production
of oil and natural gas, including provisions requiring permits for the drilling of wells and
maintaining bonding requirements in order to drill or operate wells, and provisions relating to the
location of wells, the method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled, and the abandonment of wells. Our operations are also
subject to various conservation laws and regulations. These include the regulation of the size of
drilling and spacing units or proration units and the number of wells that may be drilled in an
area and the unitization or pooling of oil and natural gas properties. In this regard, some states
can order the pooling or integration of tracts to facilitate exploration while other states rely on
voluntary pooling of lands and leases. In addition, state conservation laws establish maximum rates
of production from oil and natural gas wells, generally prohibit the venting or flaring of natural
gas, and impose certain requirements regarding the ratability or fair apportionment of production
from fields and individual wells.
Certain operations that we conduct are on federal oil and gas leases, which are administered
by the Bureau of Land Management (the “BLM”) and the Minerals Management Service (the “MMS”). These
leases contain relatively standardized terms and require compliance with detailed BLM and MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act (the “OCSLA”) (which are
subject to change by the MMS). Many onshore leases contain stipulations limiting activities that
may be conducted on the lease. Some stipulations are unique to particular geographic areas and may
limit the times during which activities on the lease may be conducted, the manner in which certain
activities may be conducted or, in some cases, may ban any surface activity. For offshore
operations, lessees must obtain MMS approval for exploration, development and production plans
prior to the commencement of such operations. In addition to permits required from other agencies
(such as the U.S. Environmental Protection Agency), lessees must obtain a permit from the BLM or
the MMS, as applicable, prior to the commencement of drilling, and comply with regulations
governing, among other things, engineering and construction specifications for production
facilities, safety procedures, plugging and abandonment of wells on the Outer Continental Shelf
(the “OCS”) of the GOM, calculation of royalty payments and the valuation of production for this
purpose, and removal of facilities. To cover the various obligations of lessees on the OCS, the MMS
generally requires that lessees post substantial bonds or other acceptable assurances that such
obligations will be met, unless the MMS exempts the lessee from such obligations. The cost of such
bonds or other surety can be substantial, and we can provide no assurance that we can continue to
obtain bonds or other surety in all cases. Under certain circumstances, the BLM or MMS, as
applicable, may require 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.
In August, 2005, Congress enacted the Energy Policy Act of 2005 (“EPAct 2005”). Among other
matters, EPAct 2005 amends the Natural Gas Act (“NGA”) to make it unlawful for “any entity”,
including otherwise non-jurisdictional producers such as Stone Energy, to use any deceptive or
manipulative device or contrivance in connection with the purchase or sale of natural gas or the
purchase or sale of transportation services subject to regulation by the Federal Energy Regulatory
Commission (“FERC”), in contravention of rules prescribed by the FERC. On January 20, 2006, the
FERC issued rules implementing this provision. The rules make it unlawful in connection with the
purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of
transportation services subject to the jurisdiction of the FERC, for any entity, directly or
indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue
statement of material fact or omit to make any such statement necessary to make the statements made
not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any
person. EPAct 2005 also gives the FERC
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authority to impose civil penalties for violations of the
NGA up to $1,000,000 per day per violation. The new anti-manipulation rule does not apply to
activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does
apply to activities of otherwise non-jurisdictional entities to the extent the activities are
conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction.
It therefore reflects a
significant expansion of the FERC’s enforcement authority. Stone Energy does not
anticipate it will be affected any differently than other producers of natural gas.
Additional proposals and proceedings that might affect the oil and gas industry are regularly
considered by Congress, states, the FERC and the courts. We cannot predict when or whether any such
proposals may become effective. In the past, the oil and natural gas industry has been heavily
regulated. We can give no assurance that the regulatory approach currently pursued by the FERC or
any other agency will continue indefinitely. We do not anticipate, however, that compliance with
existing federal, state and local laws, rules and regulations will have a material or significantly
adverse effect on our financial condition, results of operations or competitive position. No
portion of our business is subject to renegotiation of profits or termination of contracts or
subcontracts at the election of the federal government.
Environmental Regulation
As a lessee and operator of onshore and offshore oil and gas properties in the United States,
we are subject to stringent federal, state and local laws and regulations relating to environmental
protection as well as controlling the manner in which various substances, including wastes
generated in connection with oil and gas industry operations, are released into the environment.
Compliance with these laws and regulations can affect the location or size of wells and facilities,
limit or prohibit the extent to which exploration and development may be allowed, and require
proper closure of wells and restoration of properties that are being abandoned. Failure to comply
with these laws and regulations may result in the assessment of administrative, civil or criminal
penalties, imposition of remedial obligations, incurrence of capital costs to comply with
governmental standards, and even injunctions that limit or prohibit exploration and production
operations or the disposal of substances generated in connection with oil and gas industry
operation.
We currently operate or lease, and have in the past operated or leased, a number of properties
that for many years have been used for 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
operated or leased by us or on or under other locations where such wastes have been taken for
disposal. In addition, many 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 laws and regulations imposing joint
and several, strict liability, without regard to fault or the legality of the original conduct,
that could require us to remove or remediate previously disposed wastes or environmental
contamination, or to perform remedial plugging or pit closure to prevent future contamination. We
believe that it is reasonably likely that the trend in environmental legislation and regulation
will continue toward stricter standards.
The Oil Pollution Act of 1990 (or “OPA”) and regulations adopted pursuant to OPA impose a
variety of requirements related to the prevention of and response to oil spills into waters of the
United States, including the OCS. The OPA subjects owners of oil handling facilities to strict,
joint and several liability for all containment and cleanup costs and certain other damages arising
from a spill, including, but not limited to, the costs of responding to a release of oil to surface
waters and natural resource damages. OPA also requires owners and operators of offshore oil
production facilities such as us to establish and maintain evidence of financial responsibility of
at least $35 million to cover costs that could be incurred in responding to an oil spill. We
believe that we are in substantial compliance with the requirements of OPA, and that these
requirements are not any more burdensome to us than they are to other similarly situated oil and
gas companies.
We have made, and will continue to make, expenditures in efforts to comply with environmental
laws and regulations. While we believe that we are in substantial compliance with applicable
environmental laws and regulations in effect and that continued compliance with existing
requirements will not have a material adverse impact on us, we cannot give any assurance that we
will not be adversely affected in the future.
We have established internal guidelines to be followed in order to comply with environmental
laws and regulations in the United States. We employ a safety department whose responsibilities
include providing assurance that our operations are carried out in accordance with applicable
environmental guidelines and safety precautions. Although we maintain pollution insurance to cover
a portion of the costs of cleanup operations, public liability and physical damage, there is no
assurance that such insurance will be adequate to cover all such costs or that such insurance will
continue to be available in the future. To date we believe that compliance with existing
requirements of such governmental bodies has not had a material effect on our operations.
Employees
On March 1, 2006, we had 271 full time employees. We believe that our relationships with our
employees are satisfactory. None of our employees are covered by a collective bargaining
agreement. Under our supervision, we utilize the services of independent contractors to perform
various daily operational duties.
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Forward-Looking Statements
The information in this Form 10-K/A includes “forward-looking statements” within the meaning
of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of
1934. All statements, other than statements of historical or current facts, that address
activities, events, outcomes and other matters that we plan, expect, intend, assume, believe,
budget, predict, forecast, project, estimate or anticipate (and other similar expressions) will,
should or may occur in the future are forward-looking statements. These forward-looking statements
are based on management’s current belief, based on currently available information, as to the
outcome and timing of future events. When considering forward-looking statements, you should keep
in mind the risk factors and other cautionary statements in this Form 10-K/A.
Forward-looking statements appear in a number of places and include statements with respect
to, among other things:
We caution you that these forward-looking statements are subject to all of the risks and
uncertainties, many of which are beyond our control, incident to the exploration for and
development, production and marketing of oil and natural gas. These risks include, but are not
limited to, commodity price volatility, third party interruption of sales to market, inflation,
lack of availability of goods and services, environmental risks, drilling and other operating
risks, hurricanes and other weather conditions, regulatory changes, the uncertainty inherent in
estimating proved oil and natural gas reserves and in projecting future rates of production and
timing of development expenditures and the other risks described in this Form 10-K/A.
Reserve engineering is a subjective process of estimating underground accumulations of oil and
natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends
on the quality of available data and the interpretation of that data by geological engineers. In
addition, the results of drilling, testing and production activities may justify revisions of
estimates that were made previously. If significant, these revisions would change the schedule of
any further production and development drilling. Accordingly, reserve estimates are generally
different from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described above or elsewhere in this Form
10-K/A occur, or should underlying assumptions prove incorrect, our actual results and plans could
differ materially from those expressed in any forward-looking statements. 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 us are expressly qualified in their entirety by
this cautionary statement.
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ITEM 1A. 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:
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.
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
be recovered quickly through production with associated steep declines, while declines in other
regions after initial flush production tend to be relatively low. During 2005, 89% of our
production and 76% of our estimated proved reserves were derived from Gulf of Mexico reservoirs,
while the remaining portions of our production and reserves were derived from the Rocky Mountain
Region. Our reserves will decline as they are produced unless we acquire properties with proved
reserves or conduct successful development and exploration drilling activities. Our future natural
gas and oil production is highly dependent upon our level of success in finding or acquiring
additional reserves.
