Attached files
file | filename |
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EX-23.2 - EX-23.2 - STONE ENERGY CORP | h79966exv23w2.htm |
EX-31.2 - EX-31.2 - STONE ENERGY CORP | h79966exv31w2.htm |
EX-21.1 - EX-21.1 - STONE ENERGY CORP | h79966exv21w1.htm |
EX-32.1 - EX-32.1 - STONE ENERGY CORP | h79966exv32w1.htm |
EX-31.1 - EX-31.1 - STONE ENERGY CORP | h79966exv31w1.htm |
EX-23.1 - EX-23.1 - STONE ENERGY CORP | h79966exv23w1.htm |
EX-99.1 - EX-99.1 - STONE ENERGY CORP | h79966exv99w1.htm |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-K
(Mark One)
þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
or
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 1-12074
STONE ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
State or other jurisdiction of incorporation or organization: Delaware | I.R.S. Employer Identification No. 72-1235413 |
625 E. Kaliste Saloom Road Lafayette, Louisiana (Address of principal executive offices) |
70508 (Zip Code) |
Registrants telephone number, including area code: (337) 237-0410
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered |
|
Common Stock, Par Value $.01 Per Share | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. þ Yes o 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 whether the registrant has submitted electronically and posted on its
corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant
to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for
such shorter period that the registrant was required to submit and post such files). o 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 registrants 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, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Large accelerated filer o | Accelerated filer þ | Non-accelerated filer o (Do not check if a smaller reporting company) | Smaller reporting company 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 $471,997,324 as of June 30, 2010 (based on the last reported sale price of such stock
on the New York Stock Exchange Composite Tape on that day).
As of February 22, 2011, the registrant had outstanding 49,009,409 shares of Common Stock, par
value $.01 per share.
Documents 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 20, 2011 are
incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
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Table of Contents
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 and its consolidated subsidiaries.
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.
ITEM 1. BUSINESS
The Company
Stone Energy is an independent oil and natural gas company engaged in the acquisition,
exploration, exploitation, development and operation of oil and gas properties located primarily in
the Gulf of Mexico (GOM). We have been operating in the Gulf Coast Basin since our incorporation
in 1993 and have established a technical and operational expertise in this area. More recently, we
have made strategic investments in the deep water and deep shelf GOM, which we have targeted as an
important exploration area. We are also active in the Appalachia region, where we have established
a significant acreage position and have development operations in the Marcellus Shale. We have
also targeted several exploratory oil projects in the Rocky Mountain region. As of December 31,
2010, our estimated proved oil and natural gas reserves were approximately 473.9 Bcfe. We were
incorporated in 1993 as a Delaware corporation. Our corporate headquarters are located at 625 E.
Kaliste Saloom Road, Lafayette, Louisiana.
Strategy and Operational Overview
Our business strategy is to leverage high cash flow generated from existing assets to maintain
relatively stable GOM shelf production, profitably grow gas reserves and production rates in
price-advantaged basins such as Appalachia and the Gulf Coast Basin, and profitably grow oil
reserves and production rates in material impact areas such as the deep water GOM and the Rocky
Mountain region.
Gulf of Mexico Conventional Shelf (Including Onshore Louisiana)
Our conventional shelf strategy is to apply the latest geophysical interpretation tools to
identify underdeveloped properties and the latest production techniques to increase production
attributable to these properties. 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/ Deep Shelf
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 made a
significant investment in seismic data and leasehold interests and have assembled a technical team
with prior geological, geophysical and engineering experience in the deep water arena to evaluate
potential opportunities.
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 usually with existing infrastructure, which shortens the lead time to
production.
Appalachia
During 2006, we began securing leasehold interests in the Appalachia regions of Pennsylvania
and West Virginia. As of February 22, 2011, we have secured leasehold interests in approximately
79,000 net acres. During 2010, we successfully drilled 15 operated horizontal wells. We expect to
add leasehold interests and drill additional wells to further expand our interests in Appalachia.
Rocky Mountain Region
We maintain working interests in several undeveloped plays in the Rocky Mountain region, which
totaled approximately 92,000 net acres as of February 22, 2011. In December 2010, drilling
operations on an exploration well in the Paradox Basin were finished, and the well is currently
being tested. A second horizontal exploration well started drilling in January 2011.
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Oil and Gas Marketing
Our oil and natural gas production is sold at current market prices under short-term
contracts. Shell Trading (US) Company, Conoco, Inc., Sequent Energy Management LP and Hess
Corporation each accounted for between 10% 40% of our oil and natural gas revenue generated
during the year ended December 31, 2010. No other purchaser accounted for 10% or more of our total
oil and natural gas revenue during 2010. We do not believe that the loss of any of our major
purchasers would 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.
Competition and Markets
Competition in the Gulf Coast Basin, the deep water and deep shelf GOM, the Appalachia region
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 we conduct operations 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 Bureau of Ocean Energy Management, Regulation
and Enforcement (BOEMRE), the successor agency to the Minerals Management Service. These leases
contain relatively standardized terms and require compliance with detailed BLM and BOEMRE
regulations and orders pursuant to various federal laws, including the Outer Continental Shelf
Lands Act (the OCSLA) (which are subject to change by the applicable agency). 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 BOEMRE 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,
the (EPA)), lessees must obtain a permit from the BLM or the BOEMRE, 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 BOEMRE generally requires that lessees post
substantial bonds or other acceptable assurances that such obligations will be met, unless the
BOEMRE exempts the lessee from such obligations. The cost of
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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
BOEMRE, 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.
Natural Gas. In 2005, the U.S. 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. In 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 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 FERCs enforcement authority. The
Commodities Futures Trading Commission (CFTC) has similar authority with respect to energy
futures commodity markets. Stone Energy does not anticipate it will be affected any differently
than other producers of natural gas.
In 2007, the FERC issued rules (Order 704) requiring that any market participant, including
a producer such as Stone Energy, that engages in sales for resale or purchases for resale of
natural gas that equal or exceed 2.2 million MMBtus during a calendar year to annually report such
sales or purchases to the FERC, beginning on May 1, 2009. These rules are intended to increase the
transparency of the wholesale natural gas markets and to assist the FERC in monitoring such markets
and in detecting market manipulation. The monitoring and reporting required by these rules have
increased our administrative costs. Stone Energy does not anticipate it will be affected any
differently than other producers of natural gas.
Our sales of natural gas are affected by the availability, terms and cost of transportation.
The price and terms for access to pipeline transportation are subject to extensive regulation. In
recent years, the FERC has undertaken various initiatives to increase competition within the
natural gas industry. As a result of initiatives like FERC Order No. 636, issued in April 1992,
the interstate natural gas transportation and marketing system has been substantially restructured
to remove various barriers and practices that historically limited non-pipeline natural gas
sellers, including producers, from effectively competing with interstate pipelines for sales to
local distribution companies and large industrial and commercial customers. The most significant
provisions of FERC Order No. 636 require that interstate pipelines provide firm and interruptible
transportation service on an open access basis that is equal for all natural gas supplies. In many
instances, the results of FERC Order No. 636 and related initiatives have been to substantially
reduce or eliminate the interstate pipelines traditional role as wholesalers of natural gas in
favor of providing only storage and transportation services. Similarly, the natural gas pipeline
industry is also subject to state regulations, which may change from time to time in ways that
affect the availability, terms, and cost of transportation. However, we do not believe that any
such changes would affect our business in a way that would be materially different from the way
such changes would affect our competitors.
Oil. Effective November 4, 2009, pursuant to the Energy Independence and Security Act of
2007, the Federal Trade Commission (FTC) issued a rule prohibiting market manipulation in the
petroleum industry. The FTC rule prohibits any person, directly or indirectly, in connection with
the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale from knowingly
engaging in any act, practice, or course of business, including the making of any untrue statement
of material fact, that operates or would operate as a fraud or deceit upon any person, or
intentionally failing to state a material fact that under the circumstances renders a statement
made by such person misleading, provided that such omission distorts or is likely to distort market
conditions for any such product. A violation of this rule may result in civil penalties of up to
$1,000,000 per day per violation, in addition to any applicable penalty under the Federal Trade
Commission Act.
Our sales of crude oil, condensate and natural gas liquids are not currently regulated and are
transacted at market prices. In a number of instances, however, the ability to transport and sell
such products is dependent on pipelines whose rates, terms and conditions of service are subject to
FERC jurisdiction under the Interstate Commerce Act. The price we receive from the sale of oil and
natural gas liquids is affected by the cost of transporting those products to market. Interstate
transportation rates for oil, natural gas liquids, and other products are regulated by the FERC.
The FERC has established an indexing system for such transportation, which allows such pipelines to
take an annual inflation-based rate increase.
In other instances, the ability to transport and sell such products is dependent on pipelines
whose rates, terms and conditions of service are subject to regulation by state regulatory bodies
under state statutes. As it relates to intrastate crude oil, condensate and natural gas liquids
pipelines, state regulation is generally less rigorous than the federal regulation of interstate
pipelines. State
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agencies have generally not investigated or challenged existing or proposed rates
in the absence of shipper complaints or protests,
which are infrequent and are usually resolved informally.
We do not believe that the regulatory decisions or activities relating to interstate or
intrastate crude oil, condensate or natural gas liquids pipelines will affect us in a way that
materially differs from the way it affects other crude oil, condensate and natural gas liquids
producers or marketers.
Miscellaneous. Additional proposals and proceedings that might affect the oil and gas
industry are regularly considered by the U.S. 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.
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 require the acquisition of permits authorizing air
emissions and wastewater discharge from operations and 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 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 hydrocarbons or wastes have been taken for
recycling or disposal. In addition, many of these properties have been operated by third parties
whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These
properties and the hydrocarbons and 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.
Oil Pollution Act. The Oil Pollution Act of 1990 (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. Although defenses exist to the liability
imposed by OPA, they are limited. OPA also requires owners and operators of offshore oil
production facilities to establish and maintain evidence of financial responsibility to cover costs
that could be incurred in responding to an oil spill. OPA currently requires a minimum financial
responsibility demonstration of $35 million for companies operating on the OCS, although the
Secretary of Interior may increase this amount up to $150 million in certain situations. We cannot
predict at this time whether OPA will be amended or whether the level of financial responsibility
required for companies operating on the OCS will be increased. In any event, if there were to
occur an oil discharge or substantial threat of discharge, we may be liable for costs and damages,
which costs and liabilities could be material to our results of operations and financial position.
Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide,
methane and other greenhouse gases present an endangerment to public health and the environment
because emissions of such gases are, according to the EPA, contributing to warming of the earths
atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and
implementing regulations to restrict emissions of greenhouse gases under existing provisions of the
Clean Air Act (CAA). The EPA recently adopted two sets of rules regulating greenhouse gas
emissions under the CAA, one of which requires a reduction in emissions of greenhouse gases from
motor vehicles and the other of which regulates emissions of greenhouse gases from certain large
stationary sources, effective January 2, 2011. The EPA has also adopted rules requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the
United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions
occurring after January 1, 2010, as well as certain onshore oil and natural gas production
facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation
to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal
measures to reduce emissions of greenhouse gases primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of
these cap and trade programs work by requiring major sources of emissions, such as electric power
plants, or major
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producers of fuels, such as refineries and gas processing plants, to acquire and
surrender emission allowances. The number of allowances available for purchase is reduced each year
in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases
could require us to incur increased operating costs, such as costs to purchase and operate
emissions control systems, to acquire emissions allowances or comply with new regulatory or
reporting requirements. Any such legislation or regulatory programs could also increase the cost of
consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently,
legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse
effect on our business, financial condition and results of operations. Finally, it should be noted
that some scientists have concluded that increasing concentrations of greenhouse gases in the
Earths atmosphere may produce climate changes that have significant physical effects, such as
increased frequency and severity of storms, droughts, and floods and other climatic events. If any
such effects were to occur, they could have an adverse effect on our financial condition and
results of operations.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used
to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The
process involves the injection of water, sand and chemicals under pressure into the formation to
fracture the surrounding rock and stimulate production. The process is typically regulated by
state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of
Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation
has been introduced before Congress to provide for federal regulation of hydraulic fracturing and
to require disclosure of the chemicals used in the fracturing process. In addition, some states
have adopted, and other states are considering adopting, regulations that could impose more
stringent permitting, disclosure and well construction requirements on hydraulic fracturing
operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well
construction, set back, and disclosure regulations limiting how fracturing can be performed and
requiring various degrees of chemical disclosure. If new laws or regulations that significantly
restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us
to perform fracturing to stimulate production from tight formations. In addition, if hydraulic
fracturing becomes regulated at the federal level as a result of federal legislation or regulatory
initiatives by the EPA, our fracturing activities could become subject to additional permitting
requirements, and also to attendant permitting delays and potential increases in costs.
Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we
are ultimately able to produce from our reserves.
We have made, and will continue to make, expenditures in our effort to comply with
environmental laws and regulations. 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. However, we also believe that it is
reasonably likely that the trend in environmental legislation and regulation will continue toward
stricter standards and, thus, 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 February 22, 2011, we had 331 full time employees. We believe that our relationships with
our employees are satisfactory. None of our employees are covered by a collective bargaining
agreement. We utilize the services of independent contractors to perform various daily operational
duties.
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). 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, which have been approved by our
board of directors. We will make timely 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
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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 February 17, 2010.
Forward-Looking Statements
The information in this Form 10-K 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
managements 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.
Forward-looking statements appear in a number of places and include statements with respect
to, among other things:
| any expected results or benefits associated with our acquisitions; | ||
| estimates of our future oil and natural gas production, including estimates of any increases in oil and gas production; | ||
| planned capital expenditures and the availability of capital resources to fund capital expenditures; | ||
| our outlook on oil and gas prices; | ||
| estimates of our oil and gas reserves; | ||
| any estimates of future earnings growth; | ||
| the impact of political and regulatory developments; | ||
| our outlook on the resolution of pending litigation and government inquiry; | ||
| estimates of the impact of new accounting pronouncements on earnings in future periods; | ||
| our future financial condition or results of operations and our future revenues and expenses; | ||
| our access to capital and our anticipated liquidity; | ||
| estimates of future income taxes; and | ||
| our business strategy and other plans and objectives for future operations. |
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, among other
things:
| consequences of the Deepwater Horizon oil spill and resulting stringent regulatory requirements; | ||
| commodity price volatility; | ||
| domestic and worldwide economic conditions; | ||
| the availability of capital on economic terms to fund our capital expenditures and acquisitions; | ||
| our level of indebtedness; | ||
| declines in the value of our oil and gas properties resulting in a decrease in our borrowing base under our credit facility and ceiling test write-downs and impairments; | ||
| our ability to replace and sustain production; | ||
| the impact of a financial crisis on our business operations, financial condition and ability to raise capital; | ||
| the ability of financial counterparties to perform or fulfill their obligations under existing agreements; | ||
| third party interruption of sales to market; | ||
| lack of availability and cost of goods and services; | ||
| regulatory and environmental risks associated with drilling and production activities; | ||
| drilling and other operating risks; | ||
| unsuccessful exploration and development drilling activities; | ||
| hurricanes and other weather conditions; | ||
| the adverse effects of changes in applicable tax, environmental, derivatives and other regulatory legislation, including changes affecting our offshore and Appalachian operations; | ||
| 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. |
Should one or more of the risks or uncertainties described above or elsewhere in this Form
10-K 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
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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.
ITEM 1A. RISK FACTORS
Our business is subject to a number of risks including, but not limited to, those described
below:
BPs Deepwater Horizon explosion and ensuing oil spill could have broad adverse consequences
affecting our operations in the Gulf of Mexico, some of which may be unforeseeable.
In April 2010, there was a fire and explosion aboard the Deepwater Horizon drilling platform
operated by BP in ultra deep water in the Gulf of Mexico. As a result of the explosion, ensuing
fire and apparent failure of the blowout preventers, the rig sank and created a catastrophic oil
spill that produced widespread economic, environmental and natural resource damage in the Gulf
Coast region. In response to the explosion and spill, there have been many proposals by
governmental and private constituencies to address the direct impact of the disaster and to prevent
similar disasters in the future. Beginning in May 2010, the BOEMRE issued a series of notices to
lessees and operators implementing a six-month moratorium on drilling activities in federal
offshore waters and imposing a variety of new safety measures and permitting requirements.
In addition to the drilling restrictions, new safety measures and permitting requirements
already issued by the BOEMRE, there have been numerous additional proposed changes in laws,
regulations, guidance and policy in response to the Deepwater Horizon explosion and oil spill that
could affect our operations and cause us to incur substantial losses or expenditures.
Implementation of any one or more of the various proposed responses to the disaster could
materially adversely affect operations in the Gulf of Mexico by raising operating costs, increasing
insurance premiums, delaying drilling operations and increasing regulatory costs, and, further,
could lead to a wide variety of other unforeseeable consequences that make operations in the Gulf
of Mexico more difficult, more time consuming, and more costly. For example, OPA currently requires
a minimum financial responsibility demonstration of $35 million for companies operating on the OCS,
although the Secretary of Interior may increase this amount up to $150 million in certain
situations. If we are unable to provide the level of financial assurance required by OPA, we may
be forced to sell our properties or operations located on the OCS or enter into partnerships with
other companies that can meet the increased financial responsibility requirement, and any such
developments could have an adverse effect on the value of our offshore assets and the results of
our operations. We cannot predict at this time whether OPA will be amended or whether the level of
financial responsibility required for companies operating on the OCS will be increased.
New regulatory requirements and permitting procedures recently imposed by the Bureau of Ocean
Energy Management, Regulation and Enforcement could significantly delay our ability to obtain
permits to drill new wells in offshore waters.
Subsequent to the BP Deepwater Horizon incident in the U.S. Gulf of Mexico, the BOEMRE issued
a series of Notice to Lessees (NTLs) imposing new regulatory requirements and permitting
procedures for new wells to be drilled in federal waters of the OCS. These new regulatory
requirements include the following:
| The Environmental NTL, which imposes new and more stringent requirements for documenting the environmental impacts potentially associated with the drilling of a new offshore well and significantly increases oil spill response requirements. | ||
| The Compliance and Review NTL, which imposes requirements for operators to secure independent reviews of well design, construction and flow intervention processes, and also requires certifications of compliance from senior corporate officers. | ||
| The Drilling Safety Rule, which prescribes tighter cementing and casing practices, imposes standards for the use of drilling fluids to maintain well bore integrity, and stiffens oversight requirements relating to blowout preventers and their components, including shear and pipe rams. | ||
| The Workplace Safety Rule, which requires operators to have a comprehensive safety and environmental management system in order to reduce human and organizational errors as root causes of work-related accidents and offshore spills. |
Since the adoption of these new regulatory requirements, BOEMRE has been taking much longer to
review and approve permits for new wells. Due to the extremely slow pace of permit review and
approval, various industry sources have determined that BOEMRE may take six months or longer to
approve applications for drilling permits that were previously approved in less than 30 days. The
new rules also increase the cost of preparing each permit application and will increase the cost of
each new well, particularly for wells drilled in deeper waters on the OCS.
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Oil and natural gas prices are volatile. Declines in commodity prices have adversely affected, and
in the future may adversely affect, our financial condition and results of operations, cash flows,
access to the capital markets, and ability to grow.
Our revenues, cash flows, profitability and future rate of growth substantially depend upon
the market prices of oil and natural
gas. Prices affect our cash flow available for capital expenditures and our ability
to access funds under our bank credit facility and through the capital markets. The amount
available for borrowing under our bank credit facility is subject to a borrowing base, which is
determined by our lenders taking into account our estimated proved reserves and is subject to
periodic redeterminations based on pricing models determined by the lenders at such time. If
commodity prices decline in the future, the decline could have adverse effects on our reserves and
borrowing base.
The prices we receive for our oil and natural gas depend upon factors beyond our control,
including among others:
| changes in the supply of and demand for oil and natural gas; | ||
| market uncertainty; | ||
| the level of consumer product demands; | ||
| hurricanes and other weather conditions; | ||
| domestic governmental regulations and taxes; | ||
| the price and availability of alternative fuels; | ||
| political and economic conditions in oil producing countries, particularly those in the Middle East, Russia, South America and Africa; | ||
| actions by the Organization of Petroleum Exporting Countries (OPEC); | ||
| the foreign supply of oil and natural gas; | ||
| the price of oil and gas imports; and | ||
| overall domestic and foreign economic conditions. |
These factors make it very difficult to predict future commodity price movements with any
certainty. Substantially all of our oil and natural gas sales are made in the spot market or
pursuant to contracts based on spot market prices and are not long-term fixed price contracts.
Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each
other.
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. Approximately 83% of our
estimated proved reserves at December 31, 2010 and 99.5% of our production during 2010 were
associated with our Gulf Coast Basin properties. 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 at a unit cost that is sustainable at
prevailing commodity prices.
Exploring for, developing, or acquiring reserves is capital intensive and uncertain. We may
not be able to economically find, develop, or acquire additional reserves, or may not be able to
make the necessary capital investments if our cash flows from operations decline or external
sources of capital become limited or unavailable. We cannot assure you that our future
exploitation, exploration, development, and acquisition activities will result in additional proved
reserves or that we will be able to drill productive wells at acceptable costs.
Our actual recovery of reserves may substantially differ from our proved reserve estimates.
This Form 10-K 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
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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.
You should not assume that any present value of future net cash flows from our producing
reserves contained in this Form 10-K represents the market value of our estimated oil and natural
gas reserves. We base the estimated discounted future net cash flows from our proved reserves at
December 31, 2010 on average 12-month prices and costs as of the date of the estimate. Actual
future prices and costs may be materially higher or lower. Further, actual future net revenues
will be affected by factors such as the amount and timing of actual development expenditures, the
rate and timing of production, and changes in governmental regulations or taxes. At December 31,
2010, approximately 31% of our estimated proved reserves (by volume) were undeveloped. Recovery of
undeveloped reserves generally requires significant capital expenditures and successful drilling
operations. Our reserve estimates include the assumption that we will make significant capital
expenditures to develop these undeveloped reserves and the actual costs, development schedule, and
results associated with these properties may not be as estimated. In addition, the 10% discount
factor that we use to calculate the net present value of future net revenues and cash flows may not
necessarily be the most appropriate discount factor based on our cost of capital in effect from
time to time and the risks associated with our business and the oil and gas industry in general.