We have identified a material weakness in our internal controls relating to the estimation of
proved reserves.
This Form 10-K/A contains estimates of our proved oil and gas reserves and the estimated
future net cash flows from such reserves. These estimates are based upon various assumptions,
including assumptions required by the SEC relating to oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and
natural 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
and is therefore inherently imprecise. Additionally, our interpretations of the rules governing
the estimation of proved reserves could differ from the interpretation of staff members of
regulatory authorities resulting in estimates that could be challenged by these authorities.
Actual future production, oil and natural 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 natural gas prices and other factors, many of which are beyond our control.
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As articulated in “Item 9A. Controls and Procedures” on page 31, management has identified a
material weakness in internal controls that did not prevent the overstatement of our proved oil and
gas reserves in prior periods. As of the date of this report, we have not completely mitigated the
causes of this weakness because we have not had an adequate passage of time to monitor the progress
of our continuing training programs.
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 acquisition,
exploration, exploitation, development and production of oil and gas reserves. Our capital
expenditures, including acquisitions and exclusive of estimated asset retirement costs, were $479.8
million during 2005, $501.2 million during 2004 and $361.9 million during 2003. We have budgeted
total capital expenditures in 2006, excluding property acquisitions, asset retirement costs and
capitalized salaries, general and administrative costs and interest, to be approximately $360
million. If low oil and natural gas prices, operating difficulties or other factors, many of which
are beyond our control, cause our revenues and cash flows from operating activities to decrease, we
may be limited in our ability to fund the capital necessary to complete our capital expenditures
program. In addition, if our borrowing base under our credit facility is re-determined to a lower
amount, this could adversely affect our ability to fund our planned capital expenditures. After
utilizing our available sources of financing, we may be forced to raise additional debt or equity
proceeds to fund such capital expenditures. We cannot assure you that additional debt or equity
financing will be available or cash flows provided by operations will be sufficient to meet these
requirements.
Our debt level and the covenants in the agreements governing our debt could negatively impact our
financial condition, results of operations and business prospects.
As of March 1, 2006, we had $563 million in outstanding indebtedness. We have a borrowing
base under our bank credit facility of $300 million with availability of an additional $114 million
of borrowings as of March 1, 2006. Our borrowing base was reduced from $425 million to $300
million after we announced our reserve revision in October 2005.
The terms of the agreements governing our debt impose significant restrictions on our ability
to take a number of actions that we may otherwise desire to take, including:
Our level of indebtedness, and the covenants contained in the agreements governing our debt,
could have important consequences on our operations, including:
We may be required to repay all or a portion of our debt on an accelerated basis in certain
circumstances. If we fail to comply with the covenants and other restrictions in the agreements
governing our debt, it could lead to an event of default and the acceleration of our repayment of
outstanding debt. Our ability to comply with these covenants and other restrictions may be affected
by events beyond our control, including prevailing economic and financial conditions. Our
borrowing base under the credit facility, which is re-determined periodically, is based on an
amount established by the bank group after its evaluation of our proved oil and gas reserve values.
Upon a re-determination, if borrowings in excess of the revised borrowing capacity were
outstanding, we could be forced to repay a portion of our bank debt.
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We may not have sufficient funds to make such repayments. If we are unable to repay our debt
out of cash on hand, we could attempt to refinance such debt, sell assets 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 from operating activities to pay the interest on our debt or that future
borrowings, equity financings or proceeds from the sale of assets will be available to pay or
refinance such debt. The terms of our debt, including our credit facility and our indentures, may
also prohibit us from taking such actions. Factors that will affect our ability to raise cash
through an offering of our
capital stock, a refinancing of our debt or a sale of assets 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, refinancing or sale of assets can be successfully
completed.
We have experienced significant shut-ins and losses of production in 2004 and 2005 due to the
effects of hurricanes in the Gulf of Mexico.
Approximately 76% of our estimated proved reserves at December 31, 2005 and 89% of our
production during 2005 were associated with our Gulf Coast Basin properties. Accordingly, if the
level of production from these properties substantially declines, it could have a material adverse
effect on our overall production level and our revenue. We are particularly vulnerable to
significant risk from hurricanes and tropical storms. During 2004, we experienced an approximate
7.0 Bcfe deferral of production due to Hurricane Ivan. During 2005, we experienced an approximate
16.4 Bcfe deferral of production resulting from Hurricanes Katrina and Rita. We are unable to
predict what impact future hurricanes and tropical storms might have on our future results of
operations and production.
The marketability of our production depends mostly upon the availability, proximity and capacity of
oil and natural gas gathering systems, pipelines and processing facilities.
The marketability of our production depends upon the availability, proximity, operation and
capacity of oil and natural 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, state
and local 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.
We may not receive payment for a portion of our future production.
We may not receive payment for a portion of our future production. We have attempted to
diversify our sales and obtain credit protections such as parental guarantees from certain of our
purchasers. We are unable to predict, however, what impact the financial difficulties of certain
purchasers may have on our future results of operations and liquidity.
Lower oil and gas prices may cause us to record ceiling test write-downs.
We use the full cost method of accounting for our oil and gas operations. Accordingly, we
capitalize the cost to acquire, explore for and develop oil and gas properties. Under the
full cost method of accounting, we compare, at the end of each financial reporting period, the
present value of estimated future net cash flows from proved reserves (based on period-end hedge
adjusted commodity prices and excluding cash flows related to estimated abandonment costs), net of
related tax effect, to the net capitalized costs of proved oil and gas properties, including
estimated capitalized abandonment costs, net of related deferred taxes. We refer to this
comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas properties
exceed the estimated discounted future net cash flows from proved reserves, we are required to
write-down the value of our oil and gas properties to the value of the discounted cash flows.
This charge does not impact cash flow from operating activities, but does reduce net income.
The risk that we will be required to write down the carrying value of oil and gas properties
increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur
if we experience substantial downward adjustments to our estimated proved reserves. 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 short and long-term liquidity needs through the use of bank
credit facilities, the issuance of debt and equity securities and the use of cash flow provided by
operating activities. We continue to examine the following alternative sources of capital:
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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 fully execute our operating strategy if we cannot obtain capital from these sources.
There are uncertainties in successfully integrating our acquisitions.
Integrating acquired businesses and properties involves a number of special risks. These
risks include the possibility that management may be distracted from regular business concerns by
the need to integrate operations and that unforeseen difficulties can arise in integrating
operations and systems and in retaining and assimilating employees. Any of these or other similar
risks could lead to potential adverse short-term or long-term effects on our operating results.
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:
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 revenue after operating and other costs to recoup drilling costs.
Our industry experiences numerous operating risks.
The exploration, development and production 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 have begun to explore for natural gas and oil in the deep waters of the GOM (water depths
greater than 2,000 feet) where operations are more difficult than in shallower waters. Our deep
water drilling and operations require the application of recently developed technologies that
involve a higher risk of mechanical failure. The deep waters of the GOM often lack the physical
infrastructure and availability of services present in the shallower waters. As a result, deep
water operations may require a significant amount of time between a discovery and the time that we
can market the oil and gas, increasing the risks involved with these operations.
We maintain 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. In addition, we maintain operator’s extra expense insurance, which
provides coverage for the care, custody and control of wells drilled and/or completed plus re-drill
and pollution coverage. The exact amount of coverage for each well is dependent upon its depth and
location. We experienced Gulf of Mexico production interruption in 2004 from Hurricane Ivan and in
2005 from Hurricanes Katrina and Rita for which we do not have any loss of production insurance.
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. No assurance can be given that we will be able to maintain insurance in the future at
rates we consider reasonable. The occurrence of a significant event, not fully insured or
indemnified against, could have a material adverse affect on our financial condition and
operations.
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Terrorist attacks aimed at our facilities could adversely affect our business.
The U.S. government has issued warnings that U.S. energy assets may be the future targets of
terrorist organizations. These developments have subjected our operations to increased risks. Any
future terrorist attack at our facilities, or those of our purchasers, could have a material
adverse affect on our financial condition and operations.
Competition within our industry may adversely affect our operations.
Competition in the Gulf Coast Basin and the Rocky Mountain Region is intense, particularly
with respect to the acquisition of producing properties and undeveloped acreage. We compete with
major oil and gas 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.
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 laws and
regulations. These laws and regulations may be changed in response to economic or political
conditions. Regulated matters include: permits for exploration, development and production
operations; limitations on our drilling activities in environmentally sensitive areas, such as
wetlands and restrictions on the way we can release materials into the environment; 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. Failure to comply with these laws and regulations can result in the
assessment of administrative, civil, or criminal penalties, the issuance of remedial obligations,
and the imposition of injunctions limiting or prohibiting certain of our operations. 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 such as us to prove that they have the financial capability to respond to costs
that may be incurred in connection with potential oil spills. Under OPA and other federal and state
environmental statutes like the federal Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) and Resource Conservation and Recovery Act (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. Consequently, a substantial spill from one of
our facilities subject to laws such as OPA, CERCLA and RCRA could require the expenditure of
additional, and potentially significant, amounts of capital, or could have a material adverse
effect on our earnings, 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 impact on our earnings, operations or competitive position.
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 individuals will remain with us for the immediate or
foreseeable future. The unexpected loss of the services of one or more of these individuals could
have an adverse effect on us.
Hedging transactions may limit our potential gains or become ineffective.
In order to manage our exposure to price risks in the marketing of our oil and natural gas, we
periodically 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 estimated production quantities may be hedged. These
arrangements may include futures contracts on the New York Mercantile Exchange (“NYMEX”). While
intended to reduce the effects of volatile oil and gas prices, such transactions, 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:
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Ownership of working interests, net profits interests and overriding royalty interests in certain
of our properties by certain affiliates may create conflicts of interest.
James H. Stone, our chairman of the board of directors, owns up to 7.5% of the working
interest in certain wells drilled on Section 19 of the east flank of the Weeks Island Field. This
interest was acquired prior to our initial public offering in 1993. In his capacity as a working
interest owner, he is required to pay a proportional share of all costs and is entitled to receive
a proportional share of revenue.
D. Peter Canty, a former director and our former President and Chief Executive Officer, and
James H. Prince, our former Executive Vice President and Chief Financial Officer, were granted net
profits interests in some of Stone’s oil and gas properties acquired prior to our initial public
offering in 1993. In addition, Michael E. Madden, our Vice President of Reserves, was granted an
overriding royalty interest in some of Stone’s properties by an independent third party. At the
time he was granted this interest, Mr. Madden was serving Stone as an independent engineering
consultant. The recipients of net profits and overriding royalty 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 former
directors and present and former 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 81/4% Senior Subordinated Notes due 2011
and 63/4% Senior Subordinated Notes due 2014. 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 stockholders 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, who are elected by plurality voting. 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. Our board of
directors recently considered a policy to elect directors by majority vote, but a decision was made
to continue with plurality voting at this time.
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. This shareholder rights
agreement expires on September 30, 2008.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
As of March 1, 2006, our property portfolio consisted of 58 active properties and 60 primary
term leases in the Gulf Coast Basin and 21 active properties in the Rocky Mountain Region. We
serve as operator on 59% of our active properties, including a 64% operating percentage on our Gulf
Coast Basin properties and 48% operating percentage on our Rocky Mountain Region properties. The
properties that we operate accounted for 72% of our year-end 2005 estimated proved reserves. This
high operating percentage allows us to better control the timing, selection and costs of our
drilling and production activities.
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Oil and Natural Gas Reserves
The information in this Annual Report on Form 10-K/A relating to our estimated oil and gas
reserves is based upon reserve reports prepared as of December 31, 2005. The majority of our Gulf
Coast Basin reserves have been audited by Netherland, Sewell & Associates, Inc. (An audit is an
examination of Reserve Information that is conducted for the purpose of expressing an opinion as to
whether such Reserve Information, in the aggregate, is reasonable and has been estimated and
presented in conformity with generally accepted petroleum engineering and evaluation principles.
The Netherland, Sewell & Associates, Inc. audit report has been included as Exhibit 99.1 in this
filing). The audited properties cover 72.6% of our total reserve base on a volumetric basis. Of
the audited properties, 71% (on a volumetric basis) were prepared by Netherland, Sewell &
Associates, Inc. with the remainder prepared by us. The remainder of our Gulf Coast Basin reserves
were prepared by Cawley, Gillespie & Associates, Inc. and represent 3.0% of our reserves on a
volumetric basis. Our Rocky Mountain Region reserves were prepared by Ryder Scott Company, L.P.
and represent 24.4% of our reserves on a volumetric basis. All product pricing and cost estimates
used in the reserve reports are in accordance with the rules and regulations of the SEC. The
standardized measure of discounted 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 period-end market prices for oil and gas without considering hedge contracts in place
at the end of the period. Using the information contained in the reserve reports, the average 2005
year-end product prices for all of our properties were $57.17 per barrel of oil and $9.86 per Mcf
of gas. The following table sets forth our estimated net proved oil and natural gas reserves and
the present value of estimated future net cash flows related to such reserves as of December 31,
2005.
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The following represents additional information on individually significant properties:
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. Results of drilling, testing and production
subsequent to the date of an estimate may justify a revision of such estimate. 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, operating costs, development costs and income taxes 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. See “Item 1A. Risk Factors – We have identified a material weakness in our internal
controls relating to the estimation of proved reserves".
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.
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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, 2005.
Drilling Activity. The following table sets forth our drilling activity for the periods
indicated.
Title to Properties
We believe that we have satisfactory title to substantially all of our active 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 active properties.
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ITEM 3. LEGAL PROCEEDINGS
We are among the defendants included in a lawsuit filed in 2004 by the State of Louisiana and
the Iberia Parish School Board in Case Number 101934, Iberia Parish, Louisiana, alleging
contamination and damage and seeking an undisclosed monetary sum as compensation for said damages
to portions of Section 16, Township 12 South, Range 11 East in the Bayou Pigeon Field as a result
of past oil and gas exploration and production activities. The Company believes it has been named
as a defendant in error and intends to vigorously defend this matter.
On December 30, 2004, Stone was served with two petitions (civil action numbers 2004-6227 and
2004-6228) filed by the Louisiana Department of Revenue (“LDR”) in the 15th Judicial District Court
(Parish of Lafayette, Louisiana) claiming additional franchise taxes due. In one case, the LDR is
seeking additional franchise taxes from Stone in the amount of $640,000, plus accrued interest of
$352,000 (calculated through December 15, 2004), for the franchise year 2001. In the other case,
the LDR is seeking additional franchise taxes from Stone (as successor to Basin Exploration, Inc.)
in the amount of $274,000, plus accrued interest of $159,000 (calculated through December 15,
2004), for the franchise years 1999, 2000 and 2001. Further, on December 29, 2005, the LDR filed
another petition in the 15th Judicial District Court claiming additional franchise taxes
due for the taxable years ended December 31, 2002 and 2003 in the amount of $2.6 million plus
accrued interest calculated through December 15, 2005 in the amount of $1.2 million. These
assessments all relate to the LDR’s assertion that sales of crude oil and natural gas from
properties located on the Outer Continental Shelf, which are transported through the state of
Louisiana, should be sourced to the state of Louisiana for purposes of computing the Louisiana
franchise tax apportionment ratio. The Company disagrees with these contentions and intends to
vigorously defend itself against these claims. Stone has not yet been given any indication that
the LDR plans to review franchise taxes for the franchise tax years 2004 and 2005.
Stone has received notice that the staff of the SEC is conducting an informal inquiry into the
revision of Stone’s proved reserves and the financial statement restatement. In addition, Stone
has received an inquiry from the Philadelphia Stock Exchange investigating matters including
trading prior to Stone’s October 6, 2005 announcement. Stone intends to cooperate fully with both
inquiries.
On or around November 30, 2005, George Porch filed a putative class action in the United
States District Court for the Western District of Louisiana against Stone, David H. Welch, Kenneth
H. Beer, D. Peter Canty and James H. Prince purporting to allege violations of Sections 10(b) and
20(a) of the Securities Exchange Act of 1934 (the “Exchange Act”). Three similar complaints were
filed soon thereafter. All complaints assert a putative class period commencing on June 17, 2005
and ending on October 6, 2005. All complaints contend that, during the putative class period,
defendants, among other things, misstated or failed to disclose (i) that Stone had materially
overstated Stone’s financial results by overvaluing its oil reserves through improper and
aggressive reserve methodologies; (ii) that the Company lacked adequate internal controls and was
therefore unable to ascertain its true financial condition; and (iii) that as a result of the
foregoing, the values of the Company’s proved reserves, assets and future net cash flows were
materially overstated at all relevant times. A motion to consolidate these actions and to appoint
a lead plaintiff will be heard on March 22, 2006. In addition, on or about December 16, 2005,
Robert Farer filed a complaint in the United States District Court for the Western District of
Louisiana alleging claims derivatively on behalf of Stone, and three similar complaints were filed
soon thereafter in federal and state court. Stone is named as a nominal defendant, and certain
current and former officers and directors are named as defendants in these actions, which allege
breaches of the fiduciary duties owed to Stone, gross mismanagement, abuse of control, waste of
corporate assets, unjust enrichment, and violations of the Sarbanes-Oxley Act of 2002. Stone
intends to vigorously defend these lawsuits.
Stone’s Certificate of Incorporation and/or its Restated Bylaws provide, to the extent
permissible under the law of Delaware (Stone’s state of incorporation), for indemnification of and
advancement of defense costs to Stone’s current and former directors and officers for potential
liabilities related to their service to Stone. Stone has purchased directors and officers
insurance policies that, under certain circumstances, may provide coverage to Stone and/or its
officers and directors for certain losses resulting from securities-related civil liabilities
and/or the satisfaction of indemnification and advancement obligations owed to directors and
officers. These insurance policies may not cover all costs and liabilities incurred by Stone and
its current and former officers and directors in these regulatory and civil proceedings.
We
are named as a defendant in certain other lawsuits and are a party to
certain other 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.
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ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted for a vote of our stockholders during the third or fourth quarters
of 2005.
ITEM 4A. EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth information regarding the names, ages (as of March 1, 2006) and
positions held by each of our executive officers, followed by biographies describing the business
experience of our executive officers for at least the past five years. Our executive officers
serve at the discretion of the board of directors.