We require substantial capital expenditures to conduct our operations and replace our
production, and we may be unable to obtain needed financing on satisfactory terms necessary
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. 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 redetermined 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 estimates of future asset retirement obligations may vary significantly from period to period
and are especially significant because our operations are almost exclusively in the Gulf of Mexico.
We are required to record a liability for the discounted present value of our asset retirement
obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged
platforms, facilities and equipment, and to restore the land or seabed at the end of oil and
natural gas production operations. These costs are typically considerably more expensive for
offshore operations as compared to most land-based operations due to increased regulatory scrutiny
and the logistical issues associated with working in waters of various depths. Estimating future
restoration and removal costs in the GOM is especially difficult because most of the removal
obligations may be many years in the future, regulatory requirements are subject to change or more
restrictive interpretation, and asset removal technologies are constantly evolving, which may
result in additional or increased costs. As a result, we may make significant increases or
decreases to our estimated asset retirement obligations in future periods. For example, because we
operate in the GOM, platforms, facilities and equipment are subject to damage or destruction as a
result of hurricanes. The estimated cost to plug and abandon a well or dismantle a platform can
change dramatically if the host platform from which the work was anticipated to be performed is
damaged or toppled rather than structurally intact. Accordingly, our estimate of future asset
retirement obligations could differ dramatically from what we may ultimately incur as a result of
damage from a hurricane.
In addition, the BOEMRE recently issued a NTL dated to be effective October 15, 2010 that
establishes a more stringent regimen for the timely decommissioning of what is known as idle iron
wells, platforms and pipelines that are no longer producing or serving exploration or support
functions related to an operators lease in the GOM. Historically, many oil and natural gas
producers in the GOM have delayed the plugging, abandoning or removal of such idle iron until they
met the final decommissioning regulatory requirement, which has been established as being within
one year after the lease expires or terminates, a time period that sometimes is years after use of
the idle iron has been discontinued. The determination of productive lease termination dates are
generally based on managements estimate as to when it would become likely that production,
including from future development activities, would cease on the lease. The recently issued NTL,
however, sets forth more stringent standards for decommissioning timing requirements any well
that has not been used during the past five years for exploration or production on active leases
and is no longer capable of producing in paying quantities must be permanently plugged or
temporarily abandoned within three years. Plugging or abandonment of wells may be delayed by two
years if all of the wells hydrocarbon and sulphur zones are appropriately isolated. Similarly,
platforms or other facilities that are no longer useful for operations must be removed within five
years of the cessation of operations. Triggering of these plugging, abandonment and removal
activities under what may be viewed as an accelerated schedule in comparison to historical
decommissioning efforts may serve to increase, perhaps materially, our future plugging, abandonment
and removal costs, which may translate into a need to increase our estimate of future asset
retirement obligations required to meet such increased costs. In addition, the potential increase
in decommissioning activity in the GOM over the next few years as a result of the NTL could likely
result in increased demand for salvage contractors and equipment, resulting in increased estimates
of plugging, abandonment and removal costs and increases in related asset retirement
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obligations.
For additional information about our asset retirement obligations, see Managements Discussion and
Analysis of Financial Condition and Results of Operations Known Trends and Uncertainties
Asset Retirement Obligations.
A financial crisis may impact our business and financial condition. A financial crisis may
adversely impact our ability to obtain funding under our current bank credit facility or in the
capital markets.
The credit crisis and related turmoil in the global financial systems had an impact on our
business and our financial condition. An economic crisis could reduce the demand for oil and
natural gas and put downward pressure on the prices for oil and natural gas. Historically, we have
used our cash flow from operations and borrowings under our bank credit facility to fund our
capital expenditures and have relied on the capital markets and asset monetization transactions to
provide us with additional capital for large or exceptional transactions. In the future, we may
not be able to access adequate funding under our bank credit facility as a result of (i) a decrease
in our borrowing base due to the outcome of a borrowing base redetermination, or (ii) an
unwillingness or inability on the part of our lending counterparties to meet their funding
obligations. In addition, we may face limitations on our ability to access the debt and equity
capital markets and complete asset sales, an increased counterparty credit risk on our derivatives
contracts and the requirement by contractual counterparties of us to post collateral guaranteeing
performance.
Our debt level and the covenants in the current and any future agreements governing our debt could
negatively impact our financial condition, results of operations and business prospects.
The terms of the current agreements governing our debt impose significant restrictions on our
ability to take a number of actions that we may otherwise desire to take, including:
| incurring additional debt; | ||
| paying dividends on stock, redeeming stock or redeeming subordinated debt; | ||
| making investments; | ||
| creating liens on our assets; | ||
| selling assets; | ||
| guaranteeing other indebtedness; | ||
| entering into agreements that restrict dividends from our subsidiary to us; | ||
| merging, consolidating or transferring all or substantially all of our assets; and | ||
| entering into transactions with affiliates. |
Our level of indebtedness, and the covenants contained in current and future agreements
governing our debt, could have important consequences on our operations, including:
| making it more difficult for us to satisfy our obligations under the indentures or other debt and increasing the risk that we may default on our debt obligations; | ||
| requiring us to dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities; | ||
| limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities; | ||
| limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; | ||
| detracting from our ability to successfully withstand a downturn in our business or the economy generally; | ||
| placing us at a competitive disadvantage against other less leveraged competitors; and | ||
| making us vulnerable to increases in interest rates, because debt under our credit facility is at variable rates. |
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 our bank credit facility, which is redetermined semi-annually, is based on an
amount established by the bank group after its evaluation of our proved oil and gas reserve values.
Our borrowing base is scheduled to be redetermined by May 2011. Upon a redetermination, if
borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to
repay a portion of our bank debt.
We may not have sufficient funds to make such repayments. 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
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and our market value and operating performance at the time of such
offering, refinancing or sale of assets. 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 due to the effects of hurricanes
in the Gulf of Mexico.
Approximately
83% of our estimated proved reserves at December 31, 2010 and
99.5% of our
production during 2010 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 in the Gulf of Mexico. During 2009 and 2008,
we experienced production deferrals due to Hurricanes Gustav and Ike. During 2007, 2006 and 2005,
we experienced production deferrals due to Hurricanes Katrina and Rita, and during 2004, we
experienced production deferrals due to Hurricane Ivan. 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. The tightening of credit in the financial markets may make it more difficult for
customers to obtain financing and, depending on the degree to which this occurs, there may be a
material increase in the nonpayment and nonperformance by customers. 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 and other factors have resulted, and in the future may result,
in ceiling test write-downs and other impairments of our asset carrying values.
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 for each
cost center, the present value of estimated future net cash flows from proved reserves (based on a
12-month average hedge adjusted commodity price and excluding cash flows related to estimated
abandonment costs), to the net capitalized costs of proved oil and gas properties, 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
estimated discounted future net cash flows. A write-down of oil and gas properties does
not impact cash flow from operating activities, but does reduce net income. We also assess the
carrying amount of goodwill when events occur that may indicate an impairment exists. These events
include, for example, a significant decline in oil and gas prices or a decline in our market
capitalization. We recorded an impairment of all our goodwill of approximately $466 million for
the year ended December 31, 2008. The risk that we will be required to write down the carrying
value of oil and gas properties and goodwill 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 or our undeveloped property values, or if estimated future
development costs increase. For example, oil and natural gas prices declined
significantly throughout the second half of 2008 and into 2009. We recorded a non-cash ceiling
test impairment of approximately $1.3 billion for the year ended December 31, 2008 and
approximately $509.0 million for the year ended December 31, 2009. Volatility in commodity
prices, poor conditions in the global economic markets and other factors could cause us to record
additional write-downs of our oil and natural gas properties and other assets in the future and
incur additional charges against future earnings.
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.
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Part of our strategy includes drilling in new or emerging plays. As a result, our drilling
in these areas is subject to greater risk and uncertainty.
We have made initial investments in acreage and wells in Appalachia and in the Rocky Mountain
region. These activities are more uncertain than drilling in areas that are developed and have
established production. Our operations in Appalachia and in the Rocky Mountain region are still in
the early stages. Because emerging plays and new formations have limited or no production
history, we are less able to use past drilling results to help predict future results. The
lack of historical information may result in not being able to fully execute our expected drilling
programs in these areas or the return on investment in these areas may turn out not to be as
attractive as anticipated. We cannot assure you that our future drilling activities in these
emerging plays will be successful, or if successful will achieve the resource potential levels that
we currently anticipate based on the drilling activities that have been completed or achieve the
anticipated economic returns based on our current cost models.
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 reserves 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:
| unexpected drilling conditions; | ||
| pressure or irregularities in formations; | ||
| equipment failures or accidents; | ||
| hurricanes and other weather conditions; | ||
| shortages in experienced labor; and | ||
| shortages or delays in the delivery of equipment. |
The prevailing prices of oil and natural gas also affect the cost of and the demand for
drilling rigs, production equipment and related services. We cannot assure you that the new wells
we drill will be productive or that we will recover all or any portion of our investment. Drilling
for oil and natural gas may be unprofitable. Drilling activities can result in dry wells and wells
that are productive but do not produce sufficient net 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. Additionally, our offshore operations are
subject to the additional hazards of marine operations, such as capsizing, collision and adverse
weather and sea conditions, including the effects of hurricanes.
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 and more expensive 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.
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.
We may not be insured against all of the operating risks to which our business in exposed.
In accordance with industry practice, we maintain insurance against some, but not all, of the
operating risks to which our business is exposed. We insure some, but not all, of our properties
from operational and hurricane related events. We currently have insurance policies that include
coverage for general liability, physical damage to our oil and gas properties, operational control
of wells, oil pollution, third party liability, workers compensation and employers liability and
other coverage. Our insurance coverage includes deductibles that must be met prior to recovery, as
well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and
limitations, and there is no assurance that such coverage will adequately protect us against
liability from all potential consequences and damages and losses.
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Currently, we have general liability insurance coverage with an annual aggregate limit of up
to $75 million applicable to our working interest. We also have an offshore property physical
damage policy that contains a $75 million annual aggregate named windstorm limit. Our operational
control of well coverage provides limits that vary by well location and depth and range from a
combined single limit of $10 million to $150 million per occurrence. Exploratory deep water wells
have a coverage limit of $300 million per occurrence. Additionally, we maintain $35 million in oil
pollution liability coverage. Our control of well and oil pollution liability policy limits are
scaled proportionately to our working interests, and all of our policies described above are
subject to deductibles, sub-limits and/or self-insurance. Under our service agreements, including
drilling contracts, generally we
are indemnified for injuries and death of the service providers employees as well as
contractors and subcontractors hired by the service provider.
An operational or hurricane related event may cause damage or liability in excess of our
coverage, which might severely impact our financial position. We may be liable for damages from an
event relating to a project in which we are a non-operator, but have a working interest in such
project. Such an event may also cause a significant interruption to our business, which might also
severely impact our financial position. For example, we experienced production interruptions in
2005, 2006 and 2007 from Hurricanes Katrina and Rita and in 2008 and 2009 from Hurricanes Gustav
and Ike for which we had no production interruption insurance.
We reevaluate the purchase of insurance, policy limits and terms annually each May. In light
of the recent catastrophic accident in the GOM, we may not be able to secure similar coverage for
the same costs. Future insurance coverage for our industry could increase in cost and may include
higher deductibles or retentions. In addition, some forms of insurance may become unavailable in
the future or unavailable on terms that we believe are economically acceptable. No assurance can
be given that we will be able to maintain insurance in the future at rates that we consider
reasonable and we may elect to maintain minimal or no insurance coverage. We may not be able to
secure additional insurance or bonding that might be required by new governmental regulations.
This may cause us to restrict our operations in the GOM, which might severely impact our financial
position. The occurrence of a significant event, not fully insured against, could have a material
adverse effect on our financial condition and results of operations.
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, the Appalachia region 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.
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The loss of key personnel could adversely affect our ability to operate.
Our operations are dependent upon 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:
| our production is less than expected or is shut-in for extended periods due to hurricanes or other factors; | ||
| there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; | ||
| the counterparties to our futures contracts fail to perform the contracts; | ||
| a sudden, unexpected event materially impacts oil or natural gas prices; or | ||
| we are unable to market our production in a manner contemplated when entering into the hedge contract. |
Currently, some of our outstanding commodity derivative instruments are with certain lenders
or affiliates of the lenders under our bank credit facility. Our existing derivative agreements
with our lenders are secured by the security documents executed by the parties under our bank
credit facility. Future collateral requirements for our commodity hedging activities are
uncertain and will depend on the arrangements we negotiate with the counterparty and the
volatility of oil and natural gas prices and market conditions.
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 and Bylaws 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 board of directors 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, 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.
Resolution of litigation could materially affect our financial position and results of operations.
We have been named as a defendant in certain lawsuits (See Item 3. Legal Proceedings). In
some of these suits, our liability for potential loss upon resolution may be mitigated by insurance
coverage. To the extent that potential exposure to liability is not covered by insurance or
insurance coverage is inadequate, we could incur losses that could be material to our financial
position or results of operations in future periods.
Certain U.S. federal income tax deductions currently available with respect to oil and gas
exploration and development may be eliminated as a result of future legislation.
Legislation has been proposed that would, if enacted into law, make significant changes to
U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax
incentives currently available to oil and natural gas exploration and production companies. These
changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for
oil and gas properties; (ii) the elimination of current deductions for intangible drilling and
development costs; (iii) the elimination of the deduction for certain U.S. production activities;
and (iv) an extension of the amortization period for certain geological and geophysical
expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how
soon any such changes could become effective. The passage of this legislation or any other similar
changes in U.S. Federal income tax laws could eliminate or postpone certain tax deductions that are
currently available with respect to oil and natural gas exploration and development, and any such
change could negatively impact the value of an investment in our common stock.
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Climate change legislation or regulations restricting emissions of greenhouse gases could result
in increased operating costs and reduced demand for the crude oil and natural gas that we produce.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and other
greenhouse gases present an endangerment to public health and the environment because emissions
of such gases are, according to the EPA, contributing to warming of the earths atmosphere and
other climatic changes. Based on these findings, the EPA has begun adopting and implementing
regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. The
EPA recently
adopted two sets of rules regulating greenhouse gas emissions under the CAA, one of which
requires a reduction in emissions of greenhouse gases from motor vehicles and the other of which
regulates emissions of greenhouse gases from certain large stationary sources, effective January 2,
2011. The EPAs rules relating to emissions of greenhouse gases from large stationary sources of
emissions are currently subject to a number of legal challenges, but the federal courts have thus
far declined to issue any injunctions to prevent the EPA from implementing, or requiring state
environmental agencies to implement, the rules. The EPA has also adopted rules requiring the
reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the
United States, including petroleum refineries, on an annual basis, beginning in 2011 for emissions
occurring after January 1, 2010, as well as certain onshore oil and natural gas production
facilities, on an annual basis, beginning in 2012 for emissions occurring in 2011.
In addition, the United States Congress has from time to time considered adopting legislation
to reduce emissions of greenhouse gases and almost one-half of the states have already taken legal
measures to reduce emissions of greenhouse gases primarily through the planned development of
greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. Most of
these cap and trade programs work by requiring major sources of emissions, such as electric power
plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and
surrender emission allowances. The number of allowances available for purchase is reduced each year
in an effort to achieve the overall greenhouse gas emission reduction goal.
The adoption of legislation or regulatory programs to reduce emissions of greenhouse gases
could require us to incur increased operating costs, such as costs to purchase and operate
emissions control systems, to acquire emissions allowances or comply with new regulatory or
reporting requirements. Any such legislation or regulatory programs could also increase the cost of
consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently,
legislation and regulatory programs to reduce emissions of greenhouse gases could have an adverse
effect on our business, financial condition and results of operations. Finally, it should be noted
that some scientists have concluded that increasing concentrations of greenhouse gases in the
Earths atmosphere may produce climate changes that have significant physical effects, such as
increased frequency and severity of storms, droughts, and floods and other climatic events. If any
such effects were to occur, they could have an adverse effect on our financial condition and
results of operations.
The recent adoption of derivatives legislation by the United States Congress could have an adverse
effect on our ability to use derivative instruments to reduce the effect of commodity price,
interest rate and other risks associated with our business.
The United States Congress adopted comprehensive financial reform legislation that establishes
federal oversight and regulation of the over-the-counter derivatives market and entities, such as
us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street
Reform and Consumer Protection Act (the Act), was signed into law by the President on July 21,
2010 and requires the CFTC and the SEC to promulgate rules and regulations implementing the new
legislation within 360 days from the date of enactment. In its rulemaking, the CFTC has proposed
regulations to set position limits for certain futures and option contracts in the major energy
markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions
or positions would be exempt from these position limits. It is not possible to predict when the
CFTC will finalize these regulations. The financial reform legislation may also require us to
comply with margin requirements and with certain clearing and trade-execution requirements in
connection with our derivative activities, although the application of those provisions to us is
uncertain at this time. The financial reform legislation may also require the counterparties to
our derivative instruments to spin off some of their derivatives activities to a separate entity,
which may not be as creditworthy as the current counterparty. The new legislation and any new
regulations could significantly increase the cost of derivative contracts (including through
requirements to post collateral which could adversely affect our available liquidity), materially
alter the terms of derivative contracts, reduce the availability of derivatives to protect against
risks that we encounter, reduce our ability to monetize or restructure our existing derivative
contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of
derivatives as a result of the legislation and regulations, our results of operations may become
more volatile and our cash flows may be less predictable, which could adversely affect our ability
to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to
reduce the volatility of oil and natural gas prices, which some legislators attributed to
speculative trading in derivatives and commodity instruments related to oil and natural gas. Our
revenues could therefore be adversely affected if a consequence of the legislation and regulations
is to lower commodity prices. Any of these consequences could have a material, adverse effect on
us, our financial condition, and our results of operations.
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Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could
make it more difficult or costly for us to perform fracturing of producing formations and could
have an adverse effect on our ability to produce oil and gas from new wells.
Hydraulic fracturing is an important and common practice that is used to stimulate production
of hydrocarbons, particularly natural gas, from tight formations. We routinely use hydraulic
fracturing techniques in many of our natural gas wells drilling and completion programs. The
process involves the injection of water, sand and chemicals under pressure into the formation to
fracture the surrounding rock and stimulate production. The process is typically regulated by
state oil and gas commissions. However, the EPA, recently asserted federal regulatory authority
over hydraulic fracturing involving diesel additives under the Safe Drinking Water Acts
Underground Injection Control Program. While the EPA has yet to take any action to enforce or
implement this newly asserted regulatory authority, industry groups have filed suit challenging the
EPAs recent decision. At the same time, the EPA has commenced a study of the potential
environmental impacts of hydraulic fracturing activities, and a committee of the U.S. House of
Representatives is also conducting an investigation of hydraulic fracturing practices. Legislation
has been introduced before Congress to provide for federal regulation of hydraulic fracturing and
to require disclosure of the chemicals used in the fracturing process. In addition, some states
have adopted, and other states are considering adopting, regulations that could impose more
stringent permitting, disclosure and well construction requirements on hydraulic fracturing
operations. For example, Pennsylvania, Colorado, and Wyoming have each adopted a variety of well
construction, set back, and disclosure regulations limiting how fracturing can be performed and
requiring various degrees of chemical disclosure. If new laws or regulations that significantly
restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us
to perform fracturing to stimulate production from tight formations. In addition, if hydraulic
fracturing becomes regulated at the federal level as a result of federal legislation or regulatory
initiatives by the EPA, our fracturing activities could become subject to additional permitting
requirements, and also to attendant permitting delays and potential increases in costs.
Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we
are ultimately able to produce from our reserves.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
As of February 22, 2011, our property portfolio consisted of 65 active properties and 102
primary term leases in the Gulf Coast Basin, five active properties in the Appalachia region, and
two active properties in the Rocky Mountain region. We serve as operator on 76% of our active
properties. The properties that we operate accounted for 90.2% of our year-end 2010 estimated
proved reserves. This high operating percentage allows us to better control the timing, selection
and costs of our drilling and production activities.
Oil and Natural Gas Reserves
In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which
adopted revisions to the SECs oil and gas reporting requirements. Among other things, the
revisions: (1) replaced the single-day year-end pricing with a twelve-month average pricing
assumption; (2) permit the reporting of probable and possible reserves in addition to the existing
requirement to disclose proved reserves; (3) allow the use of new technologies to determine proved
reserves if those technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes; (4) require the disclosure of the independence and qualifications of third
party preparers of reserves; and (5) require the filing of reports when a third party is relied
upon to prepare or audit reserve estimates. We were required to adopt the provisions of the new
rule as of December 31, 2009.
Our Reserves Committee Charter provides that the reserves committee has the sole authority to
recommend to the Board of Directors appointments or replacements of one or more firms of
independent reservoir engineers and geoscientists. The reserves committee reviews annually the
arrangements of the independent reservoir engineers and geoscientists with management, including
the scope and general extent of the examination of our reserves, the reports to be rendered, the
services and fees, and consideration of the independence of such independent reservoir engineers
and geoscientists. The reserves committee may consult with management but may not delegate these
responsibilities. The reserves committee provides oversight in regards to the reserve estimation
process but not the actual determination of estimated proved reserves. Our Reserves Committee
Charter provides that it is the duty of management and not the duty of the reserves committee to
plan or conduct reviews or to determine that our reserve estimates are complete and accurate and
are in accordance with generally accepted engineering standards and applicable rules and
regulations of the SEC. Our Director of Strategic Planning is the in-house person designated as
primarily responsible for the process of reserve preparation. He is a petroleum engineer with
nineteen years experience in reservoir engineering and analysis. His duties include oversight of
estimate preparation of non year-end quarterly estimations and coordination with the outside
engineering consultants on the preparation of year-end reserve estimates. The year-end reserve
estimates prepared by our outside engineering firm are independent of any oversight of the Director
of Strategic Planning or the reserves committee.