David H. Welch was appointed President, Chief Executive Officer and a director of the Company
effective April 1, 2004. Prior to joining Stone, Mr. Welch served as Senior Vice President of BP
America, Inc. since 2003, and Vice President of BP, Inc. since 1999.
Craig L. Glassinger was named Executive Vice President of Business Development in April 2004.
Previously, Mr. Glassinger served as Senior Vice President – Planning, Acquisitions and Analysis
since April 2002. From February 2001 until April 2002, he served as Vice President – Resources and
from December 1995 to February 2001 he served as Vice President – Acquisitions.
Kenneth H. Beer was named Senior Vice President and Chief Financial Officer in August 2005
upon the resignation of James H. Prince. He most recently served as a director of research and a
senior energy analyst at the investment banking firm of Johnson Rice & Company. Prior to joining
Johnson Rice in 1992, he spent five years as an energy analyst and investment banker at Howard Weil
Incorporated.
Andrew L. Gates, III was named Senior Vice President, General Counsel and Secretary in April
2004. He previously served as Vice President, General Counsel and Secretary since August 1995.
E. J. Louviere was named Senior Vice President – Land in April 2004. Previously, he served as
Vice President – Land since June 1995. He has been employed by Stone since its inception in 1993.
J. Kent Pierret was named Senior Vice President in April 2004. Mr. Pierret previously served
as Vice President and Chief Accounting Officer since June 1999 and Treasurer since February 2004.
Prior to June 1999, 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.
Jerome F. Wenzel, Jr. joined Stone in October 2004 as Vice President-Production and Drilling
and was named Senior Vice President – Operations in September 2005. Prior to joining Stone, Mr.
Wenzel held managerial and executive positions with Amoco and BP over a 29 year career.
Michael E. Madden was named Vice President – Reserves in September 2005, Vice President –
Exploration and Production Technology in April 2004 and Vice President – Engineering in March 2002.
Previously, he served as the Lafayette District Manager from February 2001 to March 2002. He has
been employed by Stone Energy since its inception in 1993, initially as a reservoir engineer.
Florence M. Ziegler was named Vice President – Human Resources and Administration in September
2005. She has been employed by Stone since its inception in 1993 and served as the Director of
Human Resources from 1997 to 2004.
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PART II
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 sales
prices per share of our common stock.
On March 1, 2006, the last reported sales price on the New York Stock Exchange Composite Tape
was $42.01 per share. As of that date, there were 163 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 81/4% Senior Subordinated Notes due 2011 and 63/4% Senior Subordinated Notes due
2014. In addition, our bank credit facility contains provisions that may have the effect of
limiting or prohibiting the payment of dividends.
Issuer Purchases of Equity Securities
There were no purchases of Stone’s common stock by us or on our behalf during the quarterly
period ended December 31, 2005.
Equity Compensation Plan Information
Please refer to Item 12 of this Annual Report on Form 10-K/A for information concerning
securities authorized under our equity compensation plan.
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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, 2005 and has been restated to reflect
adjustments to periods 2001 through 2004 that are further discussed in Note 1 to the Consolidated
Financial Statements in “Item 8. Financial Statements and Supplementary Data”. 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.”
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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 of the years in the three-year period ended December 31, 2005. The
financial information in this section has been restated, as further discussed in “Item 8. Note 1 –
Financial Statements and Supplementary Data.” All period to period comparisons are based upon
restated amounts. Our financial statements and the notes thereto, which are found elsewhere in
this Form 10-K/A contain detailed information that should be referred to in conjunction with the
following discussion. See “Item 8. Note 1 – Financial Statements and Supplementary Data.”
Executive Overview
We are an independent oil and gas company engaged in the acquisition, exploration,
exploitation, development and operation of oil and gas properties located in the conventional shelf
of the Gulf of Mexico (the “GOM”), deep shelf of the GOM, deep water of the GOM and several basins
in the Rocky Mountain Region. Our business strategy is to increase reserves, production and cash
flow through the acquisition, exploitation and development of mature properties in the Gulf Coast
Basin and exploring opportunities in the deep water environment of the Gulf of Mexico, Rocky
Mountain Region and other potential areas. See “Item 1. Business – Strategy and Operational
Overview.”
2005 Significant Events.
2006 Outlook.
Our 2006 capital expenditures budget is approximately $360 million, excluding acquisitions,
asset retirement costs and capitalized interest and general and administrative expenses. The $360
million is expected to be spent as follows:
We also expect to continue to investigate new opportunities in the Rocky Mountain Region and
other areas.
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Known Trends and Uncertainties
Gulf Coast Basin Reserve Replacement – We have faced challenges in replacing production in the
Gulf Coast Basin at a reasonable unit cost. This condition has been caused by a number of factors
including the following:
During 2005 and early 2006 we have instituted organizational changes which we believe will
lead to a replenishment of our prospect inventory in 2006 and 2007. Additionally, we have employed
a new risk management system for project evaluation that we believe will result in more efficient
portfolio management.
Louisiana Franchise Taxes – We have been involved in litigation with the state of Louisiana
over the proper computation of franchise taxes allocable to the state. This litigation relates to
the state’s position that sales of crude oil and natural gas from properties located on the Outer
Continental Shelf, which are transported through the state of Louisiana, should be sourced to
Louisiana for purposes of computing franchise taxes. We disagree with the state’s position.
However, if the state’s position were to be upheld, we would incur higher franchise tax expense in
future years barring the implementation of other tax savings measures. See “Item 3. Legal
Proceedings.”
Stock Based Compensation – In 2006, we will begin implementation of Statement of Financial
Accounting Standard (“SFAS”) No. 123(R) which will require expensing of the fair value of stock
option issuances on the income statement. We have previously elected to disclose such amounts.
In 2005, we adjusted our emphasis in our long-term incentive compensation from the issuance of
stock options to the issuance of restricted stock. We expect total equity based compensation
expense in 2006 to total between $9.8 and $10.3 million and estimate approximately $4.5 million of
this amount will be capitalized.
Hurricanes – Since the majority of our production originates in the Gulf of Mexico, we are
particularly vulnerable to the effects of hurricanes on production. In 2004 we experienced an
approximate 7.0 Bcfe deferral of production due to Hurricane Ivan and in 2005 an approximate 16.4
Bcfe deferral due to Hurricanes Katrina and Rita. Although the financial impact of the hurricanes
is difficult to project, we estimate the lost revenue in 2005 from the production deferred was
approximately $150 million, although most volumes were deferred to a later period, not lost. The
hurricane repair related expenses were approximately $25 million for 2005, although a majority is
expected to be reimbursed by our insurance carriers. We had eight structures that were totally
destroyed, two structures that have been condemned and over $50 million in estimated partial damage
to other structures (these platform losses and repairs are substantially covered by insurance). In
addition, we have identified approximately $100 million in expenditures over three years for
removal of wreck and debris, and abandonment projects which are also substantially covered by
insurance. Our overall production dropped from over 280 MMcfe per day in August 2005 to an exit
rate in December 2005 of less than 200 MMcfe per day, as a number of pipeline and processing plants
were still off line or constrained, and may remain as such throughout the balance of 2006.
However, most of the affected production will ultimately come back on line, with less than 10 Bcfe
of estimated proved reserves actually lost due to the hurricanes. The most significant impact to
Stone has been at Mississippi Canyon 109/108, which is expected to remain off line until the fourth
quarter of 2006 due to pipeline problems. Prior to going offline this property was producing
approximately 20 MMcfe per day of production net to Stone. Although we do include hurricane
contingencies in our production forecasting models, hurricane activity can be more frequent and
disruptive than what is projected as was the case in 2004 and 2005.
Regulatory Inquiries and Stockholder Lawsuits – We are subject to ongoing inquiries by the
SEC and the Philadelphia Stock Exchange. We have also been named as a defendant in certain stockholder lawsuits resulting from our
reserve restatement. The ultimate resolution of these matters and their impact on us is uncertain.
Liquidity and Capital Resources
Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $461.2
million during 2005 compared to $369.7 million and $390.8 million in 2004 and 2003, respectively.
Based on our outlook of commodity prices and our estimated production, we expect to fund our 2006
capital expenditures with cash flow provided by operating activities.
Net cash flow used in investing activities totaled $499.9 million, $475.2 million and $341.2
million during 2005, 2004 and 2003, respectively, which primarily represents our investment in oil
and gas properties.
Net cash flow provided by (used in) financing activities totaled $94.2 million, $112.6 million
and ($60.1) million for the years ended December 31, 2005, 2004 and 2003, respectively. Net cash
flow provided by financing activities generated during 2005 primarily relates to net proceeds from
borrowings under our bank credit facility. Net cash flow provided by financing activities
generated during 2004
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primarily relates to the proceeds from our 63/4% Senior Subordinated Notes
offering offset in part by the use of offering proceeds to repay borrowings under our bank credit
facility. Net cash flow used in financing activities during 2003 was primarily the result of the
$61.0 million of repayments under the amended credit facility. Cash and cash equivalents increased
from $24.3 million as of December 31, 2004 to $79.7 million as of December 31, 2005.
We had working capital at December 31, 2005 of $16.5 million. We believe that our working
capital balance should be viewed in conjunction with availability of borrowings under our bank
credit facility when measuring liquidity. “Liquidity” is defined as the ability to obtain cash
quickly either through the conversion of assets or incurrence of liabilities. See “Bank Credit
Facility.”
Our 2006 capital expenditures budget, excluding acquisitions, asset retirement costs and
capitalized interest and general and administrative expenses, is approximately $360 million, or 18%
higher than our 2005 capital expenditures, excluding acquisitions, asset retirement costs and
capitalized interest and general and administrative expenses. Based on our outlook of commodity
prices and our estimated production, we expect to fund our 2006 capital program with cash flow
provided by operating activities.
To the extent that 2006 cash flow from operating activities exceeds our estimated 2006 capital
expenditures, we may pay down a portion of our existing debt. If cash flow from operating
activities during 2006 is not sufficient to fund estimated 2006 capital expenditures, we believe
that our bank credit facility will provide us with adequate liquidity. See “Bank Credit Facility.”
We do not budget acquisitions; however, we are continually evaluating opportunities that fit
our specific acquisition profile. See “Item 1. Business – Strategy and Operational Overview.” Any
one or a combination of certain of these possible transactions could fully utilize our existing
sources of capital. Although we have no current plans to access the public markets for purposes of
capital, if the opportunity arose, we would consider such funding sources to provide capital in
excess of what is currently available to us.
Bank Credit Facility. At March 1, 2006, we had $163 million of borrowings outstanding under
our credit facility and letters of credit totaling $22.9 million had been issued pursuant to the
facility. We have a borrowing base under the credit facility of $300 million, with availability of
an additional $114.1 million in borrowings as of March 1, 2006. Our borrowing base was reduced from
$425 million to $300 million after we announced our reserve revision in October 2005.
Under the financial covenants of our credit facility, we must (i) maintain a ratio of
consolidated debt to consolidated EBITDA, as defined in the amended credit agreement, for the
preceding four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a Consolidated
Tangible Net Worth (as defined). As of December 31, 2005 our debt to EBITDA Ratio was 1.16 and our
Consolidated Tangible Net Worth was approximately $185 million in excess of the amount required to
be maintained. In addition, the credit facility places certain customary restrictions or
requirements with respect to disposition of properties, incurrence of additional debt, change of
ownership and reporting responsibilities. These covenants may limit or prohibit us from paying
cash dividends. During 2005, the participating banks in our credit facility granted waivers from
certain covenants regarding the filing of our financial statements until March 31, 2006.
Additionally, we have agreed to secure borrowings under the facility with a security interest in
certain oil and gas properties. As of the date of this filing we had not completed the transfer of
the security interests to the banks participating in the facility. If we are unable to complete
this transaction by March 31, 2006, it is possible that the balance of the facility could become
due at that time; however, we believe we could replace the facility if this were to occur.
Hedging. See “Item 7A. Quantitative and Qualitative Disclosure About Market Risk – Commodity
Price Risk.”
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Contractual Obligations and Other Commitments
The following table summarizes our significant contractual obligations and commitments, other
than hedging contracts, by maturity as of December 31, 2005.
Results of Operation
2005 Compared to 2004. 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 Natural Gas Reserves.”
For the year ended 2005, we reported net income totaling $136.8 million, or $5.02 per share,
compared to net income for the year ended December 31, 2004 of $119.7 million, or $4.45 per share.
The variance in annual results was due to the following components:
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Production. During 2005, total production volumes decreased 6% to 83.2 Bcfe compared to 88.2
Bcfe produced during 2004. Oil production during 2005 totaled approximately 4.8 million barrels
compared to 2004 oil production of 5.4 million barrels, while natural gas production during 2005
totaled approximately 54.1 billion cubic feet compared to 55.5 billion cubic feet produced during
2004. The decrease in overall 2005 production was primarily the result of extended production
downtime from Hurricanes Katrina and Rita (16.4 Bcfe) in excess of downtime experienced for
Hurricane Ivan in 2004 (7.0 Bcfe).
Prices. Prices realized during 2005 averaged $50.53 per barrel of oil and $7.24 per Mcf of
gas compared to 2004 average realized prices of $39.38 per barrel of oil and $5.94 per Mcf of gas.
On a gas equivalent basis, average 2005 prices were 24% higher than prices realized during 2004.
All unit pricing amounts include the settlement of hedging contracts.
We enter into various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. During 2005, hedging transactions decreased the average price we
received for natural gas by $0.58 per Mcf and for oil by $2.26 per Bbl compared to a net decrease
of $0.18 per Mcf of natural gas realized during 2004.
Oil and Gas Revenue. As a result of 24% higher realized prices on a gas equivalent basis, oil
and gas revenue increased 17% to $636.2 million in 2005 from $544.2 million during 2004 despite a
6% decline in total production volumes during 2005.
Expenses. During 2005, we incurred lease operating expenses of $114.7 million, compared to
$100.0 million incurred during 2004. On a unit of production basis, 2005 lease operating expenses
were $1.38 per Mcfe as compared to $1.13 per Mcfe for 2004. The increase in lease operating
expenses in 2005 is due to a combination of increases in overall industry service costs and
additional costs associated with storm-related shut-ins and evacuations. Included in lease
operating expenses are maintenance costs, which represent repairs and maintenance costs that vary
from year to year. Maintenance costs totaled $28.9 million in 2005 compared to $29.1 million in
2004.
DD&A expense on oil and gas properties for 2005 totaled $238.3 million, or $2.87 per Mcfe
compared to DD&A expense of $208.0 million, or $2.36 per Mcfe in 2004. The increase in DD&A per
Mcfe is attributable to the unit cost of current year net reserve additions (including related
future development costs) exceeding the per unit amortizable base as of the beginning of the year.
See Known Trends and Uncertainties.
During 2005 and 2004, we incurred $7.2 million and $5.9 million, respectively, of accretion
expense related to the January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement
Obligations.” Stone expects accretion expense to total approximately $12.2 million during 2006 as
a result of higher estimated costs combined with a shortened time frame to plug and abandon our
facilities.
The approximate $50 million revision in estimates of asset retirement obligations in 2005 is
due to the following factors: (1) approximately $20.5 million of the increase is due to a
significant increase in 2005 in the cost of services necessary to abandon oil and gas properties;
(2) approximately $9.7 million of the increase is due to an accelerated time frame in which
certain of our oil and gas properties will need to be abandoned as a result of hurricanes Katrina
and Rita; and (3) approximately $19.8 million of the increase is due to additional costs of
wreckage and debris removal associated with the hurricanes.
Interest expense for 2005 totaled $23.2 million, net of $14.9 million of capitalized interest,
compared to interest of $16.8 million, net of $7.0 million of capitalized interest, during 2004.
The increase in interest expense in 2005 is primarily the result of the issuance of our $200
million 63/4% Senior Subordinated Notes on December 15, 2004.
Reserves. At December 31, 2005, our estimated proved oil and gas reserves totaled 593.1 Bcfe,
compared to December 31, 2004 reserves of 668.2 Bcfe. The decrease in estimated proved reserves
during 2005 was the result of production and downward revisions of previous estimates exceeding
additions from drilling results and acquisitions made during the year. Estimated proved natural
gas reserves totaled 344.1 Bcf and estimated proved oil reserves totaled 41.5 MMBbls at the end of
2005. The reserve estimates at December 31, 2005 were engineered and/or audited by engineering
firms in accordance with guidelines established by the SEC.
Our standardized measure of discounted future net cash flows was $1.9 billion and $1.6 billion
at December 31, 2005 and 2004, respectively. You should not assume that these estimates of future
net cash flows represent the fair value of our estimated oil and natural gas reserves. As required
by the SEC, we determine these estimates of 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, excluding the effects of hedges in place at year-end,
were $57.17 per barrel and $9.86 per Mcf for 2005 and $41.06 per barrel and $6.57 per Mcf for 2004.
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2004 Compared to 2003. 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.
For the year ended 2004, net income totaled $119.7 million, or $4.45 per share, compared to
net income for the year ended December 31, 2003 of $123.2 million, or $4.64 per share. The
variance in annual results was due to the following components:
Production. During 2004, total production volumes decreased 9% to 88.2 Bcfe compared to 96.9
Bcfe produced during 2003. Oil production during 2004 totaled approximately 5.4 million barrels
compared to 2003 oil production of 5.7 million barrels, while natural gas production during 2004
totaled approximately 55.5 billion cubic feet compared to 62.5 billion cubic feet produced during
2003. The decrease in overall 2004 production, compared to 2003, was primarily the result of
extended production downtime from Hurricane Ivan totaling 7.0 Bcfe.
Prices. Prices realized during 2004 averaged $39.38 per barrel of oil and $5.94 per Mcf of
gas compared to 2003 average realized prices of $30.41 per barrel of oil and $5.34 per Mcf of gas.
On a gas equivalent basis, average 2004 prices were 18% higher than prices realized during 2003.
All unit pricing amounts include the settlement of hedging contracts.
During 2004, hedging transactions decreased the average price we received for natural gas by
$0.18 per Mcf compared to a net decrease of $0.03 per Mcf of natural gas realized during 2003. We
had no hedges in place for 2003 oil production.