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Estimates of our proved reserves at December 31, 2010 were prepared by Netherland, Sewell &
Associates, Inc. (NSA), a nationally recognized engineering firm. NSA provides a complete range
of geological, geophysical, petrophysical and engineering services and has the technical experience
and ability to perform these services in any of the onshore and offshore oil and gas producing
areas of the world. NSA currently has a technical staff of approximately 70 professionals who are
intimately familiar with recognized industry reserve and resource definitions, specifically those
set forth by the SEC. NSAs letter is filed as an exhibit to this Annual Report on Form 10-K.
The following table sets forth our estimated proved oil and gas reserves (83% of which are
located in the Gulf Coast Basin and 17% are located in the Appalachia region) as of December 31,
2010. The 2010 average 12-month oil and gas prices net of differentials were $77.68 per barrel of
oil and $4.46 per Mcf of gas.
Summary of Oil and Gas Reserves as of December 31, 2010
Based on Average Fiscal-Year Prices
Based on Average Fiscal-Year Prices
Oil and | ||||||||||||
Oil | Natural Gas | Natural Gas | ||||||||||
(MBbls) | (MMcf) | (MMcfe) | ||||||||||
Reserves Category: |
||||||||||||
PROVED |
||||||||||||
Developed |
25,000 | 174,876 | 324,876 | |||||||||
Undeveloped |
8,203 | 99,829 | 149,047 | |||||||||
TOTAL PROVED |
33,203 | 274,705 | 473,923 |
At December 31, 2010, we reported estimated proved undeveloped reserves (PUDs) of 149.0
Bcfe, which accounted for 31% of our total estimated proved oil and gas reserves. This figure ties
to a projected 31 new wells (95.3 Bcfe) and 18 sidetracks from existing wellbores (53.7 Bcfe). Our
timetable for the 18 sidetrack wells is totally dependent on the life of the currently producing
zones. After the current zones have depleted, we would utilize the existing wellbore to sidetrack
to the PUD objective. Regarding the remaining 31 PUD locations, we project eight wells to be
drilled in 2011 (21.0 Bcfe); eleven wells in 2012 (40.8 Bcfe); ten wells in 2013 (28.6 Bcfe); and
two wells in 2014 (4.9 Bcfe). None of these 31 PUD wells will have been on our books in excess of
five years at the time of their scheduled drilling. The following table discloses our progress
toward the conversion of PUDs during 2010.
Future Development | ||||||||
Oil and Natural Gas | Costs | |||||||
(MMcfe) | ($ in thousands) | |||||||
PUDs beginning of year |
91,982 | $ | 254,299 | |||||
Revisions of previous estimates |
(4,302 | ) | (8,970 | ) | ||||
Conversions to proved developed reserves |
| | ||||||
Additional PUDs added |
61,367 | 121,155 | ||||||
PUDs end of year |
149,047 | $ | 366,484 | |||||
Our progress in 2010 towards the drilling of PUD wells was delayed due to permitting
restrictions in the GOM. However, we did spud a PUD well in late 2010 that was completed in early
2011. This resulted in the conversion of approximately 4.2 Bcfe of previously booked PUD reserves
to proved developed producing reserves in 2011.
The following represents additional information on our significant properties:
December 31, 2010 | ||||||||||||||||
2010 | Estimated Proved | |||||||||||||||
Production | Reserves | Nature of | ||||||||||||||
Field Name | Location | (MMcfe) | (MMcfe) | Interest | ||||||||||||
Mississippi Canyon Block 109 |
GOM Shelf | 10,019 | 87,038 | Working | ||||||||||||
Ship Shoal Block 113 |
GOM Shelf | 5,782 | 59,399 | Working | ||||||||||||
Ewing Bank Block 305 |
GOM Shelf | 6,176 | 27,796 | Working | ||||||||||||
Mary |
Appalachia | 23 | 26,092 | Working | ||||||||||||
Main Pass Block 288 |
GOM Shelf | 3,374 | 20,308 | Working | ||||||||||||
South Pelto Block 22 |
GOM Shelf | 3,802 | 19,483 | Working |
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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 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.
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.
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 in the
United States and China during the periods indicated. Certain amounts for 2008 have been corrected
in the following table to reflect a change in our asset retirement obligations during that year.
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
(In thousands) | ||||||||||||
Acquisition costs, net of sales of unevaluated properties |
$ | 127,069 | $ | 9,072 | $ | 1,830,468 | ||||||
Development costs (1) |
241,387 | 199,375 | 78,359 | |||||||||
Exploratory costs |
42,205 | 78,582 | 146,529 | |||||||||
Subtotal |
410,661 | 287,029 | 2,055,356 | |||||||||
Capitalized salaries, general and administrative costs
and interest, net of fees and reimbursements |
51,016 | 44,282 | 45,757 | |||||||||
Total additions to oil and gas properties, net |
$ | 461,677 | $ | 331,311 | $ | 2,101,113 | ||||||
(1) | Includes asset retirement costs of $56,444, $78,387 and ($77,573) for the years ended December 31, 2010, 2009 and 2008, respectively. |
Production Volumes, Sales Price and Cost Data. The following table sets forth certain
information regarding our production volumes, sales prices and average production costs for the
periods indicated.
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Production: |
||||||||||||
Oil (MBbls) |
5,714 | 6,207 | 4,916 | |||||||||
Natural gas (MMcf) |
41,937 | 41,335 | 34,409 | |||||||||
Oil and natural gas (MMcfe) |
76,221 | 78,577 | 63,903 | |||||||||
Average sales prices: (1) |
||||||||||||
Oil (per Bbl) |
$ | 73.14 | $ | 70.72 | $ | 93.79 | ||||||
Natural gas (per Mcf) |
5.56 | 6.59 | 9.78 | |||||||||
Oil and natural gas (per Mcfe) |
8.54 | 9.05 | 12.48 | |||||||||
Expenses (per Mcfe): |
||||||||||||
Lease operating expenses (2) |
$ | 2.00 | $ | 2.00 | $ | 2.68 |
(1) | Includes the settlement of effective hedging contracts. | |
(2) | Includes oil and gas operating costs and major maintenance expense and excludes production and ad valorem taxes. |
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Production Volumes, Sales Price and Cost Data for Individually Significant Fields. The
following table sets forth certain information regarding our production volumes, sales prices and
average production costs for the periods indicated for any field(s) containing 15% or more of our
total estimated proved reserves at December 31, 2010.
Year Ended December 31, | ||||||||||||
Mississippi Canyon Block 109 | 2010 | 2009 | 2008 | |||||||||
Production: |
||||||||||||
Oil (MBbls) |
1,389 | 861 | 1,035 | |||||||||
Natural gas (MMcf) |
1,686 | 1,092 | 1,700 | |||||||||
Oil and natural gas (MMcfe) |
10,019 | 6,256 | 7,913 | |||||||||
Average sales prices: (1) |
||||||||||||
Oil (per Bbl) |
$ | 77.29 | $ | 66.68 | $ | 107.96 | ||||||
Natural gas (per Mcf) |
4.89 | 3.81 | 9.55 | |||||||||
Oil and natural gas (per Mcfe) |
11.54 | 9.86 | 16.18 | |||||||||
Expenses (per Mcfe): |
||||||||||||
Lease operating expenses (2) |
$ | 1.27 | $ | 2.19 | $ | 0.86 |
(1) | Exclusive of the settlement of effective hedging contracts. | |
(2) | Includes oil and gas operating costs and major maintenance expense and excludes production and ad valorem taxes. |
Drilling Activity. The following table sets forth our drilling activity for the periods
indicated.
Year Ended December 31, | ||||||||||||||||||||||||
2010 | 2009 | 2008 | ||||||||||||||||||||||
Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||
Exploratory Wells: |
||||||||||||||||||||||||
Productive |
6.00 | 4.10 | 12.00 | 6.75 | 6.00 | 3.50 | ||||||||||||||||||
Dry |
| | | | 6.00 | 3.98 | ||||||||||||||||||
Development Wells: |
||||||||||||||||||||||||
Productive |
20.00 | 15.75 | 5.00 | 4.00 | 9.00 | 7.18 | ||||||||||||||||||
Dry |
| | 4.00 | 4.00 | 1.00 | 0.25 |
During the period beginning January 1, 2011 and ending February 22, 2011, we participated in
the drilling of five gross (2.89 net) exploratory wells and four gross (4.00 net) development
wells.
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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, 2010.
Gross | Net | |||||||
Productive Wells: |
||||||||
Oil (1): |
||||||||
Gulf Coast Basin |
153 | 119 | ||||||
Rocky Mountain Region |
3 | 1 | ||||||
Appalachia |
| | ||||||
156 | 120 | |||||||
Gas (2): |
||||||||
Gulf Coast Basin |
105 | 79 | ||||||
Rocky Mountain Region |
| | ||||||
Appalachia |
10 | 8 | ||||||
115 | 87 | |||||||
Total |
271 | 207 | ||||||
Developed Acres: |
||||||||
Gulf Coast Basin |
440,195 | 338,856 | ||||||
Rocky Mountain Region |
1,234 | 432 | ||||||
Appalachia |
1,116 | 1,116 | ||||||
442,545 | 340,404 | |||||||
Undeveloped Acres (3): |
||||||||
Gulf Coast Basin |
528,656 | 377,609 | ||||||
Rocky Mountain Region |
109,030 | 91,708 | ||||||
Appalachia |
88,253 | 78,599 | ||||||
725,939 | 547,916 | |||||||
Total |
1,168,484 | 888,320 | ||||||
(1) | 16 gross wells each have dual completions. | |
(2) | 13 gross wells each have dual completions. | |
(3) | Leases covering approximately 7.8% of our undeveloped gross acreage will expire in 2011, 9.4% in 2012, 36.1% in 2013, 5.5% in 2014, 14.7% in 2015, 4.1% in 2016, 1.8% in 2017, 10.3% in 2018, 4.8% in 2019 and 5.5% thereafter. |
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
Franchise Tax Action. 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 tax
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 tax years 1999, 2000 and 2001. 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. Also, on January 2, 2008, Stone was served with a petition (civil action number
2007-6754) claiming $1.5 million of additional franchise taxes due for the 2004 franchise tax year,
plus accrued interest of $800,000 calculated through November 30, 2007. Further, on January 7,
2009, Stone was served with a petition (civil action number 2008-7193) claiming additional
franchise taxes due for the taxable years ended December 31, 2005 and 2006 in the amount of $4.0
million plus accrued interest calculated through October 21, 2008 in the amount of $1.7 million.
In addition, we have received assessments from the LDR for additional franchise taxes in the amount
of $2.9 million resulting from audits of a subsidiary. These assessments all relate to the LDRs
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. The
franchise tax years 2007 through 2010 for Stone remain subject to examination.
Ad Valorem Tax Suit. In August 2009, Gene P. Bonvillain, in his capacity as Assessor for the
Parish of Terrebonne, State of Louisiana, filed civil action No. 90-03540 and other consolidated
cases in the United States District Court for the Eastern District of Louisiana against
approximately thirty oil and gas companies, including Stone, and their respective chief executive
officers for allegedly unpaid ad valorem taxes. The amount originally alleged to be due by Stone
for the years 1998 through 2008 was $11.3 million. The defendants were subsequently served and
filed motions to dismiss this litigation pursuant to Rule 12(b)(6) of the Federal Rules of Civil
Procedure. On March 29, 2010, the trial court judge dismissed plaintiffs claims without
prejudice, with the dismissal to become effective within ten days unless plaintiff filed an amended
complaint correcting its deficiencies. On April 8, 2010, plaintiff filed a first amended complaint
without naming any of the chief executive officers as defendants and with an amount allegedly due
by Stone of not less than $3.5 million. Defendants filed motions to dismiss this litigation, and
the trial court judge granted these motions to dismiss on July 26, 2010. Subsequently, Bonvillain
appealed the dismissal, and the appeal is currently pending before the 5th Circuit Court
of Appeals. In its appellate brief, Bonvillain stated that its appeal against Stone is hereby
waived. On January 26, 2011, an order was entered formally dismissing Stone from this appeal, and
this matter is now concluded.
Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet, et al.,
filed civil action No. 110741 in the 17th Judicial District Court, Lafourche Parish,
Louisiana, against Stone. Plaintiffs have since filed three supplemental petitions, including a
third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of
approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs allege
that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs in
excess of $60 million. Plaintiffs expert witness provided his report, dated December 28, 2010,
stating his opinion that one well did not produce as much production as it should have, resulting
in a loss to plaintiffs in excess of $4 million, that imprudent operations destroyed hydrocarbon
bearing zones resulting in a loss to plaintiffs in excess of $20 million, and that imprudent
operation of a water injection secondary recovery project resulted in damages to plaintiffs of
approximately $4,755,000. There are also allegations of failure to protect from drainage from a
well on adjoining land, trespass, and various other breaches of the mineral leases. The Company
disagrees with plaintiffs contentions and intends to vigorously defend itself against these
claims.
Litigation is subject to substantial uncertainties concerning the outcome of material factual
and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner
and timing of the resolution of these matters and are unable to estimate a range of possible losses
or any minimum loss from such matters.
ITEM 4. (REMOVED AND RESERVED)
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PART II
ITEM
5. MARKET FOR REGISTRANTS COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
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.
High | Low | |||||||
2009 |
||||||||
First Quarter |
$ | 13.73 | $ | 1.55 | ||||
Second Quarter |
9.85 | 3.09 | ||||||
Third Quarter |
18.43 | 5.83 | ||||||
Fourth Quarter |
20.51 | 13.75 | ||||||
2010 |
||||||||
First Quarter |
$ | 19.76 | $ | 14.12 | ||||
Second Quarter |
20.63 | 11.13 | ||||||
Third Quarter |
15.19 | 10.30 | ||||||
Fourth Quarter |
23.31 | 14.21 | ||||||
2011 |
||||||||
First Quarter (through February 22, 2011) |
$ | 27.21 | $ | 21.28 |
On February 22, 2011, the last reported sales price on the New York Stock Exchange Composite
Tape was $26.00 per share. As of that date, there were 406 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 indentures executed in
connection with our 63/4% Senior Subordinated Notes due 2014 and our 85/8% Senior Notes due 2017. 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
On September 24, 2007, our Board of Directors authorized a share repurchase program for an
aggregate amount of up to $100 million. The shares may be repurchased from time to time in the
open market or through privately negotiated transactions. The repurchase program is subject to
business and market conditions, and may be suspended or discontinued at any time. Additionally,
shares were withheld from certain employees to pay taxes associated with the employees vesting of
restricted stock. The following table sets forth information regarding our repurchases or
acquisitions of common stock during the fourth quarter of 2010:
Maximum Number (or | ||||||||||||||||
Total Number of | Approximate Dollar | |||||||||||||||
Shares (or Units) | Value) of Shares | |||||||||||||||
Purchased as Part | (or Units) that May | |||||||||||||||
Total Number of | of Publicly | Yet be Purchased | ||||||||||||||
Shares (or Units) | Average Price Paid | Announced Plans or | Under the Plans or | |||||||||||||
Period | Purchased | per Share (or Unit) | Programs | Programs | ||||||||||||
Share Repurchase Program: |
||||||||||||||||
October 2010 |
| | | |||||||||||||
November 2010 |
| | | |||||||||||||
December 2010 |
| | | |||||||||||||
| | | $ | 92,928,632 | ||||||||||||
Other: |
||||||||||||||||
October 2010 |
378 | (a) | $ | 14.91 | | |||||||||||
November 2010 |
| | | |||||||||||||
December 2010 |
| | | |||||||||||||
378 | $ | 14.91 | | N/A | ||||||||||||
Total |
378 | $ | 14.91 | | ||||||||||||
(a) | Amounts represent shares withheld from employees upon the vesting of restricted stock in order to satisfy the required tax withholding obligations. |
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Equity Compensation Plan Information
Please refer to Item 12 of this Annual Report on Form 10-K for information concerning
securities authorized under our equity compensation plan.
Stock Performance Graph
As required by applicable rules of the Securities and Exchange Commission (SEC), the
performance graph shown below was prepared based upon the following assumptions:
1. | $100 was invested in the Companys Common Stock, the S&P 500 Index and the Peer Groups (as defined below) on December 31, 2005 at $45.53 per share for the Companys Common Stock and at the closing price of the stocks comprising the S&P 500 Index and the Peer Groups, respectively, on such date. | ||
2. | Peer Group investment is weighted based upon the market capitalization of each individual company within the Peer Group at the beginning of the period. | ||
3. | Dividends are reinvested on the ex-dividend dates. |
Measurement Period | S&P 500 | |||||||||||||||
(Fiscal Year Covered) | SGY | 2010 Peer Group | 2009 Peer Group | Index | ||||||||||||
12/31/06
|
77.64 | 99.35 | 98.12 | 115.79 | ||||||||||||
12/31/07
|
103.03 | 110.24 | 104.95 | 122.16 | ||||||||||||
12/31/08
|
24.20 | 41.00 | 39.32 | 76.96 | ||||||||||||
12/31/09
|
39.64 | 68.62 | 65.52 | 97.33 | ||||||||||||
12/31/10
|
48.96 | 105.30 | 102.21 | 111.99 |
The companies that comprised our Peer Group in 2010 were: ATP Oil & Gas Corporation, Carrizo
Oil & Gas, Inc., Energy Partners, Ltd., Energy XXI (Bermuda) Limited, Mariner Energy Inc., McMoRan
Exploration Company, Newfield Exploration Company, PetroQuest Energy, Inc., Swift Energy Company,
and W&T Offshore, Inc. Callon Petroleum Company was removed from the Peer Group and was replaced
by Carrizo Oil & Gas, Inc. in 2010 due to its more comparable size, focus areas and market
capitalization with the other members of the Peer Group.
The information in this Form 10-K appearing under the heading Stock Performance Graph is
being furnished pursuant to Item 2.01(e) of Regulation S-K under the Securities Act of 1933, as
amended, and shall not be deemed to be soliciting material or filed with the SEC or subject to
Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the
liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
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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, 2010. This information is derived from our
Consolidated Financial Statements and the notes thereto. See Item 7. Managements Discussion and
Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and
Supplementary Data. The information included in this table for the years ended December 31, 2009
and 2008 includes the effects of corrections on the previously reported financial statements, as
further discussed in Item 8. Financial Statements and Supplementary Data Note 2.
Year Ended December 31, | ||||||||||||||||||||
2010 | 2009 | 2008 | 2007 | 2006 | ||||||||||||||||
(In thousands, except per share amounts) | ||||||||||||||||||||
Statement of Operations Data: |
||||||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 417,948 | $ | 438,942 | $ | 461,050 | $ | 424,205 | $ | 348,979 | ||||||||||
Gas production |
233,055 | 272,353 | 336,665 | 329,047 | 337,321 | |||||||||||||||
Derivative income, net |
3,265 | 3,061 | 3,327 | | 2,688 | |||||||||||||||
Total operating revenue |
654,268 | 714,356 | 801,042 | 753,252 | 688,988 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
152,326 | 156,786 | 171,107 | 149,702 | 159,043 | |||||||||||||||
Other operational expense |
5,450 | 2,400 | | | | |||||||||||||||
Production taxes |
5,808 | 7,920 | 7,990 | 9,945 | 13,472 | |||||||||||||||
Depreciation, depletion and amortization |
248,201 | 259,639 | 288,384 | 302,739 | 320,696 | |||||||||||||||
Write-down of oil and gas properties |
| 508,989 | 1,324,327 | 8,164 | 510,013 | |||||||||||||||
Goodwill impairment |
| | 465,985 | | | |||||||||||||||
Accretion expense |
34,469 | 39,306 | 17,392 | 17,620 | 12,391 | |||||||||||||||
Salaries, general and administrative expenses |
42,759 | 41,367 | 43,504 | 33,584 | 34,266 | |||||||||||||||
Incentive compensation expense |
5,888 | 6,402 | 2,315 | 5,117 | 4,356 | |||||||||||||||
Impairment of inventory |
129 | 9,398 | | | | |||||||||||||||
Derivative expenses, net |
| | | 666 | | |||||||||||||||
Total operating expenses |
495,030 | 1,032,207 | 2,321,004 | 527,537 | 1,054,237 | |||||||||||||||
Gain on Rocky Mountain Region properties divestiture |
| | | 59,825 | | |||||||||||||||
Income (loss) from operations |
159,238 | (317,851 | ) | (1,519,962 | ) | 285,540 | (365,249 | ) | ||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
12,192 | 21,361 | 13,243 | 32,068 | 35,931 | |||||||||||||||
Interest income |
(1,464 | ) | (528 | ) | (11,250 | ) | (12,135 | ) | (2,524 | ) | ||||||||||
Other income, net |
(6,021 | ) | (3,854 | ) | (5,800 | ) | (5,657 | ) | (4,657 | ) | ||||||||||
Merger expense reimbursement |
| | | | (51,500 | ) | ||||||||||||||
Merger expenses |
| | | | 50,029 | |||||||||||||||
Loss on early extinguishment of debt |
1,820 | | | 844 | | |||||||||||||||
Total other (income) expenses, net |
6,527 | 16,979 | (3,807 | ) | 15,120 | 27,279 | ||||||||||||||
Net income (loss) before income taxes |
152,711 | (334,830 | ) | (1,516,155 | ) | 270,420 | (392,528 | ) | ||||||||||||
Income tax provision (benefit) |
56,282 | (116,559 | ) | (369,146 | ) | 88,984 | (138,306 | ) | ||||||||||||
Net income (loss) |
96,429 | (218,271 | ) | (1,147,009 | ) | 181,436 | (254,222 | ) | ||||||||||||
Net income (loss) attributable to non-controlling
interest |
| 27 | (77 | ) | | | ||||||||||||||
Net income (loss) attributable to Stone Energy Corp. |
$ | 96,429 | ($218,298 | ) | ($1,146,932 | ) | $ | 181,436 | ($254,222 | ) | ||||||||||
Earnings and dividends per common share: |
||||||||||||||||||||
Basic earnings (loss) per share |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | $ | 6.50 | ($9.29 | ) | ||||||||||
Diluted earnings (loss) per share |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | $ | 6.49 | ($9.29 | ) | ||||||||||
Cash dividends declared |
| | | | | |||||||||||||||
Cash Flow Data: |
||||||||||||||||||||
Net cash provided by operating activities |
$ | 424,794 | $ | 507,787 | $ | 522,478 | $ | 465,158 | $ | 399,035 | ||||||||||
Net cash provided by (used in) investing activities |
(374,088 | ) | (316,079 | ) | (1,357,907 | ) | 344,812 | (660,456 | ) | |||||||||||
Net cash provided by (used in) financing activities |
(13,043 | ) | (190,552 | ) | 428,440 | (393,706 | ) | 240,575 | ||||||||||||
Balance Sheet Data (at end of period): |
||||||||||||||||||||
Working capital |
$ | 30,382 | $ | 26,137 | $ | 123,339 | $ | 412,445 | $ | 1,845 | ||||||||||
Oil and gas properties, net |
1,397,809 | 1,185,709 | 1,628,170 | 1,181,312 | 1,784,425 | |||||||||||||||
Total assets |
1,679,090 | 1,454,242 | 2,109,852 | 1,889,603 | 2,128,471 | |||||||||||||||
Long-term debt, less current potion |
575,000 | 575,000 | 825,000 | 400,000 | 797,000 | |||||||||||||||
Stone Energy Corporation stockholders equity |
430,357 | 325,659 | 577,391 | 885,802 | 711,640 |
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ITEM 7. MANAGEMENTS 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, 2010. Our
Consolidated Financial Statements and the notes thereto, which are found elsewhere in this Form
10-K, contain detailed information that should be referred to in conjunction with the following
discussion. See Item 1A. Risk Factors and Item 8. Financial Statements and Supplementary Data
Note 1. Results for 2009 and 2008 have been corrected, as further discussed in Item 8.