Oil and Gas Revenue. As a result of 18% higher realized prices on a gas equivalent basis, oil
and gas revenue increased 7% to $544.2 million in 2004 from $508.3 million during 2003 despite a 9%
decline in total production volumes during 2004.
Expenses. During 2004, we incurred lease operating expenses of $100.0 million, compared to
$72.8 million incurred during 2003. On a unit of production basis, 2004 lease operating expenses
were $1.13 per Mcfe as compared to $0.75 per Mcfe for 2003. The increase in lease operating
expenses in 2004 is due to a combination of increases in overall industry service costs, additional
costs associated with storm-related shut-ins and evacuations and increases in maintenance costs
included in lease operating expenses during 2004. Included in lease operating expenses are
maintenance costs, which represent repairs and maintenance costs that vary from year to year.
Maintenance costs totaled $29.1 million in 2004 compared to $11.4 million in 2003. The increase in
maintenance costs during 2004 is due primarily to $4.2 million for hurricane-related repairs in
excess of estimated insurance recoveries and $6.8 million related to three replacement wells
drilled during 2004.
DD&A expense on oil and gas properties for 2004 totaled $208.0 million, or $2.36 per Mcfe
compared to DD&A expense of $186.0 million, or $1.92 per Mcfe in 2003. The increase in DD&A per
Mcfe is attributable to the unit cost of current year reserve additions and related future
development costs, exceeding the per unit amortizable base as of the beginning of the year.
During 2004 and 2003, we incurred $5.9 million and $6.3 million, respectively, of accretion
expense related to the January 1, 2003 adoption of SFAS No. 143, “Accounting for Asset Retirement
Obligations.”
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Derivative expenses in 2004 and 2003 represented primarily the cost of put contracts charged
to earnings as the contracts settled during the respective periods. During 2004, we incurred
derivative expenses of $4.1 million compared to $8.7 million in 2003. The decline in derivative
expenses in 2004 is the result of lower costs of put contracts for 2004 hedged production volumes.
Interest expense for 2004 totaled $16.8 million, net of $7.0 million of capitalized interest,
compared to interest of $19.9 million, net of $7.8 million of capitalized interest, during 2003.
The decrease in interest expense in 2004 is the result of the September 2003 redemption of our 83/4%
Senior Subordinated Notes, which lowered the average interest rate on our outstanding debt,
combined with lower average borrowings outstanding during 2004.
Reserves. At December 31, 2004, our estimated proved oil and gas reserves totaled 668.2 Bcfe,
compared to December 31, 2003 reserves of 647.3 Bcfe. The increase in estimated proved reserves
during 2004 was the combined result of drilling results and acquisitions made during the year.
Estimated proved natural gas reserves totaled 413.9 Bcf and estimated proved oil reserves totaled
42.4 MMBbls at the end of 2004.
Our standardized measure of discounted future net cash flows was $1.6 billion and $1.5 billion
at December 31, 2004 and 2003, respectively. You should not assume that these estimates of future
net cash flows represent the fair value of our estimated oil and natural gas reserves. As required
by the SEC, we determine these estimates of 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, excluding the effects of hedges in place at year-end,
were $41.06 per barrel and $6.57 per Mcf for 2004 and $31.72 per barrel and $6.29 per Mcf for 2003.
Off-Balance Sheet Arrangements
We have no off-balance sheet arrangements.
Forward-Looking Statements
Certain of the statements set forth under this item and elsewhere in this Form 10-K/A are
forward-looking and are based upon assumptions and anticipated results that are subject to numerous
risks and uncertainties. See “Item 1. Business — Forward-Looking Statements” and “Item 1A. Risk
Factors.”
Accounting Matters and Critical Accounting Policies
Changes in Accounting Principles. Effective January 1, 2003, management elected to change to
the units of production (“UOP”) method of amortizing proved oil and gas property costs from the
previously used future gross revenue method. Under the UOP method, the quarterly provision for
DD&A is computed by dividing production volumes, instead of revenue, for the period by the total
proved reserves, instead of future gross revenue, as of the beginning of the period, and similarly
applying the respective rate to the net cost of proved oil and gas properties, including future
development costs. Management believes that this change in method is preferable because it removes
fluctuations in DD&A expense caused by product pricing volatility within a reporting period and is
a method more widely used in the oil and gas industry. As a result of the change in accounting
principle, we recognized a charge against our 2003 net income for the cumulative transition
adjustment of $4.6 million, net of tax.
In addition, management elected to begin recognizing production revenue under the Entitlement
method of accounting effective January 1, 2003. Under this method, revenue is deferred for
deliveries in excess of our net revenue interest, while revenue is accrued for the undelivered
volumes. Production imbalances are generally recorded at the estimated sales price in effect at
the time of production. The cumulative effect of adoption of the Entitlement method was
immaterial.
Asset Retirement Obligations. In July 2001, the Financial Accounting Standards Board (“FASB”)
issued SFAS No. 143, “Accounting for Asset Retirement Obligations,” effective for fiscal years
beginning after June 15, 2002. This statement requires us to record our estimate of the fair value
of liabilities related to future asset retirement obligations in the period the obligation is
incurred. Asset retirement obligations relate to the removal of facilities and tangible equipment
at the end of an oil and gas property’s useful life. The adoption of SFAS No. 143 requires the use
of management’s estimates with respect to future abandonment costs, inflation, market risk
premiums, useful life and cost of capital. We adopted SFAS No. 143 on January 1, 2003. Upon
adoption, we recognized a gain for a cumulative transition adjustment of $6.7 million, net of tax,
for existing asset retirement obligation liabilities, asset retirement costs and accumulated
depreciation. In addition, we recorded an $86.7 million increase in the capitalized costs of our
oil and gas properties, net of accumulated depreciation, and recognized $76.3 million in additional
liabilities related to asset retirement obligations. As required by SFAS No. 143, our estimate of
our asset retirement obligations does not give consideration to the value the related assets could
have to other parties.
Full Cost Method. We use the full cost method of accounting for our oil and gas properties.
Under this method, all acquisition, exploration, development and estimated abandonment costs,
including certain related employee costs and general and administrative
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costs (less any
reimbursements for such costs), incurred for the purpose of acquiring and finding oil and gas are
capitalized. Unevaluated property costs are excluded from the amortization base until we have made
a determination as to the existence of proved reserves on the respective property or impairment.
We review our unevaluated properties at the end of each quarter to determine whether the costs
should be reclassified to the full cost pool and thereby subject to amortization. Sales of oil and
gas properties are accounted for as adjustments to the net full cost pool with no gain or loss
recognized, unless the adjustment would significantly alter the relationship between capitalized
costs and proved reserves.
We amortize our investment in oil and gas properties through DD&A using the UOP method. See
“Changes in Accounting Principles” above.
We capitalize a portion of the interest costs incurred on our debt that is calculated based
upon the balance of our unevaluated property costs and our weighted-average borrowing rate. During
2005, 2004 and 2003, we capitalized interest costs of $14.9 million, $7.0 million and $7.8 million,
respectively. We also capitalize the portion of salaries, general and administrative expenses that
are attributable to our acquisition, exploration and development activities. During 2005, 2004 and
2003, we capitalized salaries, general and administrative costs, net of overhead reimbursements, of
$20.5 million, $16.0 million, and $14.2 million, respectively.
Generally accepted accounting principles allow the option of two acceptable methods for
accounting for oil and gas properties. The successful efforts method is the allowable alternative
to the full cost method. The primary differences between the two methods are in the treatment of
exploration costs and in the computation of DD&A. Under the full cost method, all exploratory
costs are capitalized while under the successful efforts method exploratory costs associated with
unsuccessful exploratory wells and all geological and geophysical costs are expensed. Under full
cost accounting, DD&A is computed on cost centers represented by entire countries while under
successful efforts cost centers are represented by properties, or some reasonable aggregation of
properties with common geological structural features or stratigraphic condition, such as fields or
reservoirs.
Under the full cost method of accounting, we compare, at the end of each financial reporting
period, the present value of estimated future net cash flows from proved reserves (based on
period-end hedge adjusted commodity prices and excluding cash flows related to estimated
abandonment costs), net of related tax effect, to the net capitalized costs of proved oil and gas
properties, including estimated capitalized abandonment costs, net of related deferred taxes. We
refer to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and gas
properties exceed the estimated discounted future net cash flows from proved reserves, we are
required to write-down the value of our oil and gas properties to the value of the discounted cash
flows.
Stock-Based Compensation. On December 16, 2004, the FASB issued SFAS No. 123(R),”Share-Based
Payment”, which is a revision of SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No.
123(R) supersedes Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued
to Employees”, and amends SFAS No. 95, “Statement of Cash Flows.” Generally, the approach in SFAS
No. 123(R) is similar to the approach described in SFAS No. 123; however, SFAS No. 123(R) requires
all share-based payments to employees, including grants of employee stock options, be recognized in
the income statement based on their fair values. Pro forma disclosure will no longer be an
alternative.
SFAS No. 123(R) permits public companies to adopt its requirements using one of two methods:
We have elected the modified prospective transition method.