Financial Statements and Supplementary Data Note 2. All period to period comparisons are based
upon corrected amounts.
Executive Overview
We are an independent oil and natural gas company engaged in the acquisition, exploration,
exploitation, development and operation of oil and gas properties located primarily in the Gulf of
Mexico (GOM). We have been operating in the Gulf Coast Basin since our incorporation in 1993 and
have established a technical and operational expertise in this area. More recently, we have made
strategic investments in the deep water and deep shelf GOM, which we have targeted as important
exploration areas. We are also active in the Appalachia region, where we have established a
significant acreage position and have development operations in the Marcellus Shale. We have also
targeted several exploratory oil projects in the Rocky Mountain region. See Item 1. Business
Strategy and Operational Overview.
2010 Significant Events.
Public Offering of Senior Notes On January 26, 2010, we completed a public offering of $275
million aggregate principal amount of 85/8% Senior Notes due 2017. The net proceeds from the
offering after deducting underwriting discounts, commissions, fees and expenses totaled $265.3
million. Approximately $202 million of the net proceeds from the offering were used to fund the
tender offer and consent solicitation and redemption of our outstanding 81/4% Senior Subordinated
Notes due 2011. The remaining proceeds were used for general corporate purposes, including the
repayment of borrowings under our bank credit facility.
On November 17, 2010, we completed a public offering of an additional $100 million aggregate
principal amount our 85/8% Senior Notes due 2017. The net proceeds from the offering after deducting
underwriting discounts, commissions, fees and expenses totaled $98.2 million. We used the net
proceeds from the offering for general corporate purposes, which included the repayment of
borrowings under our bank credit facility and the payment of amounts due related to the acquisition
of additional lease acreage in Appalachia.
Deepwater Horizon Explosion and Oil Spill In April 2010, there was a fire and explosion
aboard the Deepwater Horizon drilling platform operated by BP in ultra deep water in the GOM. As a
result of the explosion, ensuing fire and apparent failure of the blowout preventers, the rig sank
and created a catastrophic oil spill that produced widespread economic, environmental and natural
resource damage in the Gulf Coast region. In response to the explosion and spill, the Bureau of
Ocean Energy Management, Regulation and Enforcement (the BOEMRE, formerly the Minerals Management
Service) of the U.S. Department of the Interior issued a Notice to Lessees (NTL) on May 30,
2010, and a revised notice on July 12, 2010, implementing a moratorium on deepwater drilling
activities that effectively halted deepwater drilling of wells. While the moratorium was in place,
the BOEMRE issued a series of NTLs and adopted changes to its regulations to impose a variety of
new measures intended to help prevent a similar disaster in the future. The moratorium was lifted
on October 12, 2010, but offshore operators must now comply with strict new safety and operating
requirements. We are experiencing lengthy delays in the permitting process.
Appalachian Basin (Marcellus Shale Play) During 2010, we substantially increased our
investment in Appalachia with the drilling of fifteen operated horizontal wells and the increase of
our leasehold position to 79,000 net acres.
2011 Outlook.
Our 2011 capital expenditure budget is approximately $425 million which is flat with the
revised 2010 capital expenditure budget and excludes material acquisitions and capitalized
salaries, general and administrative expenses and interest. Approximately 50% 55% of the capital
expenditure budget is expected to be spent on the GOM shelf, including drilling, recompletions,
facilities and abandonment. Approximately 25% of the budget is projected to be spent in
Appalachia, including drilling, facilities and minor land acquisitions. The remaining budget is
for exploration projects in the Rocky Mountain region, the deep shelf, the GOM deep water and other
new venture opportunities.
Known Trends and Uncertainties.
Deepwater Horizon Explosion and Oil Spill The explosion and sinking of the Deepwater Horizon
drilling rig and resulting oil spill has created uncertainties about the impact on our future
operations in the GOM (see Item 1A. Risk Factors). Increased regulation in a number of areas
could disrupt, delay or prohibit future drilling programs and ultimately impact the fair value of
our
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unevaluated properties, a substantial portion of which is in the deep water of the GOM. As of
December 31, 2010, we have approximately $270 million of investments in unevaluated oil and gas
properties that relate to offshore leases, the majority of which are in the deep water GOM. If the
fair value of these investments were to fall below the recorded amounts, the excess would be
transferred to evaluated oil and gas properties thereby affecting the computation of amounts for
depreciation, depletion and amortization and potentially our ceiling test computation. As of
December 31, 2010, the computation of our ceiling test indicated a cushion of approximately $139.5
million.
Asset Retirement Obligations In October 2010, we received notification from the BOEMRE
indicating that certain identified wells and facilities operated by us will need to be retired on a
timing schedule which was accelerated from the timing estimated in calculating liabilities for
asset retirement obligations at December 31, 2009. In February 2011, we submitted an abandonment
plan addressing the identified wells and facilities. The BOEMRE has indicated they will issue a
final order upon review of the plan. During 2010, we increased our asset retirement obligations in
the amount of $54.4 million for the estimated impact of the accelerated timing of the retirement of
these assets and other factors. The final order will ultimately determine the impact on our asset
retirement obligations and could result in an additional upward or downward revision. See Item
1A. Risk Factors.
Hurricanes Since the majority of our production originates in the GOM, we are particularly
vulnerable to the effects of hurricanes on production. Additionally, affordable insurance coverage
for property damage to our facilities for hurricanes is becoming more difficult to obtain. We have
narrowed our insurance coverage to selected properties, increased our deductibles and are
shouldering more hurricane related risk in the environment of rising insurance rates. Significant
hurricane impacts could include reductions and/or deferrals of future oil and natural gas
production and revenues, increased lease operating expenses for evacuations and repairs and
possible acceleration of plugging and abandonment costs.
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 states position that sales of crude oil and natural gas from properties located on the Outer
Continental Shelf (OCS), which are transported through the state of Louisiana, should be sourced
to Louisiana for purposes of computing franchise taxes. We disagree with the states position.
However, if the states position were to be upheld, we could incur additional expense for alleged
underpaid franchise taxes in prior years and higher franchise tax expense in future years. See
Item 3. Legal Proceedings.
Liquidity and Capital Resources
At February 22, 2011, we had $301.9 million of availability under our bank credit facility and
cash on hand of approximately $90.4 million. Our capital expenditure budget for 2011 has been set
at $425 million, which excludes material acquisitions and capitalized salaries, general and
administrative expenses and interest. We intend to finance our capital expenditure budget
primarily with cash flow from operations and borrowings under our bank credit facility. Our bank credit facility matures on July 1, 2011. We are currently exploring alternatives for an extension or renegotiation of our bank credit facility which would extend the due date. If we do
not have sufficient cash flow from operations or availability under our bank credit facility, we
may be forced to reduce our capital expenditures. To the extent that 2011 cash flow from
operations exceeds our estimated 2011 capital expenditures, we may pay down a portion of our
existing debt, expand our capital budget, or invest in the money markets.
There is a significant amount of uncertainty regarding our industry resulting from the
explosion and sinking of the Deepwater Horizon oil rig in the GOM and resulting oil spill. Several
bills have been introduced in Congress which would require us to demonstrate our capabilities for
greater financial responsibility in the event of spills. In addition, we are subject to an
annual evaluation for exemption from supplemental bonding on plugging and abandoning obligations.
It is possible that the resolution of these uncertainties could cause severe impacts on our
liquidity in the event we are required to post additional bonds or letters of credit.
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.
Cash Flow and Working Capital. Net cash flow provided by operating activities totaled $424.8
million during 2010 compared to $507.8 million and $522.5 million in 2009 and 2008, respectively.
Based on our outlook of commodity prices and our estimated production, we expect to fund our 2011
capital expenditures with cash flow provided by operating activities and borrowings under our bank
credit facility.
Net cash flow used in investing activities totaled $374.1 million during 2010, which primarily
represents our investment in oil and natural gas properties of $401.8 million offset by proceeds
from the sale of oil and natural gas properties of $31.6 million. Net cash flow used in investing
activities totaled $316.1 million during 2009, which primarily represents our investment in oil and
natural gas properties. Net cash flow used in investing activities totaled $1.4 billion during the
year ended December 31, 2008,
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which primarily represents cash of $922.7 million used in connection with the acquisition of
Bois dArc Energy, Inc. (Bois dArc) and our investment in oil and natural gas properties of
$446.8 million.
Net cash flow used in financing activities totaled $13.0 million for the year ended December
31, 2010, which primarily represents repayments of borrowings under our bank credit facility of
$175 million, the redemption of our 81/4% Senior Subordinated Notes due 2011 of $200.5 million, net
of proceeds from the public offering of our 85/8% Senior Notes due 2017 of approximately $375 million
less $11.5 million of deferred financing costs. Net cash flow used in financing activities totaled
$190.6 million for the year ended December 31, 2009, which primarily represents repayments of
borrowings under our bank credit facility of $250 million partially offset by proceeds from the
sale of common stock of approximately $60.4 million. Net cash flow provided by financing
activities totaled $428.4 million during the year ended December 31, 2008, which primarily
represents $425 million of borrowings under our bank credit facility in conjunction with our
acquisition of Bois dArc and $15.9 million of proceeds from the exercise of stock options and
vesting of restricted stock.
We had working capital at December 31, 2010 of $30.4 million.
Capital Expenditures. In 2010, additions to oil and gas property costs of $461.7 million
included $127.1 million of lease and property acquisition costs, $20.2 million of capitalized
salaries, general and administrative expenses (inclusive of incentive compensation) and $30.8
million of capitalized interest. These investments were financed by cash flow from operations.
Bank Credit Facility. On August 28, 2008, we entered into an amended and restated revolving
credit facility totaling $700 million, maturing on July 1, 2011, with a syndicated bank group. We
are currently exploring alternatives for an extension or renegotiation of our bank credit facility
which would extend the due date. On January 26, 2010, we completed a public offering of $275
million aggregate principal amount of 85/8% Senior Notes due 2017. In connection with this offering,
our borrowing base was automatically reduced from $425 million to $395 million. On November 17,
2010, we completed a public offering of an additional $100 million aggregate principal amount of
our 85/8% Senior Notes due 2017. Upon completion of this offering, our borrowing base was
automatically reduced from $395 million to $365 million.
At December 31, 2010 and February 22, 2011, we had no outstanding borrowings under our bank
credit facility and letters of credit totaling $63.1 million had been issued under the facility,
leaving $301.9 million of availability under the facility. Our bank credit facility is guaranteed
by our only material subsidiary, Stone Energy Offshore, L.L.C. (Stone Offshore).
The borrowing base under our bank credit facility is redetermined semi-annually, in May and
November, by the lenders taking into consideration the estimated value of our oil and gas
properties and those of our direct and indirect material subsidiaries in accordance with the
lenders customary practices for oil and gas loans. In addition, we and the lenders each have
discretion at any time, but not more than two additional times in any calendar year, to have the
borrowing base redetermined. Our bank credit facility is collateralized by substantially all of
Stones and Stone Offshores assets. Stone and Stone Offshore are required to mortgage, and grant
a security interest in, their oil and gas reserves representing at least 80% of the discounted
present value of the future net cash flows from their oil and gas reserves reviewed in determining
the borrowing base. At Stones option, loans under the credit facility will bear interest at a
rate based on the adjusted London Interbank Offering Rate plus an applicable margin, or a rate
based on the prime rate or Federal funds rate plus an applicable margin.
Under the financial covenants of our credit facility, we must (i) maintain a ratio of
consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding
four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a ratio of EBITDA to
consolidated Net Interest, as defined in the credit agreement, for the preceding four quarterly
periods of not less than 3.0 to 1.0. As of December 31, 2010, our debt to EBITDA Ratio was 1.43 to
1 and our EBITDA to consolidated Net Interest Ratio was approximately 41.72 to 1. In addition, the
credit facility includes 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 but do allow for limited stock
repurchases.
Senior Notes Offering and Redemption of Senior Subordinated Notes. On January 26, 2010, we
completed a public offering of $275 million aggregate principal amount of 85/8% Senior Notes due
2017. The net proceeds from the offering after deducting underwriting discounts, commissions, fees
and expenses totaled $265.3 million. Approximately $202 million of the net proceeds from the
offering were used to fund the tender offer and consent solicitation and redemption of our
outstanding 81/4% Senior Subordinated Notes due 2011. The remaining proceeds were used for general
corporate purposes, including the repayment of borrowings under our bank credit facility.
On November 17, 2010, we completed a public offering of an additional $100 million aggregate
principal amount of our 85/8% Senior Notes due 2017. The net proceeds from the offering after
deducting underwriting discounts, commissions, fees and expenses totaled $98.2 million. We used
the net proceeds from the offering for general corporate purposes, which included the repayment of
borrowings under our bank credit facility and the payment of amounts due related to the acquisition
of additional lease acreage in Appalachia.
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Share Repurchase Program. On September 24, 2007, our Board of Directors authorized a share
repurchase program for an aggregate amount of up to $100 million. The shares may be repurchased
from time to time in the open market or through privately negotiated transactions. The repurchase
program is subject to business and market conditions, and may be suspended or discontinued at any
time. Through December 31, 2010, 300,000 shares had been repurchased under this program at a total
cost of approximately $7.1 million, or an average price of $23.57 per share. No shares were
repurchased during the year ended December 31, 2010.
Hedging. See Item 7A. Quantitative and Qualitative Disclosure About Market Risk Commodity
Price Risk.
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, 2010 (in thousands):
Less than | More than | |||||||||||||||||||
Total | 1 Year | 1-3 Years | 4-5 Years | 5 Years | ||||||||||||||||
Contractual Obligations and Commitments: |
||||||||||||||||||||
8⅝% Senior Notes due 2017 |
$ | 375,000 | $ | | $ | | $ | | $ | 375,000 | ||||||||||
63/4% Senior Subordinated Notes due 2014 |
200,000 | | | 200,000 | | |||||||||||||||
Interest and commitment fees (1) |
250,929 | 46,607 | 91,688 | 77,596 | 35,038 | |||||||||||||||
Asset retirement obligations including
accretion |
639,140 | 42,500 | 101,666 | 145,823 | 349,151 | |||||||||||||||
Rig commitments |
9,850 | 9,850 | | | | |||||||||||||||
Seismic data commitments (2) |
3,578 | 3,578 | | | | |||||||||||||||
Operating lease obligations |
1,879 | 507 | 947 | 425 | | |||||||||||||||
Total Contractual Obligations and Commitments |
$ | 1,480,376 | $ | 103,042 | $ | 194,301 | $ | 423,844 | $ | 759,189 | ||||||||||
(1) | Includes interest on senior notes and senior subordinated notes and 0.5% fee on unused commitments under bank credit facility. | |
(2) | Represents pre-commitments for seismic data purchases. |
Safety Performance
We measure our safety performance based on the total recordable incident rate (TRIR) which
is the number of safety incidents per 200,000 man-hours worked for employees and certain
contractors. All onshore safety incidents are reported to the Occupational Safety and Health
Administration (OSHA) and are tracked on OSHA Form 301. All offshore safety incidents are
reported to the BOEMRE. Our TRIR is provided to the BOEMRE as part of a voluntary program for safety
monitoring in the Gulf of Mexico. Our TRIR for the last three calendar years was as follows:
TRIR | TRIR | |||||||
Year Ended December 31, | Performance | Goal | ||||||
2010 |
0.51 | 0.65 | ||||||
2009 |
0.18 | 0.85 | ||||||
2008 |
0.44 | 0.85 |
Although our safety initiatives do not require a significant capital expenditures commitment,
we expended approximately $800,000 in 2010 in general and administrative costs towards our safety
efforts. Our safety initiative includes formal programs for observation and reporting of at-risk
and safe behavior in and away from the work place, employee awards for results and observations,
employee participation in offsite training programs and internal safety audits. We have an annual
cash incentive compensation plan which includes a safety component based on our annual TRIR.
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Results of Operations
2010 Compared to 2009. 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.
Year Ended December 31, | ||||||||||||||||
2010 | 2009 | Variance | % Change | |||||||||||||
Production: |
||||||||||||||||
Oil (MBbls) |
5,714 | 6,207 | (493 | ) | (8 | %) | ||||||||||
Natural gas (MMcf) |
41,937 | 41,335 | 602 | 1 | % | |||||||||||
Oil and natural gas (MMcfe) |
76,221 | 78,577 | (2,356 | ) | (3 | %) | ||||||||||
Average prices: (1) |
||||||||||||||||
Oil (per Bbl) |
$ | 73.14 | $ | 70.72 | $ | 2.42 | 3 | % | ||||||||
Natural gas (per Mcf) |
5.56 | 6.59 | (1.03 | ) | (16 | %) | ||||||||||
Oil and natural gas (per Mcfe) |
8.54 | 9.05 | (0.51 | ) | (6 | %) | ||||||||||
Expenses (per Mcfe): |
||||||||||||||||
Lease operating expenses |
$ | 2.00 | $ | 2.00 | $ | | 0 | % | ||||||||
Salaries, general and administrative
expenses (2) |
0.56 | 0.53 | 0.03 | 6 | % | |||||||||||
DD&A expense on oil and gas properties |
3.18 | 3.23 | (0.05 | ) | (2 | %) | ||||||||||
Estimated Proved Reserves at December 31: |
||||||||||||||||
Oil (MBbls) |
33,203 | 32,336 | 867 | 3 | % | |||||||||||
Natural gas (MMcf) |
274,705 | 216,694 | 58,011 | 27 | % | |||||||||||
Oil and natural gas (MMcfe) |
473,923 | 410,711 | 63,212 | 15 | % |
(1) | Includes the settlement of effective hedging contracts. | |
(2) | Exclusive of incentive compensation expense. |
For the year ended December 31, 2010, we reported net income totaling $96.4 million, or $1.99
per share, compared to a net loss for the year ended December 31, 2009 of $218.3 million, or $4.97
per share. All per share amounts are on a diluted basis.
We follow the full cost method of accounting for oil and gas properties. At March 31, 2009
and December 31, 2009, we recognized ceiling test write-downs of our oil and gas properties (United
States) totaling $509.0 million ($330.8 million after taxes).
The variance in annual results was also due to the following components:
Production. Production volumes during the year ended December 31, 2010 totaled 5,714,000
barrels of oil and 41.9 Bcf of natural gas compared to 6,207,000 barrels of oil and 41.3 Bcf of
natural gas produced during the year ended December 31, 2009, a decrease on a gas equivalent basis
of 2.4 Bcfe. Production deferrals due to hurricanes during the year ended December 31, 2009
amounted to 11.8 Bcfe. Without the effects of the hurricane production deferrals, year to year
total production volumes decreased approximately 14.2 Bcfe, primarily the result of natural
production declines in the GOM.
Prices. Prices realized during the year ended December 31, 2010 averaged $73.14 per barrel of
oil and $5.56 per Mcf of natural gas, or 6% lower, on an Mcfe basis, than 2009 average realized
prices of $70.72 per barrel of oil and $6.59 per Mcf of natural gas. All unit pricing amounts
include the settlement of effective hedging contracts.
We enter into various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. During the years ended December 31, 2010 and 2009, our effective
hedging transactions increased our average realized natural gas price by $0.92 per Mcf and $2.45
per Mcf, respectively. Average realized oil prices were decreased during the year ended December
31, 2010 by $5.08 per barrel as a result of effective hedging transactions. During the year ended
December 31, 2009, our effective hedging transactions increased our average realized oil price by
$9.95 per barrel.
Income. Oil and natural gas revenue decreased 8% to $651.0 million during the year ended
December 31, 2010 from $711.3 million during the year ended December 31, 2009. The decrease was
primarily due to a 6% decrease in average realized prices on a gas equivalent basis along with a 3%
decrease in oil and natural gas production volumes.
Derivative Income/Expense. During the years ended December 31, 2010 and 2009, certain of our
derivative contracts were determined to be partially ineffective because of differences in the
relationship between the fixed price in the derivative contract and actual prices realized. Net
derivative income for the year ended December 31, 2010, totaled $3.3 million, consisting of $3.0
million of cash settlements on the ineffective portion of derivative contracts, plus $0.3 million
of changes in the fair market value of
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the ineffective portion of derivative contracts. Net
derivative income for the year ended December 31, 2009, totaled $3.1 million, consisting of $8.2
million of cash settlements on the ineffective portion of derivative contracts, less $5.1 million
of changes in the fair market value of the ineffective portion of derivative contracts.
Expenses. Lease operating expenses for the years ended December 31, 2010 and 2009 totaled
$152.3 million and $156.8 million, respectively. Lease operating expenses during the year ended
December 31, 2009 included approximately $9.3 million of repairs in excess of estimated insurance
recoveries related to damage from Hurricanes Gustav and Ike. On a unit of production basis, lease
operating expenses were $2.00 per Mcfe for each of the years ended December 31, 2010 and 2009.
For the year ended December 31, 2010, other operational expenses of $5.5 million included a
$2.2 million loss on the sale of non-dedicated tubular inventory and a total of $3.3 million of
charges related to a delay in the drilling of the second well in our Amberjack drilling program as
a result of the deep water drilling moratorium. The other operational expense charge of $2.4
million for the year ended December 31, 2009 related to the cancellation of a drilling contract
based on declining commodity prices and the economic environment at that time.
Depreciation, depletion and amortization (DD&A) expense on oil and gas properties for the
year ended December 31, 2010 totaled $242.7 million, or $3.18 per Mcfe, compared to DD&A expense of
$253.8 million, or $3.23 per Mcfe in the year ended December 31, 2009.
For the years ended December 31, 2010 and 2009, accretion expense totaled $34.5 million and
$39.3 million, respectively. The decrease is primarily due to a decrease in our credit adjusted
risk free rate at December 31, 2009.
During the years ended December 31, 2010 and 2009, SG&A expenses (exclusive of incentive
compensation) totaled $42.8 million and $41.4 million, respectively.
For the years ended December 31, 2010 and 2009, incentive compensation expense totaled $5.9
million and $6.4 million, respectively. These amounts related to incentive compensation bonuses
calculated based on the achievement of certain strategic objectives for each year.
The impairment of inventory for the years ended December 31, 2010 and 2009 totaling $0.1
million and $9.4 million, respectively, related to the write-down of our tubular inventory. These
charges were the result of the market value of these tubular goods falling below historical cost.
We consider only tubular goods not committed to capital projects to be inventory items.
Interest expense for the year ended December 31, 2010 totaled $12.2 million, net of $30.8
million of capitalized interest, compared to interest expense of $21.4 million, net of $25.6
million of capitalized interest, during the year ended December 31, 2009. The decrease in interest
cost is primarily the result of a decrease in outstanding borrowings under our bank credit
facility.
Our effective income tax rate increased during the year ended December 31, 2010 due
to the increased impact of state jurisdictions on our overall rate.
Asset Retirement Obligations. In October 2010, we received notification from the BOEMRE
indicating that certain identified wells and facilities operated by us will need to be retired on a
timing schedule, which was accelerated from the timing estimated in calculating liabilities for
asset retirement obligations at December 31, 2009. During 2010, we increased our asset retirement
obligations in the amount of $54.4 million for the estimated impact of the accelerated timing of
the retirement of these assets as well as other factors.
Reserves. At December 31, 2010, our estimated proved oil and natural gas reserves totaled
473.9 Bcfe, compared to December 31, 2009 reserves of 410.7 Bcfe. Estimated proved natural gas
reserves totaled 274.7 Bcf and estimated proved oil reserves totaled 33.2 MMBbls at the end of
2010. The increase in estimated proved reserves from year-end 2009 was primarily due to successful
drilling operations in Appalachia and the GOM shelf as well as positive pricing revisions. The
reserve estimates at December 31, 2010 were prepared by Netherland, Sewell & Associates, Inc.
(NSA) in accordance with guidelines established by the SEC.
Our standardized measure of discounted future net cash flows was $957.6 million and $615.0
million at December 31, 2010 and 2009, respectively. As required by the SEC, we determined this
estimate of future net cash flows using a 12-month average price, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month of our fiscal year. The
12-month average oil and gas prices net of differentials on all of our properties used in
determining this amount, excluding the effects of hedges in place at year-end, were $77.68 per
barrel and $4.46 per mcf for 2010 and $58.95 per barrel and $3.49 per Mcf for 2009. You should
not assume that these estimates of future net cash flows represent the fair value of our estimated
oil and natural gas reserves.
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2009 Compared to 2008. 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.
Year Ended December 31, | ||||||||||||||||
2009 | 2008 | Variance | % Change | |||||||||||||
Production: |
||||||||||||||||
Oil (MBbls) |
6,207 | 4,916 | 1,291 | 26 | % | |||||||||||
Natural gas (MMcf) |
41,335 | 34,409 | 6,926 | 20 | % | |||||||||||
Oil and natural gas (MMcfe) |
78,577 | 63,903 | 14,674 | 23 | % | |||||||||||
Average prices: (1) |
||||||||||||||||
Oil (per Bbl) |
$ | 70.72 | $ | 93.79 | ($23.07 | ) | (25 | %) | ||||||||
Natural gas (per Mcf) |
6.59 | 9.78 | (3.19 | ) | (33 | %) | ||||||||||
Oil and natural gas (per Mcfe) |
9.05 | 12.48 | (3.43 | ) | (27 | %) | ||||||||||
Expenses (per Mcfe): |
||||||||||||||||
Lease operating expenses |
$ | 2.00 | $ | 2.68 | ($0.68 | ) | (25 | %) | ||||||||
Salaries, general and administrative
expenses (2) |
0.53 | 0.68 | (0.15 | ) | (22 | %) | ||||||||||
DD&A expense on oil and gas properties |
3.23 | 4.45 | (1.22 | ) | (27 | %) | ||||||||||
Estimated Proved Reserves at December 31: |
||||||||||||||||
Oil (MBbls) |
32,336 | 36,564 | (4,228 | ) | (12 | %) | ||||||||||
Natural gas (MMcf) |
216,694 | 299,554 | (82,860 | ) | (28 | %) | ||||||||||
Oil and natural gas (MMcfe) |
410,711 | 518,935 | (108,224 | ) | (21 | %) |
(1) | Includes the settlement of effective hedging contracts. | |
(2) | Exclusive of incentive compensation expense. |
For the year ended December 31, 2009, we reported a net loss totaling $218.3 million, or $4.97
per share, compared to a net loss for the year ended December 31, 2008 of $1,146.9 million, or
$35.89 per share. All per share amounts are on a diluted basis. On August 28, 2008, we completed
our acquisition of Bois dArc. The revenues and expenses associated with Bois dArc have been
included in Stones consolidated financial statements since August 28, 2008.
We follow the full cost method of accounting for oil and gas properties. At March 31, 2009
and December 31, 2009, we recognized ceiling test write-downs of our oil and gas properties (United
States) totaling $509.0 million ($330.8 million after taxes). At the end of 2008, we recognized a
ceiling test write-down of our oil and gas properties (United States and China) totaling $1,324.3
million ($860.8 million after taxes). The write-downs did not impact our cash flow from operations
but did reduce net income and stockholders equity. At December 31, 2008, approximately $157.8
million of unevaluated costs were determined to be impaired and were reclassified to proved oil and
gas properties and included in our ceiling test computation.
The 2008 net loss included a goodwill impairment charge totaling $466.0 million (no tax
effect). The goodwill impairment charge did not impact our cash flow from operations but did
reduce net income and stockholders equity. The goodwill related to our acquisition of Bois dArc.
The variance in annual results was also due to the following components:
Production. Production volumes during the year ended December 31, 2009 totaled 6,207,000
barrels of oil and 41.3 Bcf of natural gas compared to 4,916,000 barrels of oil and 34.4 Bcf of
natural gas produced during the year ended December 31, 2008, an increase on a gas equivalent basis
of 14.7 Bcfe. Production rates were negatively impacted by Gulf Coast shut-ins due to Hurricanes
Gustav and Ike during 2009 and 2008, amounting to volumes of approximately 11.8 Bcfe and 18.1 Bcfe,
respectively. Without the effects of the hurricane production deferrals, year to year total
production volumes increased approximately 8.4 Bcfe, primarily the result of a full year of
production associated with the Bois dArc properties in 2009.
Prices. Prices realized during the year ended December 31, 2009 averaged $70.72 per barrel of
oil and $6.59 per Mcf of natural gas, or 27% lower, on an Mcfe basis, than 2008 average realized
prices of $93.79 per barrel of oil and $9.78 per Mcf of natural gas. All unit pricing amounts
include the settlement of effective hedging contracts.
We enter into various hedging contracts in order to reduce our exposure to the possibility of
declining oil and gas prices. During the years ended December 31, 2009 and 2008, our effective
hedging transactions increased our average realized natural gas price by $2.45 per Mcf and $0.44
per Mcf, respectively. During the year ended December 31, 2009, our effective hedging transactions
increased our average realized oil price by $9.95 per barrel. Average realized oil prices were
decreased during the year ended December 31, 2008 by $7.01 per barrel as a result of effective
hedging transactions.
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Income. Oil and natural gas revenue decreased 11% to $711.3 million during the year ended
December 31, 2009 from $797.7 million during the year ended December 31, 2008. The decrease was
due to a 27% decrease in average realized prices on a gas equivalent basis, partially offset by oil
and natural gas revenue associated with the Bois dArc properties totaling $169.8 million for the
full year of 2009. Oil and natural gas revenue related to the properties acquired from Bois dArc
totaled $47.3 million from August 28, 2008 through December 31, 2008.
Interest income totaled $0.5 million during the year ended December 31, 2009 compared to $11.3
million during the year ended December 31, 2008. The decrease in interest income was the result of
lower interest rates and a decrease in our cash balances during the periods after the acquisition
of Bois dArc.
Derivative Income/Expense. During 2009, certain of our derivative contracts were determined
to be partially ineffective because of differences in the relationship between the fixed price in
the derivative contract and actual prices realized. Net derivative income for the year ended
December 31, 2009, totaled $3.1 million, consisting of $8.2 million of cash settlements on the
ineffective portion of derivative contracts, less $5.1 million of changes in the fair market value
of the ineffective portion of derivative contracts. During 2008, certain of our derivative
contracts were determined to be partially ineffective because of differences in the relationship
between the fixed price in the derivative contract and actual prices realized. During the second
half of 2008, as a result of extended shut-ins of production after Hurricanes Gustav and Ike, our
September 2008 crude oil and natural gas production levels were below the volumes that we had
hedged. Consequently, some of our crude oil and natural gas hedges for September 2008 were deemed
to be ineffective. Net derivative income for the year ended December 31, 2008, totaled $3.3
million, consisting of $0.7 million of cash settlements on the ineffective derivative contracts,
$4.5 million of changes in the fair market value of the ineffective portion of derivative
contracts, less $1.9 million of amortization of the cost of puts.
Expenses. Lease operating expenses for the year ended December 31, 2009 totaled $156.8
million, compared to $171.1 million incurred during the year ended December 31, 2008. The decrease
in lease operating expenses was the result of a decline in major maintenance expenses. Partially
offsetting the decrease are lease operating expenses from the Bois dArc properties for a full year
in 2009 compared to a partial year in 2008. Included in lease operating expenses from August 28,
2008 through December 31, 2008 are $28.6 million of expenses for the properties acquired from Bois
dArc. For the year ended December 31, 2009, lease operating expenses for the properties acquired
from Bois dArc totaled $62.5 million.
The other operational expense charge of $2.4 million for the year ended December 31, 2009
related to the cancellation of a drilling contract.
DD&A expense on oil and gas properties for the year ended December 31, 2009 totaled $253.8
million, or $3.23 per Mcfe, compared to DD&A expense of $284.7 million, or $4.45 per Mcfe in the
year ended December 31, 2008. The overall decrease in DD&A from 2008 was primarily due to the 2008
year-end and first quarter 2009 ceiling test write-downs, which reduced the carrying value of the
full cost pool for our oil and gas properties.
For the years ended December 31, 2009 and 2008, accretion expense totaled $39.3 million and
$17.4 million, respectively. Due to falling commodity prices and hurricanes, the timing on a
substantial portion of our asset retirement obligations was revised in the fourth quarter of 2008
leading to a redetermination of the present value of these obligations. In this redetermination,
our credit adjusted risk free interest rate was increased to account for current credit conditions,
resulting in a material increase in accretion expense in 2009. Also contributing to the increase
was the addition of liabilities associated with properties acquired from Bois dArc.
During the years ended December 31, 2009 and 2008, SG&A expenses (exclusive of incentive
compensation) totaled $41.4 million and $43.5 million, respectively.
For the years ended December 31, 2009 and 2008, incentive compensation expense totaled $6.4
million and $2.3 million, respectively. These amounts related to incentive compensation bonuses
calculated based on the achievement of certain strategic objectives for each year.
The impairment of inventory for the year ended December 31, 2009 totaling $9.4 million related
to the write-down of our tubular inventory. This charge was the result of the market value of
these tubular goods falling below historical cost. We consider only tubular goods not committed to
capital projects to be inventory items.
Interest expense for the year ended December 31, 2009 totaled $21.4 million, net of $25.6
million of capitalized interest, compared to interest expense of $13.2 million, net of $26.4
million of capitalized interest, during the year ended December 31, 2008. The increase in interest
cost in 2009 was primarily the result of an increase in outstanding borrowings under our bank
credit facility in the first half of 2009.
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We estimate that we incurred $30.4 million of current federal income tax expense for calendar
year 2009. This was largely due to a reclassification between current and deferred income tax
expense related to a proposed IRS audit adjustment with respect to the timing of certain
deductions. We had an $11.1 million current income tax payable at December 31, 2009.
Asset Retirement Obligations. Primarily due to changes in estimated reserve lives, the timing
on a substantial portion of our asset retirement obligations was revised in the fourth quarter of
2009 leading to a redetermination of the present value of these obligations. In this
redetermination, our credit adjusted risk free rate was decreased to account for current credit
conditions contributing to a significant upward revision of our asset retirement obligations of
$76.4 million at December 31, 2009.
Reserves. At December 31, 2009, our estimated proved oil and gas reserves totaled 410.7 Bcfe,
compared to December 31, 2008 reserves of 518.9 Bcfe. Estimated proved natural gas reserves
totaled 216.7 Bcf and estimated proved oil reserves totaled 32.3 MMBbls at the end of 2009. The
decline in estimated proved reserves from year-end 2008 was due to production, negative commodity
pricing revisions and other revisions to comply with the new SEC rules regarding oil and gas
reserve estimation. The reserve estimates at December 31, 2009 were prepared by NSA in accordance
with guidelines established by the SEC.
Our standardized measure of discounted future net cash flows was $615.0 million at December
31, 2009. As required by the SEC, at December 31, 2009, we determined this estimate of future net
cash flows using a 12-month average price, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month of our fiscal year. The 12-month average oil and gas
prices net of differentials on all of our properties used in determining this amount, excluding the
effects of hedges in place at year-end, were $58.95 per barrel and $3.49 per Mcf for 2009. Our
standardized measure of discounted future net cash flows was $793.1 million at December 31, 2008
using a single-day, period-end price as required under the old SEC guidelines. Prior to the
issuance of the SECs new rule, Modernization of Oil and Gas Reporting, estimates of future net
cash flows were based on market prices for oil and gas on the last day of the fiscal period. The
average year-end oil and gas prices net of differentials on all of our properties used in
determining our standardized measure of discounted future net cash flows at December 31, 2008,
excluding the effects of hedges in place at year-end, were $39.70 per barrel and $5.87 per Mcf for
2008. You should not assume that these estimates of future net cash flows represent the fair value
of our estimated oil and natural gas reserves.
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 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
Fair Value Measurements. U.S. Generally Accepted Accounting Principles (GAAP), as codified,
establish a framework for measuring fair value and require certain disclosures about fair value
measurements. There is an established fair value hierarchy which has three levels based on the
reliability of the inputs used to determine the fair value. These levels include: Level 1, defined
as inputs such as unadjusted quoted prices in active markets for identical assets or liabilities;
Level 2, defined as inputs other than quoted prices in active markets that are either directly or
indirectly observable; and Level 3, defined as unobservable inputs for use when little or no market
data exists, therefore requiring an entity to develop its own assumptions.
As of December 31, 2010, we held certain financial assets and liabilities that are required to
be measured at fair value on a recurring basis, including our commodity derivative instruments and
our investments in money market funds. Additionally, fair value concepts were applied in the
recording of assets and liabilities acquired in the Bois dArc transaction.
Business Combinations and Goodwill. Our 2008 acquisition of Bois dArc was accounted for
using the purchase method of accounting for business combinations. Fair value concepts were used
in determining the cost of the acquired entity and allocating that cost to assets acquired
(including goodwill) and liabilities assumed. Goodwill is required to be tested for impairment at
least annually. There is a two-step methodology for determining impairment that begins with an
estimation of the fair value of the reporting unit. The first step is a screen for potential
impairment, and the second step measures the amount of impairment, if any. This authoritative
guidance provided the framework for the determination of our goodwill impairment at December 31,
2008.
Asset Retirement Obligations. We are required 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 propertys useful life. The guidance regarding asset retirement
obligations requires the use of managements estimates with respect to future abandonment costs,
inflation, market risk premiums, useful life and cost of
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capital. 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 follow 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 and general and administrative costs (less any
reimbursements for such costs) and interest 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 units of
production (UOP) method. Under the UOP method, the quarterly provision for DD&A is computed by
dividing production volumes for the period by the total proved reserves as of the beginning of the
period (beginning of the period reserves being determined by adding back production to end of the
period reserves), and applying the respective rate to the net cost of proved oil and gas
properties, including future development costs.
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. We
also capitalize the portion of salaries, general and administrative expenses that are attributable
to our acquisition, exploration and development activities.
U.S. GAAP allows 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 (excluding cash
flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas
properties 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. Historically, estimated future net cash
flows from proved reserves were calculated based on period-end hedge adjusted commodity prices. In
December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which adopted
revisions to the SECs oil and gas reporting requirements. The revisions replaced the single-day
year-end pricing with a twelve-month average pricing assumption. The changes to prices used in
reserves calculations under the new rule are used in both disclosures and accounting impairment
tests. In January 2010, the Financial Accounting Standards Board (FASB) issued its final
standard on oil and gas reserve estimation and disclosures aligning its requirements with the SECs
final rule. The new rules were considered a change in accounting principle that is inseparable from
a change in accounting estimate, which did not require retroactive revision.
Derivative Instruments and Hedging Activities. 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.
Use of Estimates. The preparation of financial statements in conformity with U.S. GAAP
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:
| remaining proved oil and gas reserve volumes and the timing of their production; | ||
| estimated costs to develop and produce proved oil and gas reserves; | ||
| accruals of exploration costs, development costs, operating costs and production revenue; | ||
| timing and future costs to abandon our oil and gas properties; | ||
| the effectiveness and estimated fair value of derivative positions; | ||
| classification of unevaluated property costs; | ||
| capitalized general and administrative costs and interest; |
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| insurance recoveries related to hurricanes; | ||
| estimates of fair value in business combinations; | ||
| goodwill impairment testing and measurement; | ||
| current income taxes; and | ||
| contingencies. |
For a more complete discussion of our accounting policies and procedures see our Notes to
Consolidated Financial Statements beginning on page F-8.
Recent Accounting Developments
Fair Value Measurements and Disclosures. Accounting Standards Update (ASU) 2010-06 was
issued in January 2010 to improve disclosures about fair value measurements by requiring a greater
level of disaggregated information, more robust disclosures about valuation techniques and inputs
to fair value measurements, information about significant transfers between the three levels in the
fair value hierarchy, and separate presentation of information about purchases, sales, issuances,
and settlements on a gross basis rather than as one net number. The guidance provided in ASU
2010-06 became effective for interim and annual periods beginning after December 15, 2009, except
for the disclosures about purchases, sales, issuances, and settlements in the roll forward of
activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years
beginning after December 15, 2010, and for interim periods within those fiscal years. We had no
Level 3 fair value measurements during the year ended December 31, 2010.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk. Our major market risk exposure continues to be the pricing applicable
to our oil and natural gas production. Our revenues, profitability and future rate of growth
depend substantially upon the market prices of oil and natural gas, which fluctuate widely. Oil
and natural gas price declines and volatility could adversely affect our revenues, cash flows and
profitability. Price volatility is expected to continue. 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 2010 would have decreased approximately $0.83 per share. In order to manage
our exposure to oil and natural gas price declines, we occasionally enter into oil and natural 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.
We have entered into fixed-price swaps with various counterparties for a portion of our
expected 2011, 2012 and 2013 oil and natural gas production from the Gulf Coast Basin. The
fixed-price oil swap settlements are based upon an average of the New York Mercantile Exchange
(NYMEX) closing price for West Texas Intermediate (WTI) during the entire calendar month. Some
of our fixed-price gas swap settlements are based on an average of NYMEX prices for the last three
days of a respective month and some are based on the NYMEX price for the last day of a respective
month. Swaps typically provide for monthly payments by us if prices rise above the swap price or
to us if prices fall below the swap price. Our outstanding fixed-price swap contracts are with
J.P. Morgan Chase Bank, N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, The Bank
of Nova Scotia and Natixis.