In March 2005, the SEC issued Staff Accounting Bulletin (“SAB”) No. 107 which expressed the
views of the SEC regarding the interaction between SFAS No. 123(R) and certain SEC rules and
regulations. SAB No. 107 provides guidance related to the valuation of share-based payment
arrangements for public companies, including assumptions such as expected volatility and expected
term. In April 2005, the SEC approved a rule that delayed the effective date of SFAS No. 123(R)
for public companies. As a result, SFAS No. 123(R) will be effective for us on January 1, 2006.
Use of Estimates. The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires us to make estimates and assumptions
that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts of revenue and
expenses during the reporting period. Actual results could differ from those estimates. Our most
significant estimates are:
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Derivative Instruments and Hedging Activities. Under SFAS No. 133, as amended, the nature of
a derivative instrument must be evaluated to determine if it qualifies for hedge accounting
treatment. We do not use derivative instruments for trading purposes. Instruments qualifying for
hedge accounting treatment are recorded as an asset or liability measured at fair value and
subsequent changes in fair value are recognized in equity through other comprehensive income, net
of related taxes, to the extent the hedge is effective. Instruments not qualifying for hedge
accounting treatment are recorded in the balance sheet and changes in fair value are recognized in
earnings. During 2005, certain of our hedges became ineffective when actual production was less
than the hedged volumes. This resulted in a charge to income in the amount of $3.4 million.
For a more complete discussion of our accounting policies and procedures see our Notes to
Consolidated Financial Statements beginning on page F-8.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Operating Cost Risk
We are currently experiencing rising operating costs which also impacts our cash flow from
operating activities and profitability. Assuming the costs to operate our properties, including
lease operating expenses and maintenance cost, increased 10%, we estimate our diluted earnings per
share for 2005 would have declined approximately 5%.
Commodity Price Risk
Our revenues, profitability and future rate of growth depend substantially upon the market
prices of oil and natural gas, which fluctuate widely. Oil and gas price declines and volatility
could adversely affect our revenues, cash flow provided by operating activities and profitability.
Assuming a 10% decline in realized oil and natural gas prices, including the effects of hedging
contracts, we estimate our diluted net income per share for 2005 would have declined approximately
32%. In order to manage our exposure to oil and gas price declines, we occasionally enter into oil
and gas price hedging arrangements to secure a price for a portion of our expected future
production.
Our hedging policy provides that not more than 50% of our estimated production quantities can
be hedged without the consent of the board of directors. Because over 90% of our production has
historically been derived from the Gulf Coast Basin, we believe that fluctuations in prices will
closely match changes in the market prices we receive for our production. Oil contracts typically
settle using the average of the daily closing prices for a calendar month. Natural gas contracts
typically settle using the average closing prices for near month NYMEX futures contracts for the
three days prior to the settlement date.
Stone has entered into zero-premium collars with various counterparties for a portion of our
expected 2006 oil and natural gas production from the Gulf Coast Basin. The natural gas collar
settlements are based on an average of NYMEX prices for the last three days of a respective month.
The oil collar settlements are based upon an average of the NYMEX closing price for West Texas
Intermediate (“WTI”) during the entire calendar month. The contracts require payments to the
counterparties if the average price is above the ceiling price or payment from the counterparties
if the average price is below the floor price.
The following tables show our hedging positions as of March 1, 2006:
We believe these positions have hedged approximately 35%-45% of our estimated 2006 production.
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Interest Rate Risk
Stone had long-term debt outstanding of $563 million at December 31, 2005, of which $400
million, or approximately 71%, bears interest at fixed rates. The $400 million of fixed-rate debt
is comprised of $200 million of 81/4% Senior Subordinated Notes due 2011 and $200 million of 63/4%
Senior Subordinated Notes due 2014. The remaining $163 million of debt outstanding at December 31,
2005 bears interest at a floating rate under our bank credit facility. At December 31, 2005, the
weighted average interest rate under our floating-rate debt was approximately 6.0%. At December
31, 2005, we had no interest rate hedge positions in place to reduce our exposure to changes in
interest rates. Assuming a 200 basis point increase in market interest rates during 2005 our
interest expense, net of capitalization, would have increased approximately $1.0 million, net of
taxes, resulting in a $0.04 per diluted share reduction in net income.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Information concerning this Item begins on Page F-1.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
There have been no disagreements with our independent registered public accounting firm on our
accounting or financial reporting that would require our independent registered public accounting
firm to qualify or disclaim their report on our financial statements, or otherwise require
disclosure in this Annual Report on Form 10-K/A.
ITEM 9A. CONTROLS AND PROCEDURES
Deficiencies Relating to Reserve Reporting
We recently completed an internal review of our estimates of proved oil and natural gas
reserves. As a result of this review and subsequent reviews, we reduced our estimate of total
proved oil and natural gas reserves at December 31, 2004 by approximately 237 Bcfe. Management
concluded that the impact of the reserve adjustment on previously issued financial statements was
material and required a restatement. The audit committee of our board of directors engaged the law
firm of Davis Polk & Wardwell (“Davis Polk”) to assist in its investigation of reserve revisions.
Davis Polk presented its final report to the audit committee and board of directors on November 28,
2005. The final report found that a number of factors at Stone contributed to the write-down of
reserves, including the following:
As part of its final report, Davis Polk proposed a number of recommendations, including the
following:
The audit committee and board of directors have accepted the Davis Polk final report, and the
board of directors implemented and resolved to continue to implement all of the recommendations.
Consequently, we have revised our historical proved reserves for the period from December 31,
2001 to June 30, 2005. This revision of reserves also resulted in a restatement of financial
information for the years from 2001 through 2004 and for the first six months of 2005. This
restatement, as well as specific information regarding its impact, is discussed in Note 1 to the
Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data.”
Restatement of previously issued financial statements to reflect
the correction of a misstatement is an indicator of the existence of a material weakness in
internal control over financial reporting as defined in the Public Company Accounting Oversight
Board’s Auditing Standard No. 2, “An Audit of Internal Control Over Financial Reporting Performed
in Conjunction with an Audit of Financial Statements.” We have identified deficiencies in our
internal controls that did not prevent the overstatement of our proved oil and natural gas
reserves. These deficiencies, which we believe constituted a material weakness in our internal
control over financial reporting, included an overly aggressive and optimistic tone
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by some members
of management which created a weak control environment surrounding the booking of proved oil and
natural gas reserves, and inadequate training and understanding of the SEC rules for booking oil
and natural gas reserves. In light of the determination that previously issued financial statements
should be restated, our management concluded that a material weakness in internal control over
financial reporting existed as of December 31, 2005 and disclosed this matter to the audit
committee, and our independent registered public accounting firm.
Remedial Actions
Our management, at the direction of our board of directors, is actively working to improve the
control environment and to implement controls and procedures that will ensure the integrity of our
proved reserve booking process.
We have implemented the following actions to mitigate weaknesses identified:
We intend to implement the following actions in 2006:
Evaluation of Disclosure Control and Procedures
Our Chief Executive Officer and our Chief Financial Officer, with the participation of other
members of our senior management, reviewed and evaluated the effectiveness of our disclosure
controls and procedures as of the end of the period covered by this report. In making this
evaluation, the Chief Executive Officer and the Chief Financial Officer considered the issues
discussed above, together with the remedial steps we have taken. Based on such evaluation, our
Chief Executive Officer and Chief Financial Officer have concluded that, because of the material
weakness discussed above, as of December 31, 2005 and December 31, 2004, our disclosure controls
and procedures were not effective in recording, processing, summarizing and reporting information
required to be disclosed by us in the reports we file or submit under the Securities Exchange Act
of 1934 (the “Exchange Act”).
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting as defined in Rules 13a-15(f) and 15d-(f) of the Exchange Act. Under the
supervision and with the participation of management, including our Chief Executive Officer, and
our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal
control over financial reporting as of December 31, 2005 based on the framework in Internal
Control-Integrated Framework, issued by the Committee of Sponsoring Organizations of the Treadway
Commission (“COSO”). Based on our evaluation under the framework in Internal Control-Integrated
Framework, our management concluded we did not maintain effective controls over the booking of our
oil and natural gas reserves as of December 31, 2005, and these ineffective controls constituted a
material weakness. As a result of this material weakness, estimated proved reserve quantities for
2004 and prior periods were revised downward and our financial statements for the years ended
December 31, 2004, 2003, 2002 and 2001 were restated. These restatements affected the Company’s
proved oil and gas properties, DD&A and write-down of oil and gas properties accounts.
Because of this material weakness, management has concluded that, as of December 31, 2005 and
December 31, 2004, we did not maintain effective internal control over financial reporting, based
on the criteria established in Internal Control-Integrated Framework issued by the COSO.
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Management’s assessment of the effectiveness of our internal control over financial reporting
as of December 31, 2005 has been audited by Ernst and Young LLP, an independent registered public
accounting firm, as stated in their report which is included herein.
Changes in Internal Control Over Financial Reporting
During 2005, we implemented the following actions to improve our control environment and to
implement controls and procedures that will ensure the integrity of our reserve booking process:
We intend to implement the following actions in 2006:
Except as discussed above, there has not been any change in our internal control over
financial reporting that occurred during our year ended December 31, 2005 that has materially
affected, or is reasonably likely to materially affect, our internal control over financial
reporting.