The following table illustrates our hedging positions for calendar years 2011, 2012 and 2013
as of February 22, 2011:
Fixed-Price Swaps | ||||||||||||||||
Natural Gas | Oil | |||||||||||||||
Daily | Daily | |||||||||||||||
Volume | Swap | Volume | Swap | |||||||||||||
(MMBtus/d) | Price | (Bbls/d) | Price | |||||||||||||
2011 |
10,000 | (a) | $ | 4.565 | 1,000 | $ | 70.05 | |||||||||
2011 |
20,000 | 5.200 | 1,000 | 78.20 | ||||||||||||
2011 |
10,000 | 6.830 | 1,000 | 80.20 | ||||||||||||
2011 |
1,000 | 83.00 | ||||||||||||||
2011 |
1,000 | 83.05 | ||||||||||||||
2011 |
1,000 | (b) | 85.20 | |||||||||||||
2011 |
1,000 | 85.25 | ||||||||||||||
2011 |
1,000 | 89.00 | ||||||||||||||
2011 |
1,000 | (c) | 97.75 | |||||||||||||
2012 |
10,000 | 5.035 | 1,000 | 90.30 | ||||||||||||
2012 |
10,000 | 5.040 | 1,000 | 90.41 | ||||||||||||
2012 |
1,000 | 90.45 | ||||||||||||||
2012 |
1,000 | 95.50 | ||||||||||||||
2012 |
1,000 | 97.60 | ||||||||||||||
2012 |
1,000 | 100.00 | ||||||||||||||
2013 |
1,000 | 97.15 |
(a) | February December | |
(b) | January June | |
(c) | July December |
We believe these positions have hedged approximately 40% of our estimated 2011 production from
estimated proved reserves, 28% of our estimated 2012 production from estimated proved reserves and
4% of our estimated 2013 production from estimated proved reserves.
Interest Rate Risk. We had long-term debt outstanding of $575 million at December 31, 2010,
all of which bears interest at fixed rates. The $575 million of fixed-rate debt is comprised of
$375 million of 85/8% Senior Notes due 2017 and $200 million of 63/4% Senior Subordinated Notes due
2014. During the year ended December 31, 2010, we had outstanding debt under our bank credit
facility at various times, bearing interest at a floating rate. We currently have 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 2010 our interest expense, net of capitalization,
would have increased approximately $0.3 million, net of taxes, resulting in a $0.01 per diluted
share decrease in our reported net income.
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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.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have established disclosure controls and procedures to ensure that material information
relating to Stone Energy Corporation and its consolidated subsidiaries (collectively Stone) is
made known to the officers who certify Stones financial reports and the Board of Directors.
Disclosure controls and procedures, as defined in the rules and regulations of the Securities
Exchange Act of 1934, means controls and other procedures of an issuer that are designed to ensure
that information required to be disclosed by the issuer in the reports that it files or submits
under the Act (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the
time periods specified in the Commissions rules and forms. Disclosure controls and procedures
include, without limitation, controls and procedures designed to ensure that information required
to be disclosed by an issuer in the reports that it files or submits under the Act is accumulated
and communicated to the issuers management, including its principal executive and principal
financial officers, or persons performing similar functions, as appropriate to allow timely
decisions regarding required disclosure. There are inherent limitations to the effectiveness of
any system of disclosure controls and procedures, including the possibility of human error and the
circumvention or overriding of controls and procedures. Accordingly, even effective disclosure
controls and procedures can only provide reasonable assurance of achieving their control
objectives.
Our principal executive officer and our principal financial officer, with the participation of
other members of our senior management, reviewed and evaluated the effectiveness of Stones
disclosure controls and procedures as of December 31, 2010. Based on this evaluation, our
principal executive officer and principal financial officer believe that as of the end of the year
ended December 31, 2010:
| Stones disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SECs rules and forms; and | ||
| Stones disclosure controls and procedures were effective to ensure that information required to be disclosed by Stone in the reports that it files or submits under the Securities Exchange Act of 1934 was accumulated and communicated to Stones management, including Stones principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure. |
Changes in Internal Control Over Financial Reporting
There has not been any change in our internal control over financial reporting that occurred
during the quarter ended December 31, 2010 that has materially affected, or is reasonably likely to
materially affect, our internal control over financial reporting.
Managements Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined by the Securities Exchange Act of 1934, as amended.
Under the supervision and with the participation of our management, including the principal
executive officer and principal financial officer, we conducted an evaluation of the effectiveness
of our internal control over financial reporting as of December 31, 2010. In making this
assessment, we used the criteria established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation,
we have concluded that our internal controls over financial reporting were effective as of December
31, 2010. Ernst and Young LLP, an independent public accounting firm, has issued their report on
the Companys internal control over financial reporting as of December 31, 2010.
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders and Board of Directors
Stone Energy Corporation
Stone Energy Corporation
We have audited Stone Energy Corporations internal control over financial reporting as of December
31, 2010, based on criteria established in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Stone Energy
Corporations management is responsible for maintaining effective internal control over financial
reporting, and for its assessment of the effectiveness of internal control over financial reporting
included in the accompanying Managements Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Companys 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, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
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 companys 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
companys 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 companys 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.
In our opinion, Stone Energy Corporation maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2010, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated balance sheets of Stone Energy Corporation as of December
31, 2010 and 2009, and the related consolidated statements of operations, cash flows, changes in
stockholders equity, and comprehensive income for each of the three years in the period ended
December 31, 2010 and our report dated March 3, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP |
New Orleans, Louisiana
March 3, 2011
March 3, 2011
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ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The following table sets forth information regarding the names, ages (as of February 22, 2011)
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.
Name | Age | Position | ||||
David H. Welch
|
62 | President, Chief Executive Officer and Director | ||||
Kenneth H. Beer
|
53 | Executive Vice President and Chief Financial Officer | ||||
Andrew L. Gates, III
|
63 | Senior Vice President, General Counsel and Secretary | ||||
E. J. Louviere
|
62 | Senior Vice President Land | ||||
John R. Pantaleo
|
53 | Vice President Gulf of Mexico | ||||
J. Kent Pierret
|
55 | Senior Vice President, Chief Accounting Officer and Treasurer | ||||
Richard L. Smith
|
52 | Executive Vice President Exploration and Business Development | ||||
Richard L. Toothman, Jr.
|
46 | Vice President Appalachia | ||||
Jerome F. Wenzel, Jr.
|
58 | Executive Vice President Operations | ||||
Florence M. Ziegler
|
50 | Vice President Human Resources and Administration |
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.
Kenneth H. Beer was named Executive Vice President and Chief Financial Officer in January
2011. Previously, he served as Senior Vice President and Chief Financial Officer since August
2005. Prior to joining Stone, he 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
was 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.
John R. Pantaleo was named Vice President Gulf of Mexico in August 2010. He previously
served as Manager Drilling & Completions since joining Stone in February 2005. Prior to joining
Stone, he worked for ENI Petroleum for approximately 2-1/2 years as Manager of Well Operations. He
also spent approximately 23 years with Amoco/BP America, Inc. where he held a number of positions
including Deepwater Drilling Manager, Strategic Staffing Manager and Manager Rigs and Contracts.
J. Kent Pierret was named Senior Vice President Chief Accounting Officer and Treasurer in
April 2004. Mr. Pierret previously served as Vice President and Chief Accounting Officer since
June 1999 and Treasurer since February 2004.
Richard L. Smith was named Executive Vice President, Exploration and Business Development in
January 2011. Previously, he served as Senior Vice President Exploration and Business
Development since January 2009 and Vice President Exploration and Business Development from June
2007 through January 2009. Prior to joining Stone, Mr. Smith served as the General
Manager of Deepwater Gulf of Mexico Exploration of Dominion E&P Inc. from 2003 to 2007. Mr. Smith
has also worked for Exxon Corporation and Texaco USA with experience in deep water, shelf, onshore,
and international projects.
Richard L. Toothman, Jr. was named Vice President Appalachia in May 2010. Prior to joining
Stone in May 2010, he was employed by CNX Gas Company in Bluefield, Virginia since August 2005
where he held two executive positions, VP Engineering and Technical Services and VP International
Business. He also worked for Consol Energy and Conoco in prior years.
Jerome F. Wenzel, Jr. was named Executive Vice President, Operations in January 2011.
Previously, he served as Senior Vice President Operations/Exploitation since September 2005. He
joined Stone in October 2004 as Vice President Production and
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Drilling. Prior to
joining Stone, Mr. Wenzel held managerial and executive positions with Amoco and BP America, Inc.
over a 29 year career.
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.
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 2011 Annual Meeting of Stockholders to be held on May 20,
2011. 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 2011 Annual Meeting of Stockholders to be held
on May 20, 2011.
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 2011 Annual Meeting of Stockholders to be held
on May 20, 2011.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required by Item 13 is incorporated herein by reference to such information as
set forth in our definitive Proxy Statement for our 2011 Annual Meeting of Stockholders to be held
on May 20, 2011.
ITEM 14. PRINCIPAL ACCOUNTING 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 2011 Annual Meeting of Stockholders to be held
on May 20, 2011.
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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
page F-1 of this Form 10-K:
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheet as of December 31, 2010 and 2009
Consolidated Statement of Operations for the three years in the period ended December 31, 2010
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2010
Consolidated Statement of Changes in Stockholders Equity for the three years in the period ended December 31, 2010
Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2010
Notes to the Consolidated Financial Statements
Consolidated Balance Sheet as of December 31, 2010 and 2009
Consolidated Statement of Operations for the three years in the period ended December 31, 2010
Consolidated Statement of Cash Flows for the three years in the period ended December 31, 2010
Consolidated Statement of Changes in Stockholders Equity for the three years in the period ended December 31, 2010
Consolidated Statement of Comprehensive Income for the three years in the period ended December 31, 2010
Notes to the Consolidated Financial Statements
2. Financial Statement Schedules:
All schedules are omitted because the required information is inapplicable or the information is
presented in the Financial Statements or the notes thereto.
3. Exhibits:
3.1
|
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 (Registration No. 33-62362)). | |
3.2
|
Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed February 7, 2001). | |
3.3
|
Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)). | |
4.1
|
Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed on December 15, 2004.) | |
4.2
|
First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)). | |
4.3
|
Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.4
|
Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.5
|
First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). |
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10.1
|
Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrants Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)). | |
10.2
|
Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix A to the Registrants Definitive Proxy Statement on Schedule 14A for Stones 2009 Annual Meeting of Stockholders (File No. 001-12074)). | |
10.3
|
Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). | |
10.4
|
Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)). | |
10.5
|
Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). | |
10.6
|
Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). | |
10.7
|
Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed May 24, 2005 (File No. 001-12074)). | |
10.8
|
Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.8 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-12074)). | |
10.9
|
Letter Agreement dated June 28, 2007 between Stone Energy Corporation and Richard L. Smith (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed July 2, 2007 (File No. 001-12074)). | |
10.10
|
Amendment No.1, dated as of April 28, 2009, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and the financial institutions named therein (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed April 30, 2009 (File No. 001-12074)). | |
10.11
|
Amendment No. 2, dated January 11, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed January 12, 2010 (File No. 001-12074)). | |
10.12
|
Amendment No. 3, dated November 9, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed November 12, 2010 (File No. 001-12074)). | |
10.13
|
Amended and Restated Security Agreement, dated as of August 28, 2008, among Stone Energy Corporation and the other Debtors parties hereto in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registrants Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)). | |
10.14
|
Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated effective December 31, 2008) (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed April 8, 2009 (File No. 001-12074)). | |
10.15
|
Stone Energy Corporation Employee Change of Control Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.3 to the Registrants Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)). |
44
Table of Contents
10.16
|
Stone Energy Corporation Executive Change in Control Severance Policy (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)). | |
10.17
|
Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed March 27, 2009 (File No. 001-12074)). | |
*21.1
|
Subsidiaries of the Registrant. | |
*23.1
|
Consent of Independent Registered Public Accounting Firm. | |
*23.2
|
Consent of Netherland, Sewell & Associates, Inc. | |
*31.1
|
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*31.2
|
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*#32.1
|
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350. | |
*99.1
|
Report of Netherland, Sewell & Associates, Inc. |
* | Filed herewith. | |
| Identifies management contracts and compensatory plans or arrangements. | |
# | Not considered to be filed for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. |
45
Table of Contents
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.
STONE ENERGY CORPORATION |
||||
Date: March 3, 2011 | By: | /s/ David H. Welch | ||
David H. Welch | ||||
President and Chief Executive Officer | ||||
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.
Signature | Title | Date | ||
/s/ David H. Welch
|
President, Chief Executive Officer | March 3, 2011 | ||
David H. Welch
|
and Director | |||
(principal executive officer) | ||||
/s/ Kenneth H. Beer
|
Executive Vice President and | March 3, 2011 | ||
Kenneth H. Beer
|
Chief Financial Officer (principal financial officer) |
|||
/s/ J. Kent Pierret
|
Senior Vice President, Chief | March 3, 2011 | ||
J. Kent Pierret
|
Accounting Officer and Treasurer (principal accounting officer) | |||
/s/ Robert A. Bernhard
|
Director | March 3, 2011 | ||
Robert A. Bernhard |
||||
/s/ George R. Christmas
|
Director | March 3, 2011 | ||
George R. Christmas |
||||
/s/ B.J. Duplantis
|
Director | March 3, 2011 | ||
B.J. Duplantis |
||||
/s/ Peter D. Kinnear
|
Director | March 3, 2011 | ||
Peter D. Kinnear |
||||
/s/ John P. Laborde
|
Director | March 3, 2011 | ||
John P. Laborde |
||||
/s/ Richard A. Pattarozzi
|
Director | March 3, 2011 | ||
Richard A. Pattarozzi |
||||
/s/ Donald E. Powell
|
Director | March 3, 2011 | ||
Donald E. Powell |
||||
/s/ Kay G. Priestly
|
Director | March 3, 2011 | ||
Kay G. Priestly |
46
Table of Contents
INDEX TO FINANCIAL STATEMENTS
F-2 | ||||
F-3 | ||||
F-4 | ||||
F-5 | ||||
F-6 | ||||
F-7 | ||||
F-8 |
F-1
Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Stockholders and Board of Directors
Stone Energy Corporation
Stone Energy Corporation
We have audited the accompanying consolidated balance sheets of Stone Energy Corporation as of
December 31, 2010 and 2009, and the related consolidated statements of operations, cash flows,
changes in stockholders equity, and comprehensive income for each of the three years in the period
ended December 31, 2010. These financial statements are the responsibility of the Companys
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 consolidated financial position of Stone Energy Corporation as of December 31, 2010
and 2009, and the consolidated results of its operations and its cash flows for each of the three
years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting
principles.
As discussed in Note 1 to the consolidated financial statements, in 2009 the Company changed its
reserve estimates and related disclosures as a result of adopting new oil and gas reserve
estimation and disclosure requirements.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), Stone Energy Corporations internal control over financial reporting as of
December 31, 2010, based on criteria established in Internal ControlIntegrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated
March 3, 2011 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP |
New Orleans, Louisiana
March 3, 2011
March 3, 2011
F-2
Table of Contents
STONE ENERGY CORPORATION
CONSOLIDATED BALANCE SHEET
(Amounts in thousands of dollars, except per share amounts)
(Amounts in thousands of dollars, except per share amounts)
December 31, | ||||||||
2010 | 2009 | |||||||
Assets |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 106,956 | $ | 69,293 | ||||
Restricted cash |
5,500 | | ||||||
Accounts receivable |
88,529 | 118,129 | ||||||
Fair value of hedging contracts |
12,955 | 16,223 | ||||||
Deferred tax asset |
27,274 | 14,571 | ||||||
Inventory |
6,465 | 8,717 | ||||||
Other current assets |
768 | 814 | ||||||
Total current assets |
248,447 | 227,747 | ||||||
Oil and gas properties United States full cost method of
accounting: |
||||||||
Proved, net of accumulated depreciation, depletion and
amortization of $4,804,949 and $4,555,372, respectively |
984,629 | 856,467 | ||||||
Unevaluated |
413,180 | 329,242 | ||||||
Building and land, net of accumulated depreciation of
$2,033 and $1,840, respectively |
6,273 | 5,723 | ||||||
Fair value of hedging contracts |
| 1,771 | ||||||
Fixed assets, net of accumulated depreciation of $20,434 and
$18,591, respectively |
4,449 | 4,084 | ||||||
Other assets, net of accumulated depreciation and amortization
of $11,277 and $10,419, respectively |
22,112 | 29,208 | ||||||
Total assets |
$ | 1,679,090 | $ | 1,454,242 | ||||
Liabilities and Stockholders Equity |
||||||||
Current liabilities: |
||||||||
Accounts payable to vendors |
$ | 103,208 | $ | 66,863 | ||||
Undistributed oil and gas proceeds |
10,037 | 15,280 | ||||||
Fair value of hedging contracts |
32,144 | 34,859 | ||||||
Asset retirement obligations |
42,300 | 30,515 | ||||||
Current income tax payable |
239 | 11,110 | ||||||
Other current liabilities |
30,137 | 42,983 | ||||||
Total current liabilities |
218,065 | 201,610 | ||||||
Long-term debt |
575,000 | 575,000 | ||||||
Deferred taxes |
99,227 | 35,756 | ||||||
Asset retirement obligations |
331,620 | 290,084 | ||||||
Fair value of hedging contracts |
3,606 | 7,721 | ||||||
Other long-term liabilities |
21,215 | 18,412 | ||||||
Total liabilities |
1,248,733 | 1,128,583 | ||||||
Commitments and contingencies |
||||||||
Stockholders equity: |
||||||||
Common stock, $.01 par value; authorized 100,000,000 shares;
issued 47,764,505 and 47,509,144 shares, respectively |
478 | 475 | ||||||
Treasury stock (16,582 shares, respectively, at cost) |
(860 | ) | (860 | ) | ||||
Additional paid-in capital |
1,331,500 | 1,324,410 | ||||||
Accumulated deficit |
(886,557 | ) | (982,986 | ) | ||||
Accumulated other comprehensive loss |
(14,204 | ) | (15,380 | ) | ||||
Total stockholders equity |
430,357 | 325,659 | ||||||
Total liabilities and stockholders equity |
$ | 1,679,090 | $ | 1,454,242 | ||||
The accompanying notes are an integral part of this balance sheet.
F-3
Table of Contents
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF OPERATIONS
(Amounts in thousands, except per share amounts)
(Amounts in thousands, except per share amounts)
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Operating revenue: |
||||||||||||
Oil production |
$ | 417,948 | $ | 438,942 | $ | 461,050 | ||||||
Gas production |
233,055 | 272,353 | 336,665 | |||||||||
Derivative income, net |
3,265 | 3,061 | 3,327 | |||||||||
Total operating revenue |
654,268 | 714,356 | 801,042 | |||||||||
Operating expenses: |
||||||||||||
Lease operating expenses |
152,326 | 156,786 | 171,107 | |||||||||
Other operational expense |
5,450 | 2,400 | | |||||||||
Production taxes |
5,808 | 7,920 | 7,990 | |||||||||
Depreciation, depletion and amortization |
248,201 | 259,639 | 288,384 | |||||||||
Write-down of oil and gas properties |
| 508,989 | 1,324,327 | |||||||||
Goodwill impairment |
| | 465,985 | |||||||||
Accretion expense |
34,469 | 39,306 | 17,392 | |||||||||
Salaries, general and administrative expenses |
42,759 | 41,367 | 43,504 | |||||||||
Incentive compensation expense |
5,888 | 6,402 | 2,315 | |||||||||
Impairment of inventory |
129 | 9,398 | | |||||||||
Total operating expenses |
495,030 | 1,032,207 | 2,321,004 | |||||||||
Income (loss) from operations |
159,238 | (317,851 | ) | (1,519,962 | ) | |||||||
Other (income) expenses: |
||||||||||||
Interest expense |
12,192 | 21,361 | 13,243 | |||||||||
Interest income |
(1,464 | ) | (528 | ) | (11,250 | ) | ||||||
Other income |
(6,663 | ) | (4,362 | ) | (5,800 | ) | ||||||
Loss on early extinguishment of debt |
1,820 | | | |||||||||
Other expense |
642 | 508 | | |||||||||
Total other (income) expenses |
6,527 | 16,979 | (3,807 | ) | ||||||||
Net income (loss) before income taxes |
152,711 | (334,830 | ) | (1,516,155 | ) | |||||||
Provision (benefit) for income taxes: |
||||||||||||
Current |
5,808 | 30,376 | 6,998 | |||||||||
Deferred |
50,474 | (146,935 | ) | (376,144 | ) | |||||||
Total income taxes |
56,282 | (116,559 | ) | (369,146 | ) | |||||||
Net income (loss) |
96,429 | (218,271 | ) | (1,147,009 | ) | |||||||
Less: Net income (loss) attributable to non-controlling interest |
| 27 | (77 | ) | ||||||||
Net income (loss) attributable to Stone Energy Corporation |
$ | 96,429 | ($218,298 | ) | ($1,146,932 | ) | ||||||
Basic earnings (loss) per share attributable to Stone Energy
Corporation stockholders |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | ||||||
Diluted earnings (loss) per share attributable to Stone Energy
Corporation stockholders |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | ||||||
Average shares outstanding |
47,681 | 43,953 | 31,961 | |||||||||
Average shares outstanding assuming dilution |
47,706 | 43,953 | 31,961 |
The accompanying notes are an integral part of this statement.