ITEM 9B. OTHER INFORMATION
None.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders of
Stone Energy Corporation: We have audited management’s assessment, included in the accompanying Management’s Report on
Internal Control over Financial Reporting, that Stone Energy Corporation did not maintain effective
internal control over financial reporting as of December 31, 2005, because of the effect of a
material weakness related to the booking of proved oil and natural gas reserves, based on criteria
established in Internal Control—Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Stone Energy Corporation’s management
is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting. Our responsibility is
to express an opinion on management’s assessment and an opinion on the effectiveness of the
Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles. A
company’s internal control over financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of financial statements in accordance
with generally accepted accounting principles, and that receipts and expenditures of the company
are being made only in accordance with authorizations of management and directors of the company;
and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the
financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or
detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
A material weakness is a control deficiency, or combination of control deficiencies, that results
in more than a remote likelihood that a material misstatement of the annual or interim financial
statements will not be prevented or detected. The following material weakness has been identified
and included in management’s assessment. The Company did not maintain effective controls over the
booking of its oil and natural gas reserves as of December 31, 2005, and these ineffective controls
constituted a material weakness. As a result of this material weakness, proved reserve quantities
for 2004 and prior periods were revised downward and the Company’s financial statements for the
years ended December 31, 2004, 2003, 2002 and 2001 were restated. These restatements affected the
Company’s proved oil and gas properties, DD&A and write-down of oil and gas properties accounts.
This material weakness was considered in determining the nature, timing, and extent of audit tests
applied in our audit of the 2005 financial statements, and this report does not affect our report
dated March 7, 2006 on those financial statements.
In our opinion, management’s assessment that Stone Energy Corporation did not maintain effective
internal control over financial reporting as of December 31, 2005, is fairly stated, in all
material respects, based on the COSO control criteria. Also, in our opinion, because of the effect
of the material weakness described above on the achievement of the objectives of the control
criteria, Stone Energy Corporation has not maintained effective internal control over financial
reporting as of December 31, 2005, based on the COSO control criteria.
/s/Ernst & Young LLP
New Orleans, Louisiana
March 7, 2006 35
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
See Item 4A. Executive Officers of the Registrant for information regarding our executive
officers.
Additional information required by Item 10, including information regarding our audit
committee financial experts, is incorporated herein by reference to such information as set forth
in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held on May 18,
2006. The Company has made available free of charge on its Internet Web Site (www.StoneEnergy.com)
the Code of Business Conduct and Ethics applicable to all employees of the Company including the
Chief Executive Officer, Chief Financial Officer and Principal Accounting Officer.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated herein by reference to such information as
set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held
on May 18, 2006.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by Item 12 is incorporated herein by reference to such information as
set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held
on May 18, 2006.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 is incorporated herein by reference to such information as
set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held
on May 18, 2006.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by Item 14 is incorporated herein by reference to such information as
set forth in our definitive Proxy Statement for our 2006 Annual Meeting of Stockholders to be held
on May 18, 2006.
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PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) 1. Financial Statements:
The following consolidated financial statements, notes to the consolidated financial statements
and the Report of Independent Registered Public Accounting Firm thereon are included beginning on
pages F-1 of this Form 10-K/A:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheet as of December 31, 2005 and 2004
Consolidated Statement of Income for the three years in the period ended December 31, 2005
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2005
Consolidated Statement of Changes in Stockholders’ Equity for the three years in the period
ended December 31, 2005
Consolidated Statement of Comprehensive Income for the three years in the period ended
December 31, 2005
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules:
All schedules are omitted because the required information is inapplicable or the information is
presented in the Financial Statements or the notes thereto.
3. Exhibits:
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38
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39
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.
Pursuant to the requirements of the Securities Exchange Act, this report has been signed below
by the following persons on behalf of the Registrant and in the capacities and on the dates
indicated.
40
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INDEX TO FINANCIAL STATEMENTS
F-1
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders of
Stone Energy Corporation: We have audited the accompanying consolidated balance sheet of Stone Energy Corporation as of
December 31, 2005 and 2004, and the related consolidated statements of income, cash flows, changes
in stockholders’ equity and comprehensive income for each of the three years in the period ended
December 31, 2005. These financial statements are the responsibility of the Company’s management.
Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material
respects, the financial position of Stone Energy Corporation as of December 31, 2005 and 2004, and
the consolidated results of its operations and its cash flows for each of the three years in the
period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 1 to the consolidated financial statements, the 2004 and 2003 consolidated
financial statements have been restated to reflect the effects of negative revisions to the
Company’s quantities of estimated proved reserves.
As discussed in Note 2 to the consolidated financial statements, effective January 1, 2003, the
Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” As also discussed in
Note 2 to the consolidated financial statements, effective January 1, 2003, the Company elected to
change to the units of production method of amortizing proved oil and gas property costs and
elected to begin recognizing production revenue under the entitlement method.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the effectiveness of Stone Energy Corporation’s internal control over
financial reporting as of December 31, 2005, based on criteria established in Internal
Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated March 7, 2006, expressed an unqualified opinion on management’s
assessment and an adverse opinion on the effectiveness of internal control over financial
reporting.
/s/ Ernst & Young LLP
New Orleans, Louisiana
March 7, 2006 F-2
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STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Amounts in thousands of dollars, except per share amounts)
The accompanying notes are an integral part of this balance sheet.
F-3
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STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF INCOME
(Amounts in thousands of dollars, except per share amounts)
The accompanying notes are an integral part of this statement.
F-4
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STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands of dollars)
The accompanying notes are an integral part of this statement.
F-5
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STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY
(Amounts in thousands of dollars)
The accompanying notes are an integral part of this statement.
F-6
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STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Amounts in thousands of dollars)
The accompanying notes are an integral part of this statement.
F-7
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STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars, except per share and price amounts)
NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS:
On October 6, 2005, as a result of reservoir level reviews conducted during August 2005
through early October 2005, we announced a downward revision of 171 billion cubic feet of natural
gas equivalent (“Bcfe”) of estimated proved reserves. After additional analysis and additional
consultation with outside engineering firms, the revision was increased to 237 Bcfe.
Based on internal assessments and consultation with outside engineering firms, we concluded
that 157 Bcfe of the negative reserve revisions should have been reflected in 2004 and prior
periods and would require a revision of the historical reserve estimates included in our
supplemental natural gas and oil operating data. Quantities of estimated proved reserves are used
in determining financial statement amounts, including ceiling test charges and depletion,
depreciation and amortization (“DD&A”). The revision of our historical reserve estimates required
the restatement of the financial statement information derived from these estimates for the periods
from 2001 to 2004 and the first two quarters of 2005.
Additionally, in the process of the preparation of our Form 10-Q for September 30, 2005, it
was determined that approximately $9,794 of unevaluated oil and gas property costs were
inappropriately classified and should have been reclassified to proved oil and gas property costs
in 2002. The Financial Restatement includes the effect of this revision for the years ended
December 31, 2002, 2003 and 2004.
Reserves Restatement (Unaudited)
Our reserves restatement resulted in the following revisions to our estimated proved reserves
as of:
Financial Restatement
The total cumulative impact of the restatement on our stockholders’ equity as of December 31,
2004 was a reduction of approximately $81,400, which includes a reduction in beginning
stockholders’ equity as of January 1, 2002 of approximately $45,290.
F-8
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
As to the individual consolidated statement of income line items, our historical financial
statements for the years ended December 31, 2004 and 2003 and for each of the quarters in those
years and the first two quarters of 2005 reflect the effects of the restatement on (1) the
calculation of our historical depletion, depreciation and amortization expense, (2) the effects, if
any, on interest expense resulting from changes in unevaluated oil and gas properties, (3) the
impact on the cumulative effect of accounting changes and (4) the impact on income taxes. We did
not amend our Annual Report on Form 10-K for the year ended December 31, 2004 or our Quarterly
Reports on Form 10-Q for any periods prior to June 30, 2005, and the financial statements and
related financial information contained in those reports should no longer be relied upon. A
summary of the effects of the restatement on reported amounts for the years ended December 31, 2004
and 2003 and quarters ended March 31, 2005 and June 30, 2005 is presented below. Also, the
information in the data below represents only those income statement, balance sheet, cash flow
statement and statement of comprehensive income line items affected by the restatement.
F-9
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
F-10
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
F-11
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
The adjustments related to the restatement resulted in the following restated interim
financial statements for each of the calendar years represented in this Form 10-K/A.
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (In thousands of dollars)
F-12
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF INCOME (In thousands of dollars, except per share amounts) (Unaudited)
F-13
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands of dollars) (Unaudited)
F-14
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In thousands of dollars) (Unaudited)
F-15
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (In thousands of dollars)
F-16
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF INCOME (In thousands of dollars, except per share amounts) (Unaudited)
F-17
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands of dollars) (Unaudited)
F-18
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In thousands of dollars) (Unaudited)
F-19
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEET (In thousands of dollars)
F-20
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF INCOME (In thousands of dollars, except per share amounts) (Unaudited)
F-21
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS (In thousands of dollars) (Unaudited)
F-22
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NOTE 1 — RESTATEMENT OF HISTORICAL FINANCIAL STATEMENTS: (Continued)
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME (In thousands of dollars) (Unaudited)
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