F-4
Table of Contents
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Amounts in thousands of dollars)
(Amounts in thousands of dollars)
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Cash flows from operating activities: |
||||||||||||
Net income (loss) |
$ | 96,429 | ($218,271 | ) | ($1,147,009 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided
by operating activities: |
||||||||||||
Depreciation, depletion and amortization |
248,201 | 259,639 | 288,384 | |||||||||
Write-down of oil and gas properties |
| 508,989 | 1,324,327 | |||||||||
Goodwill impairment |
| | 465,985 | |||||||||
Impairment of inventory |
129 | 9,398 | | |||||||||
Accretion expense |
34,469 | 39,306 | 17,392 | |||||||||
Deferred income tax provision (benefit) |
50,474 | (146,935 | ) | (376,144 | ) | |||||||
Settlement of asset retirement obligations |
(36,901 | ) | (66,780 | ) | (49,242 | ) | ||||||
Non-cash stock compensation expense |
5,692 | 5,944 | 8,405 | |||||||||
Excess tax benefits |
(299 | ) | (2 | ) | (3,045 | ) | ||||||
Non-cash derivative (income) expense |
(324 | ) | 5,142 | (2,592 | ) | |||||||
Loss on early extinguishment of debt |
1,820 | | | |||||||||
Other non-cash expenses |
1,708 | 1,573 | 1,687 | |||||||||
Change in current income taxes |
(10,871 | ) | 66,185 | (87,110 | ) | |||||||
Decrease in accounts receivable |
49,633 | 50,159 | 110,689 | |||||||||
(Increase) decrease in other current assets |
74 | 627 | (866 | ) | ||||||||
(Increase) decrease in inventory |
2,123 | 17,561 | (33,530 | ) | ||||||||
Increase (decrease) in accounts payable |
(773 | ) | (10,200 | ) | 24,950 | |||||||
Decrease in other current liabilities |
(18,088 | ) | (14,431 | ) | (17,780 | ) | ||||||
Investment in hedging contracts |
| | (1,914 | ) | ||||||||
Other |
1,298 | (117 | ) | (109 | ) | |||||||
Net cash provided by operating activities |
424,794 | 507,787 | 522,478 | |||||||||
Cash flows from investing activities: |
||||||||||||
Acquisition of Bois dArc Energy, Inc., net of cash acquired |
| | (922,714 | ) | ||||||||
Investment in oil and gas properties |
(401,767 | ) | (320,214 | ) | (446,771 | ) | ||||||
Proceeds from sale of oil and gas properties, net of expenses |
31,635 | 5,553 | 13,339 | |||||||||
Sale of fixed assets |
| 35 | 4 | |||||||||
Investment in fixed and other assets |
(2,949 | ) | (1,412 | ) | (1,765 | ) | ||||||
Acquisition of non-controlling interest in subsidiary |
(1,007 | ) | (41 | ) | | |||||||
Net cash used in investing activities |
(374,088 | ) | (316,079 | ) | (1,357,907 | ) | ||||||
Cash flows from financing activities: |
||||||||||||
Proceeds from bank borrowings |
| | 425,000 | |||||||||
Repayments of bank borrowings |
(175,000 | ) | (250,000 | ) | | |||||||
Redemption of senior subordinated notes |
(200,503 | ) | | | ||||||||
Proceeds from issuance of senior notes |
375,000 | | | |||||||||
Proceeds from stock offering, net of expenses |
| 60,447 | (54 | ) | ||||||||
Deferred financing costs |
(11,474 | ) | (141 | ) | (8,766 | ) | ||||||
Excess tax benefits |
299 | 2 | 3,045 | |||||||||
Purchase of treasury stock |
| (347 | ) | (6,724 | ) | |||||||
Net payments for share based compensation |
(1,365 | ) | (513 | ) | 15,939 | |||||||
Net cash provided by (used in) financing activities |
(13,043 | ) | (190,552 | ) | 428,440 | |||||||
Net increase (decrease) in cash and cash equivalents |
37,663 | 1,156 | (406,989 | ) | ||||||||
Cash and cash equivalents, beginning of year |
69,293 | 68,137 | 475,126 | |||||||||
Cash and cash equivalents, end of year |
$ | 106,956 | $ | 69,293 | $ | 68,137 | ||||||
Supplemental disclosures of cash flow information: |
||||||||||||
Cash paid (refunded) during the year for: |
||||||||||||
Interest (net of amount capitalized) |
$ | 8,760 | $ | 20,623 | $ | 13,001 | ||||||
Income taxes |
26,525 | (35,920 | ) | 94,109 |
The accompanying notes are an integral part of this statement.
F-5
Table of Contents
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS EQUITY
(Amounts in thousands of dollars)
(Amounts in thousands of dollars)
Stone Energy Corporation Stockholders | ||||||||||||||||||||||||||||
Accumulated Other | ||||||||||||||||||||||||||||
Additional Paid-In | Comprehensive | Non-controlling | Total Stockholders | |||||||||||||||||||||||||
Common Stock | Treasury Stock | Capital | Retained Earnings | Income (Loss) | Interest | Equity | ||||||||||||||||||||||
Balance, December 31, 2007 |
$ | 278 | ($1,161 | ) | $ | 515,055 | $ | 382,365 | ($10,735 | ) | $ | | $ | 885,802 | ||||||||||||||
Net loss |
| | | (1,146,932 | ) | | (77 | ) | (1,147,009 | ) | ||||||||||||||||||
Adjustment for fair value
accounting of derivatives,
net of tax |
| | | | 95,647 | | 95,647 | |||||||||||||||||||||
Exercise of stock options and
vesting of restricted stock |
5 | | 15,934 | | | | 15,939 | |||||||||||||||||||||
Amortization of stock
compensation expense |
| | 12,906 | | | | 12,906 | |||||||||||||||||||||
Tax benefit from stock option
exercises and restricted
stock vesting |
| | 2,740 | | | | 2,740 | |||||||||||||||||||||
Non-controlling interest in
subsidiary |
| | | | | 164 | 164 | |||||||||||||||||||||
Issuance of common stock |
113 | | 717,720 | | | | 717,833 | |||||||||||||||||||||
Cancellation of treasury stock |
(2 | ) | | (6,722 | ) | | | | (6,724 | ) | ||||||||||||||||||
Issuance of treasury stock |
| 301 | | (121 | ) | | | 180 | ||||||||||||||||||||
Balance, December 31, 2008 |
394 | (860 | ) | 1,257,633 | (764,688 | ) | 84,912 | 87 | 577,478 | |||||||||||||||||||
Net income (loss) |
| | | (218,298 | ) | | 27 | (218,271 | ) | |||||||||||||||||||
Adjustment for fair value
accounting of derivatives,
net of tax |
| | | | (100,292 | ) | | (100,292 | ) | |||||||||||||||||||
Acquisition of
non-controlling interest |
| | 73 | | | (114 | ) | (41 | ) | |||||||||||||||||||
Exercise of stock options and
vesting of restricted stock |
| | (514 | ) | | | | (514 | ) | |||||||||||||||||||
Amortization of stock
compensation expense |
| | 8,845 | | | | 8,845 | |||||||||||||||||||||
Tax deficit from stock option
exercises and restricted
stock vesting |
| | (1,647 | ) | | | | (1,647 | ) | |||||||||||||||||||
Stock repurchase and
cancellation |
| | (346 | ) | | | | (346 | ) | |||||||||||||||||||
Issuance of common stock |
81 | | 60,366 | | | | 60,447 | |||||||||||||||||||||
Balance, December 31, 2009 |
475 | (860 | ) | 1,324,410 | (982,986 | ) | (15,380 | ) | | 325,659 | ||||||||||||||||||
Net income |
| | | 96,429 | | | 96,429 | |||||||||||||||||||||
Adjustment for fair value
accounting of derivatives,
net of tax |
| | | | 1,176 | | 1,176 | |||||||||||||||||||||
Exercise of stock options and
vesting of restricted stock |
3 | | (1,370 | ) | | | | (1,367 | ) | |||||||||||||||||||
Amortization of stock
compensation expense |
| | 8,462 | | | | 8,462 | |||||||||||||||||||||
Tax deficit from stock option
exercises and restricted
stock vesting |
| | (2 | ) | | | | (2 | ) | |||||||||||||||||||
Balance, December 31, 2010 |
$ | 478 | ($860 | ) | $ | 1,331,500 | ($886,557 | ) | ($14,204 | ) | $ | | $ | 430,357 | ||||||||||||||
The accompanying notes are an integral part of this statement.
F-6
Table of Contents
STONE ENERGY CORPORATION
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(Amounts in thousands of dollars)
(Amounts in thousands of dollars)
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Net income (loss) attributable to Stone Energy
Corporation |
$ | 96,429 | ($218,298 | ) | ($1,146,932 | ) | ||||||
Other comprehensive income (loss) net of tax effect: |
||||||||||||
Adjustment for fair value accounting of derivatives |
1,176 | (100,292 | ) | 95,647 | ||||||||
Comprehensive income (loss) attributable to Stone
Energy Corporation |
$ | 97,605 | ($318,590 | ) | ($1,051,285 | ) | ||||||
The accompanying notes are an integral part of this statement.
F-7
Table of Contents
STONE ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars, except per share and price amounts)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands of dollars, except per share and price amounts)
NOTE 1 ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Stone Energy Corporation is an independent oil and natural gas company engaged in the
acquisition and subsequent exploration, development, and operation of oil and gas properties
located primarily in the Gulf of Mexico (GOM). We are also active in the Appalachia region,
where we have established a significant acreage position and have development operations in the
Marcellus Shale. We have also targeted several exploratory oil projects in the Rocky Mountain
region. In 2008, we acquired Bois dArc Energy, Inc. (Bois dArc), an independent exploration
company which was engaged in the discovery and production of oil and natural gas in the GOM. Prior
to November 30, 2008, we participated in an exploratory joint venture in Bohai Bay, China. Our
corporate headquarters are located at 625 E. Kaliste Saloom Road, Lafayette, Louisiana 70508. We
have additional offices in New Orleans, Louisiana, Houston, Texas and Morgantown, West Virginia.
A summary of significant accounting policies followed in the preparation of the accompanying
consolidated financial statements is set forth below.
Basis of Presentation:
The financial statements include our accounts and the accounts of our wholly owned
subsidiaries, Stone Energy Offshore, L.L.C. (Stone Offshore), Stone Energy, L.L.C. and Caillou
Boca Gathering, LLC (Caillou Boca). On December 31, 2010, Stone Energy, L.L.C. was merged into
Stone Offshore. From August 2008 to the second quarter of 2009, Calliou Boca was a majority owned
subsidiary. During the second quarter of 2009, we acquired the entire non-controlling interest in
Calliou Boca. All intercompany balances have been eliminated. Certain prior year amounts have
been reclassified to conform to current year presentation.
Use of Estimates:
The preparation of financial statements in conformity with U.S. Generally Accepted Accounting
Principles (U.S. GAAP) requires our management to make estimates and assumptions that affect the
reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at
the date of the financial statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates. Estimates are used primarily
when accounting for depreciation, depletion and amortization, unevaluated property costs, estimated
future net cash flows from proved reserves, cost to abandon oil and gas properties, taxes, reserves
of accounts receivable, accruals of capitalized costs, operating costs and production revenue,
capitalized general and administrative costs and interest, insurance recoveries related to
hurricanes, effectiveness and estimated fair value of derivative positions, the purchase price
allocation on properties acquired, estimates of fair value in business combinations, goodwill
impairment testing and measurement, and contingencies.
Fair Value Measurements:
U.S. GAAP establishes a framework for measuring fair value and requires certain disclosures
about fair value measurements. As of December 31, 2010, we held certain financial assets and
liabilities that are required to be measured at fair value on a recurring basis, including our
commodity derivative instruments and our investments in money market funds.
Cash and Cash Equivalents:
We consider all money market funds and highly liquid investments in overnight securities
through our commercial bank accounts, which result in available funds on the next business day, to
be cash and cash equivalents.
Restricted Cash:
At December 31, 2010, the restricted cash balance of $5,500 related to escrowed amounts on
deposit with a qualified intermediary involved in a tax-free exchange of properties. These amounts
became unrestricted in January 2011.
Oil and Gas Properties:
We follow the full cost method of accounting for oil and gas properties. Under this method,
all acquisition, exploration, development and estimated abandonment costs, including certain
related employee and general and administrative costs (less any reimbursements for such costs) and
interest incurred for the purpose of finding oil and gas are capitalized. Such amounts include the
cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay
rentals and other costs related to such activities. Employee, general and administrative costs
that are capitalized include salaries and all related fringe benefits paid to employees directly
engaged in the acquisition, exploration and development of oil and gas properties, as well
F-8
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as all other directly identifiable general and administrative costs associated with such
activities, such as rentals, utilities and insurance. 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. Employee, general and administrative costs
associated with production operations and general corporate activities are expensed in the period
incurred. Additionally, workover and maintenance costs incurred solely to maintain or increase
levels of production from an existing completion interval are charged to lease operating expense in
the period incurred.
U.S. GAAP allows 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 depreciation, depletion and amortization (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.
We amortize our investment in oil and gas properties through DD&A using the units of
production (UOP) method. Under the UOP method, the quarterly provision for DD&A is computed by
dividing production volumes for the period by the total proved reserves as of the beginning of the
period (beginning of the period reserves being determined by adding back production to end of the
period reserves), and applying the respective rate to the net cost of proved oil and gas
properties, including future development costs.
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 (excluding cash
flows related to estimated abandonment costs), to the net capitalized costs of proved oil and gas
properties 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 (See Note 7 Investment in Oil and Gas
Properties). Historically, estimated future net cash flows from proved reserves were calculated
based on period-end hedge adjusted commodity prices, and the impact of price increases subsequent
to the period end could be considered. In December 2008, the Securities and Exchange Commission
(SEC) issued a final rule, Modernization of Oil and Gas Reporting, which adopted revisions to
the SECs oil and gas reporting requirements. The revisions replaced the single-day year-end
pricing with a twelve-month average pricing assumption. Additionally, consideration of the impact
of subsequent price increases after period end is no longer allowed. The changes to prices used in
reserves calculations under the new rule are used in both disclosures and accounting impairment
tests. In January 2010, the Financial Accounting Standards Board (FASB) issued its final
standard on oil and gas reserve estimation and disclosures aligning its requirements with the SECs
final rule. The new rules were considered a change in accounting principle that is inseparable from
a change in accounting estimate, which did not require retroactive revision.
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.
Asset Retirement Obligations:
U.S. GAAP 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
propertys useful life. The application of this rule requires the use of managements estimates
with respect to future abandonment costs, inflation, market risk premiums, useful life and cost of
capital. U.S. GAAP requires that our estimate of our asset retirement obligations does not give
consideration to the value the related assets could have to other parties.
Building and Land:
Building and land are recorded at cost. Our office building in Lafayette, Louisiana is being
depreciated on the straight-line method over its estimated useful life of 39 years.
Inventory:
We maintain an inventory of tubular goods. Items remain in inventory until dedicated to
specific projects, at which time they are transferred to oil and gas properties. Items are carried
at the lower of cost or market applied to items specifically identified.
Earnings Per Common Share:
Under U.S. GAAP, instruments granted in share-based payment transactions are participating
securities prior to vesting and are therefore required to be included in the earnings allocation in
calculating earnings per share under the two-class method.
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Companies are required to treat
unvested share-based payment awards with a right to receive non-forfeitable dividends as a
separate class of securities in calculating earnings per share. This rule became effective
for us on January 1, 2009 and the net effect of its implementation on our financial statements was
immaterial.
Business Combinations and Goodwill:
Our 2008 acquisition of Bois dArc was accounted for using the purchase method of accounting
for business combinations. We applied fair value concepts in determining the cost of the acquired
entity and allocating that cost to the assets acquired (including goodwill) and liabilities
assumed. U.S. GAAP requires the testing for impairment of goodwill at least annually. It
establishes a two-step methodology for determining impairment that begins with an estimation of the
fair value of the reporting unit. The first step is a screen for potential impairment, and the
second step measures the amount of impairment, if any. This authoritative guidance provided the
framework for the determination of our goodwill impairment of
$465,985 at December 31, 2008. We have no goodwill recognized in
our financial statements at December 31, 2010 or December 31, 2009.
Production Revenue:
We recognize production revenue under the entitlement method of accounting. Under this
method, revenue is deferred for deliveries in excess of our net revenue interest, while revenue is
accrued for undelivered volumes. Production imbalances are generally recorded at the estimated
sales price in effect at the time of production.
Income Taxes:
Provisions for income taxes include deferred taxes resulting primarily from temporary
differences due to different reporting methods for oil and gas properties for financial reporting
purposes and income tax purposes. For financial reporting purposes, all exploratory and
development expenditures, including future abandonment costs, related to evaluated projects are
capitalized and depreciated, depleted and amortized on the UOP method. For income tax purposes,
only the equipment and leasehold costs relative to successful wells are capitalized and recovered
through depreciation or depletion. Generally, most other exploratory and development costs are
charged to expense as incurred; however, we follow certain provisions of the Internal Revenue Code
that allow capitalization of intangible drilling costs where management deems appropriate. Other
financial and income tax reporting differences occur as a result of statutory depletion, different
reporting methods for sales of oil and gas reserves in place, different reporting methods used in
the capitalization of employee, general and administrative and interest expenses, and different
reporting methods for stock-based compensation.
Derivative Instruments and Hedging Activities:
The nature of a derivative instrument must be evaluated to determine if it qualifies for hedge
accounting treatment. 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 (loss), net of related taxes, to the extent the hedge is
considered effective. Additionally, monthly settlements of effective hedges are reflected in
revenue from oil and gas production and cash flow from operations. Instruments not qualifying for
hedge accounting treatment are recorded in the balance sheet at fair value and changes in fair
value are recognized in earnings through derivative expense (income).
Stock-Based Compensation:
We record stock-based compensation based on the grant date fair value of issued stock options
and restricted stock over the vesting period of the instrument. We utilize the Black-Scholes
option pricing model to measure the fair value of stock options. The fair value of restricted
shares is determined based on the average of the high and low prices on the grant date.
Recent Accounting Developments:
Fair Value Measurements and Disclosures. Accounting Standards Update (ASU) 2010-06 was
issued in January 2010 to improve disclosures about fair value measurements by requiring a greater
level of disaggregated information, more robust disclosures about valuation techniques and inputs
to fair value measurements, information about significant transfers between the three levels in the
fair value hierarchy, and separate presentation of information about purchases, sales, issuances,
and settlements on a gross basis rather than as one net number. The guidance provided in ASU
2010-06 became effective for interim and annual periods beginning after December 15, 2009, except
for the disclosures about purchases, sales, issuances, and settlements in the roll forward of
activity in Level 3 fair value measurements. Those disclosures are effective for fiscal years
beginning after December 15, 2010, and for interim periods within those fiscal years. We had no
Level 3 fair value measurements during the year ended December 31, 2010.
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NOTE 2 PRIOR PERIOD CORRECTION OF IMMATERIAL ERRORS:
During the fourth quarter of 2010, we determined that prior reporting periods had
misstatements caused by errors in the process of the estimation of asset retirement obligations at
December 31, 2008. Management has concluded that the impact of these errors on prior reporting
periods is immaterial. However, given that the adjustment to correct the errors in 2010 would have
a material impact on the 2010 financial statements, we have corrected the prior periods in the
current Form 10-K in accordance with SEC guidance. The information included in this Form 10-K sets
forth the effects of these corrections on the previously reported financial statements and
accompanying information for the years ended December 31, 2009 and 2008. The net effect of the
corrections on the individual financial statement line items for the periods presented are as
follows:
Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||||||||||||||||||
As Reported | Adjustment | As Adjusted | As Reported | Adjustment | As Adjusted | |||||||||||||||||||
Consolidated Statement of Operations: |
||||||||||||||||||||||||
Write-down of oil and gas properties |
$ | 505,140 | $ | 3,849 | $ | 508,989 | $ | 1,309,403 | $ | 14,924 | $ | 1,324,327 | ||||||||||||
Accretion expense |
33,016 | 6,290 | 39,306 | 17,392 | | 17,392 | ||||||||||||||||||
Total operating expenses |
1,022,068 | 10,139 | 1,032,207 | 2,306,080 | 14,924 | 2,321,004 | ||||||||||||||||||
Income (loss) from operations |
(307,712 | ) | (10,139 | ) | (317,851 | ) | (1,505,038 | ) | (14,924 | ) | (1,519,962 | ) | ||||||||||||
Net income (loss) before income taxes |
(324,691 | ) | (10,139 | ) | (334,830 | ) | (1,501,231 | ) | (14,924 | ) | (1,516,155 | ) | ||||||||||||
Provision (benefit) for deferred
income taxes |
(143,386 | ) | (3,549 | ) | (146,935 | ) | (370,921 | ) | (5,223 | ) | (376,144 | ) | ||||||||||||
Total income taxes |
(113,010 | ) | (3,549 | ) | (116,559 | ) | (363,923 | ) | (5,223 | ) | (369,146 | ) | ||||||||||||
Net income (loss) |
(211,681 | ) | (6,590 | ) | (218,271 | ) | (1,137,308 | ) | (9,701 | ) | (1,147,009 | ) | ||||||||||||
Net income (loss) attributable to
Stone Energy Corporation |
(211,708 | ) | (6,590 | ) | (218,298 | ) | (1,137,231 | ) | (9,701 | ) | (1,146,932 | ) | ||||||||||||
Basic earnings (loss) per share
attributable to Stone Energy
Corporation stockholders |
($4.82 | ) | ($0.15 | ) | ($4.97 | ) | ($35.58 | ) | ($0.31 | ) | ($35.89 | ) | ||||||||||||
Diluted earnings (loss) per share
attributable to Stone Energy
Corporation stockholders |
($4.82 | ) | ($0.15 | ) | ($4.97 | ) | ($35.58 | ) | ($0.31 | ) | ($35.89 | ) | ||||||||||||
Consolidated Statement of Cash Flows: |
||||||||||||||||||||||||
Net income (loss) |
(211,681 | ) | (6,590 | ) | (218,271 | ) | (1,137,308 | ) | (9,701 | ) | (1,147,009 | ) | ||||||||||||
Write-down of oil and gas properties |
505,140 | 3,849 | 508,989 | 1,309,403 | 14,924 | 1,324,327 | ||||||||||||||||||
Accretion expense |
33,016 | 6,290 | 39,306 | 17,392 | | 17,392 | ||||||||||||||||||
Deferred income tax benefit |
(143,386 | ) | (3,549 | ) | (146,935 | ) | (370,921 | ) | (5,223 | ) | (376,144 | ) | ||||||||||||
Consolidated Statement of
Comprehensive Income: |
||||||||||||||||||||||||
Net income (loss) attributable to
Stone Energy Corporation |
(211,708 | ) | (6,590 | ) | (218,298 | ) | (1,137,231 | ) | (9,701 | ) | (1,146,932 | ) | ||||||||||||
Comprehensive income (loss)
attributable to Stone Energy
Corporation |
(312,000 | ) | (6,590 | ) | (318,590 | ) | (1,041,584 | ) | (9,701 | ) | (1,051,285 | ) |
December 31, 2009 | ||||||||||||
As Reported | Adjustment | As Adjusted | ||||||||||
Consolidated Balance Sheet: |
||||||||||||
Asset retirement obligations, long-term |
$ | 265,021 | $ | 25,063 | $ | 290,084 | ||||||
Deferred taxes, long-term |
44,528 | (8,772 | ) | 35,756 | ||||||||
Total liabilities |
1,112,292 | 16,291 | 1,128,583 | |||||||||
Accumulated deficit |
(966,695 | ) | (16,291 | ) | (982,986 | ) | ||||||
Total stockholders equity |
341,950 | (16,291 | ) | 325,659 |
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NOTE 3 EARNINGS PER SHARE:
The following table sets forth the calculation of basic and diluted weighted average shares
outstanding and earnings per share for the indicated periods.
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Income (numerator): |
||||||||||||
Net income (loss) attributable to Stone Energy Corporation |
$ | 96,429 | ($218,298 | ) | ($1,146,932 | ) | ||||||
Net income attributable to participating securities |
(1,559 | ) | | | ||||||||
Net income (loss) attributable to common stock basic and
diluted |
$ | 94,870 | ($218,298 | ) | ($1,146,932 | ) | ||||||
Weighted average shares (denominator): |
||||||||||||
Weighted average shares basic |
47,681 | 43,953 | 31,961 | |||||||||
Diluted effect of stock options and unvested restricted stock |
25 | | | |||||||||
Weighted average shares diluted |
47,706 | 43,953 | 31,961 | |||||||||
Basic income (loss) per common share |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | ||||||
Diluted income (loss) per common share |
$ | 1.99 | ($4.97 | ) | ($35.89 | ) | ||||||
Stock options that were considered antidilutive because the exercise price of the option
exceeded the average price of our common stock for the applicable period totaled approximately
420,000 during the year ended December 31, 2010. All outstanding stock options (approximately
495,000 shares) were considered antidilutive during the year ended December 31, 2009 because we had
a net loss for the period. All outstanding stock options (approximately 511,000 shares) were
considered antidilutive during the year ended December 31, 2008 because we had a net loss for the
period.
During the years ended December 31, 2010, 2009 and 2008, approximately 255,000, 129,000 and
567,000 shares of common stock, respectively, were issued, from either authorized shares or shares
held in treasury, upon the exercise of stock options, vesting (lapse of forfeiture restrictions) of
restricted stock by employees and nonemployee directors and the awarding of employee bonus stock
pursuant to the 2004 Amended and Restated Stock Incentive Plan. During the year ended December 31,
2009, 100,000 shares of common stock were repurchased under our stock repurchase program. On June
10, 2009, 8,050,000 shares of common stock were issued in a public offering. During the year ended
December 31, 2008, 200,000 shares of common stock were repurchased under our stock repurchase
program. On August 28, 2008, 11,301,751 shares of common stock were issued upon the completion of
our acquisition of Bois dArc (see Note 6 Acquisitions and Divestitures).
NOTE 4 ACCOUNTS RECEIVABLE:
In our capacity as operator for our co-venturers, we incur drilling and other costs that we
bill to the respective parties based on their working interests. We also receive payments for
these billings and, in some cases, for billings in advance of incurring costs. Our accounts
receivable are comprised of the following amounts:
As of December 31, | ||||||||
2010 | 2009 | |||||||
Accounts Receivable: |
||||||||
Other co-venturers |
$ | 6,769 | $ | 6,831 | ||||
Trade |
75,653 | 77,948 | ||||||
Insurance receivable on hurricane claims |
1,718 | 28,629 | ||||||
Unbilled accounts receivable |
4,352 | 4,685 | ||||||
Other |
37 | 36 | ||||||
$ | 88,529 | $ | 118,129 | |||||
We have accrued insurance receivables on hurricane claims to the extent we have concluded the
insurance recovery is probable. The accrual only relates to costs previously recorded in our
financial statements, including asset retirement obligations and repair expenses included in lease
operating expenses.
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NOTE 5 CONCENTRATIONS:
Sales to Major Customers
Our production is sold on month-to-month contracts at prevailing prices. We have attempted to
diversify our sales and obtain credit protections such as parental guarantees from certain of our
purchasers. The following table identifies customers from whom we derived 10% or more of our total
oil and gas revenue during the years ended:
December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Chevron U.S.A., Inc. |
(a | ) | (a | ) | 18 | % | ||||||
Conoco, Inc. |
26 | % | 27 | % | 29 | % | ||||||
Hess Corporation |
11 | % | 11 | % | (a | ) | ||||||
Sequent Energy Management LP |
10 | % | 13 | % | (a | ) | ||||||
Shell Trading (US) Company |
40 | % | 34 | % | 16 | % | ||||||
(a) Less than 10 percent
The maximum amount of credit risk exposure at December 31, 2010 relating to these customers
amounted to $70,704.
We believe that the loss of any of these purchasers would not result in a material adverse
effect on our ability to market future oil and gas production.
Production and Reserve Volumes
Approximately
99.5% of our production during 2010 was associated with our Gulf Coast Basin
properties and 83% of our estimated proved reserves (unaudited) at December 31, 2010 were derived
from Gulf Coast Basin reservoirs.
Cash and Cash Equivalents
Substantially all of our cash balances are in excess of federally insured limits. At December
31, 2010 approximately $7,306 was invested in the J.P. Morgan Prime Money Market Fund (Capital
Shares). An additional $81,006 was in accounts at J.P. Morgan Chase & Co.
NOTE 6 ACQUISITIONS AND DIVESTITURES:
Acquisitions
During 2010, we acquired an approximate 26,000 net acre leasehold position in Appalachia from
various landowners at a cost of approximately $74,334.
On August 28, 2008, we completed the acquisition of Bois dArc in a cash and stock transaction
totaling approximately $1,653,312. Bois dArc was an independent exploration company engaged in
the discovery and production of oil and natural gas in the Gulf of Mexico. Pursuant to the terms
and conditions of the agreement and plan of merger, Stone paid total merger consideration of
approximately $935,425 in cash and issued approximately 11.3 million common shares, valued at
$63.52 per share. The per share value of the Stone common shares issued was calculated as the
average of Stones closing share price for the two days prior to through the two days after the
merger announcement date of April 30, 2008. The cash component of the merger consideration was
funded with approximately $510,425 of cash on hand and $425,000 of borrowings from our amended and
restated bank credit facility.
The acquisition was accounted for using the purchase method of accounting for business
combinations. The acquisition was preliminarily recorded in Stones consolidated financial
statements on August 28, 2008, the date the acquisition closed. The preliminary purchase price
allocation was adjusted in the fourth quarter of 2008 as a result of further analysis of the assets
acquired, principally proved and unevaluated oil and gas properties, and liabilities assumed,
principally asset retirement obligations and deferred taxes, which resulted in an adjustment to the
preliminary allocation to goodwill. The adjustments were the result of additional analysis of
proved, probable and possible reserves at the time of the acquisition.
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Table of Contents
The following table represents the allocation of the total purchase price of Bois dArc to the
acquired assets and liabilities of Bois dArc.
Fair value of Bois dArcs net assets: |
||||
Net working capital, including cash of $15,333 |
$ | 27,865 | ||
Proved oil and gas properties |
1,339,117 | |||
Unevaluated oil and gas properties |
422,183 | |||
Fixed and other assets |
333 | |||
Goodwill |
465,985 | |||
Deferred tax liability |
(467,872 | ) | ||
Dismantlement reserve |
(4,239 | ) | ||
Asset retirement obligations |
(127,380 | ) | ||
Total fair value of net assets |
$ | 1,655,992 | ||
The following table represents the breakdown of the consideration paid for Bois dArcs net
assets.
Consideration paid for Bois dArcs net assets: |
||||
Cash consideration paid |
$ | 935,425 | ||
Stone common stock issued |
717,887 | |||
Aggregate purchase consideration issued to Bois dArc
stockholders |
1,653,312 | |||
Plus: |
||||
Direct merger costs (1) |
2,680 | |||
Total purchase price |
$ | 1,655,992 | ||
(1) | Direct merger costs include legal and accounting fees, printing fees, investment banking expenses and other merger-related costs. |
The allocation of the purchase price included $465,985 of asset valuation attributable to
goodwill. Goodwill represents the amount by which the total purchase price exceeds the aggregate
fair values of the assets acquired and liabilities assumed in the merger, other than goodwill.
Goodwill was not deductible for tax purposes. Goodwill is required to be tested for impairment at
least annually. We tested goodwill created in the Bois dArc acquisition for impairment on
December 31, 2008. A substantial reduction in commodity prices and the existence of a full cost
ceiling test write-down in the fourth quarter of 2008 were indications of potential impairment.
The reporting unit for the impairment test was Stone Energy Corporation and its consolidated
subsidiaries. The fair value of the reporting unit was determined using average quoted market
prices for Stone common stock for the two market days prior to through the two market days after
December 31, 2008. A control premium of 25% was applied to the market capitalization. The control
premium was based on a history of control premiums paid for the acquisition of entities in similar
industries. The resulting fair value of the reporting unit was $504,025 below the reporting units
carrying value. Additional analysis indicated no implied value of the recorded goodwill, resulting
in the impairment of the entire amount of goodwill of $465,985 at December 31, 2008.
Divestitures
In April 2010, we divested our leasehold interest in approximately 7,000 acres in the
Marcellus Shale for approximately $30,315. In the fourth quarter of 2010, we completed the sale of
our interest in the Main Pass Block 41 Field for cash consideration of approximately $5,500. The
estimated asset retirement obligation for this field was $632. In the second quarter of 2009, we
completed the sale of an onshore Louisiana field for cash consideration of approximately $4,909.
The estimated asset retirement obligation for this field was $5,941. The sales of these properties
were accounted for as an adjustment of net capitalized costs with no gain or loss recognized.
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Table of Contents
NOTE 7 INVESTMENT IN OIL AND GAS PROPERTIES:
The following table discloses certain financial data relative to our oil and gas producing
activities located onshore and offshore the continental United States:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Oil and gas properties United States, proved and unevaluated: |
||||||||||||
Balance, beginning of year |
$ | 5,741,081 | $ | 5,409,770 | $ | 3,310,074 | ||||||
Costs incurred during the year (capitalized): |
||||||||||||
Acquisition costs, net of sales of unevaluated properties |
127,069 | 9,072 | 1,830,468 | |||||||||
Exploratory costs |
42,205 | 78,582 | 146,303 | |||||||||
Development costs (1) |
241,387 | 199,375 | 78,359 | |||||||||
Salaries, general and administrative costs |
20,521 | 19,107 | 19,507 | |||||||||
Interest |
30,783 | 25,573 | 25,195 | |||||||||
Less: overhead reimbursements |
(288 | ) | (398 | ) | (136 | ) | ||||||
Total costs incurred during the year, net of divestitures |
461,677 | 331,311 | 2,099,696 | |||||||||
Balance, end of year |
$ | 6,202,758 | $ | 5,741,081 | $ | 5,409,770 | ||||||
Accumulated depreciation, depletion and amortization (DD&A): |
||||||||||||
Balance, beginning of year |
($4,555,372 | ) | ($3,781,600 | ) | ($2,158,327 | ) | ||||||
Provision for DD&A |
(242,745 | ) | (253,790 | ) | (284,672 | ) | ||||||
Write-down of oil and gas properties |
| (508,989 | ) | (1,293,345 | ) | |||||||
Sale of proved properties |
(6,832 | ) | (10,993 | ) | (45,256 | ) | ||||||
Balance, end of year |
($4,804,949 | ) | ($4,555,372 | ) | ($3,781,600 | ) | ||||||
Net capitalized costs United States (proved and unevaluated) |
$ | 1,397,809 | $ | 1,185,709 | $ | 1,628,170 | ||||||
DD&A per Mcfe |
$ | 3.18 | $ | 3.23 | $ | 4.45 | ||||||
(1) Includes asset retirement costs of $56,444, $78,387
and ($77,573), respectively. |
||||||||||||
Costs incurred during the year (expensed): |
||||||||||||
Lease operating expenses |
$ | 152,326 | $ | 156,786 | $ | 171,107 | ||||||
Production taxes |
5,808 | 7,920 | 7,990 | |||||||||
Accretion expense |
34,469 | 39,306 | 17,392 | |||||||||
Expensed costs United States |
$ | 192,603 | $ | 204,012 | $ | 196,489 | ||||||
In December 2008, the SEC issued a final rule, Modernization of Oil and Gas Reporting, which
adopted revisions to the SECs oil and gas reporting requirements. It became effective January 1,
2010 for Annual Reports on Form 10-K for years ending on or after December 31, 2009. The revisions
replaced the single-day year-end pricing with a twelve-month average pricing assumption. Changes to
prices used in reserves calculations are used in both disclosures and accounting impairment tests.
At December 31, 2009, our ceiling test computation (See Note 1) resulted in a write-down of our
U.S. oil and gas properties of $165,057 based on twelve-month average prices of $58.95 per barrel
of oil and $3.49 per Mcf of natural gas. The benefit of hedges in place at December 31, 2009
reduced the write-down by $94,541. At March 31, 2009, our ceiling test computation resulted in a
write-down of our U.S. oil and gas properties of $343,932 based on a March 31, 2009 Henry Hub gas
price of $3.63 per MMBtu and a West Texas Intermediate (WTI) oil price of $44.92 per barrel. At
December 31, 2008, our ceiling test computation resulted in a write-down of our U.S. oil and gas
properties, which included assets acquired in the Bois dArc transaction, of $1,293,345 based on a
December 31, 2008 Henry Hub gas price of $5.71 per MMBtu and a WTI oil price of $41.00 per barrel.
The benefit of hedges in place at December 31, 2008 reduced the write-down by $177,729.
The following table discloses net costs incurred (evaluated) on our unevaluated properties
located in the United States for the years indicated:
Unevaluated oil and gas properties United States | 2010 | 2009 | 2008 | |||||||||
Net costs incurred (evaluated) during year: |
||||||||||||
Acquisition costs |
$ | 42,664 | ($203,776 | ) | $ | 308,325 | ||||||
Exploration costs |
10,491 | 15,337 | 24,531 | |||||||||
Capitalized interest |
30,783 | 23,943 | 10,314 | |||||||||
$ | 83,938 | ($164,496 | ) | $ | 343,170 | |||||||
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Table of Contents
During 2006, we entered into an agreement to participate in the drilling of exploratory wells
on two offshore concessions in Bohai Bay, China. After the drilling of three wells, we decided in
2008 not to pursue any additional investments in this area. As a result of this decision, we fully
impaired our capitalized costs from activities in China in 2008. The following table discloses
certain financial data relative to our oil and gas exploration activities located in Bohai Bay,
China:
Year Ended | ||||
December 31, | ||||
2008 | ||||
Oil and gas properties China: |
||||
Balance, beginning of year |
$ | 37,729 | ||
Costs incurred during the year (capitalized): |
||||
Exploratory costs |
226 | |||
Salaries, general and administrative costs |
31 | |||
Interest |
1,160 | |||
Total costs incurred during the year |
1,417 | |||
Balance, end of year (fully evaluated) |
$ | 39,146 | ||
Accumulated depreciation, depletion and amortization (DD&A): |
||||
Balance, beginning of year |
$ | (8,164 | ) | |
Write-down of oil and gas properties |
(30,982 | ) | ||
Balance, end of year |
$ | (39,146 | ) | |
Net capitalized costs China |
$ | | ||
The following table discloses financial data associated with unevaluated costs in the United
States at December 31, 2010:
Net Costs Incurred During the | ||||||||||||||||||||
Year Ended December 31, | ||||||||||||||||||||
Balance as of | 2007 | |||||||||||||||||||
December 31, 2010 | 2010 | 2009 | 2008 | and prior | ||||||||||||||||
Acquisition costs |
$ | 234,680 | $ | 110,301 | $ | 4,445 | $ | 112,658 | $ | 7,276 | ||||||||||
Exploration costs |
131,467 | 31,405 | 39,063 | 25,543 | 35,456 | |||||||||||||||
Capitalized interest |
47,033 | 25,396 | 16,497 | 4,260 | 880 | |||||||||||||||
Total unevaluated costs |
$ | 413,180 | $ | 167,102 | $ | 60,005 | $ | 142,461 | $ | 43,612 | ||||||||||
Approximately 107 specifically identified drilling projects are included in unevaluated costs
at December 31, 2010 and are expected to be evaluated in the next four years. The excluded costs
will be included in the amortization base as the properties are evaluated and proved reserves are
established or impairment is determined. Interest costs capitalized on unevaluated properties
during the years ended December 31, 2010, 2009 and 2008 totaled $30,783, $25,573 and $26,355,
respectively.
NOTE 8 DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES:
Our hedging strategy is designed to protect our near and intermediate term cash flow from
future declines in oil and natural gas prices. This protection is essential to capital budget
planning which is sensitive to expenditures that must be committed to in advance such as rig
contracts and the purchase of tubular goods. We enter into hedging transactions to secure a
commodity price for a portion of future production that is acceptable at the time of the
transaction. These hedges are designated as cash flow hedges upon entering into the contract. We
do not enter into hedging transactions for trading purposes. We have no fair value hedges.
The nature of a derivative instrument must be evaluated to determine if it qualifies for
hedge accounting treatment. If the instrument qualifies for hedge accounting treatment, it is
recorded as either an asset or liability measured at fair value and subsequent changes in the
derivatives fair value are recognized in equity through other comprehensive income (loss), net of
related taxes, to the extent the hedge is considered effective. Additionally, monthly settlements
of effective hedges are reflected in revenue from oil and gas production and cash flows from
operations. Instruments not qualifying for hedge accounting are recorded in the balance sheet at
fair value and changes in fair value are recognized in earnings through derivative expense
(income). Typically, a small portion of our derivative contracts are determined to be ineffective.
This is because oil and
natural gas price changes in the markets in which we sell our products are not 100%
correlative to changes in the underlying price basis indicative in the derivative contract.
Monthly settlements of ineffective hedges are recognized in earnings through derivative expense
(income) and cash flows from operations.
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We have entered into fixed-price swaps with various counterparties for a portion of our
expected 2011, 2012 and 2013 oil and natural gas production from the Gulf Coast Basin. The
fixed-price oil swap settlements are based upon an average of the New York Mercantile Exchange
(NYMEX) closing price for WTI during the entire calendar month. Some of our fixed-price gas swap
settlements are based on an average of NYMEX prices for the last three days of a respective month
and some are based on the NYMEX price for the last day of a respective month. Swaps typically
provide for monthly payments by us if prices rise above the swap price or to us if prices fall
below the swap price. Our outstanding fixed-price swap contracts are with J.P. Morgan Chase Bank,
N.A., The Toronto-Dominion Bank, Barclays Bank PLC, BNP Paribas, the Bank of Nova Scotia and
Natixis.
During 2009 and 2008, a portion of our oil and natural gas production was hedged with
zero-premium collars. 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 on an average
of the NYMEX closing price for WTI during the entire calendar month. The collar 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.
During 2008, a portion of our natural gas production was also hedged with put contracts. Put
contracts are purchased at a rate per unit of hedged production that fluctuates with the commodity
futures market. The historical cost of the put contracts represents our maximum cash exposure. We
are not obligated to make any further payments under the put contracts regardless of future
commodity price fluctuations. Under put contracts, monthly payments are made to us if NYMEX prices
fall below the agreed upon floor price, while allowing us to fully participate in commodity prices
above the floor.
During the years ended December 31, 2010, 2009 and 2008, certain of our derivative contracts
were determined to be partially ineffective because of differences in the relationship between the
fixed price in the derivative contract and actual prices realized. During the second half of 2008,
as a result of extended shut-ins of production after Hurricanes Gustav and Ike, our September 2008
crude oil and natural gas production levels were below the volumes that we had hedged.
Consequently, some of our crude oil and natural gas hedges for September 2008 were deemed to be
ineffective.
All of our derivative instruments at December 31, 2010 and December 31, 2009 were designated
as effective cash flow hedges. The following tables disclose the location and fair value amounts
of derivative instruments reported in our balance sheet at December 31, 2010 and December 31, 2009.
Fair Value of Derivative Instruments at December 31, 2010 | ||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||
Description | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||||||
Commodity contracts |
Current assets: Fair value of hedging contracts |
$ | 12,955 | Current liabilities: Fair value of hedging contracts |
($32,144 | ) | ||||||||||
Long-term assets: Fair value of hedging contracts |
| Long-term liabilities: Fair value of hedging contracts |
(3,606 | ) | ||||||||||||
$ | 12,955 | ($35,750 | ) | |||||||||||||
Fair Value of Derivative Instruments at December 31, 2009 | ||||||||||||||||
Asset Derivatives | Liability Derivatives | |||||||||||||||
Description | Balance Sheet Location | Fair Value | Balance Sheet Location | Fair Value | ||||||||||||
Commodity contracts |
Current assets: Fair value of hedging contracts |
$ | 16,223 | Current liabilities: Fair value of hedging contracts |
($34,859 | ) | ||||||||||
Long-term assets: Fair value of hedging contracts |
1,771 | Long-term liabilities: Fair value of hedging contracts |
(7,721 | ) | ||||||||||||
$ | 17,994 | ($42,580 | ) | |||||||||||||
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The following table discloses the effect of derivative instruments in the statement of
operations for the years ended December 31, 2010, 2009 and 2008.
The Effect of Derivative Instruments on the Statement of Operations for the Years Ended December 31, 2010, 2009 and 2008 | ||||||||||||||||||||
Amount of Gain | ||||||||||||||||||||
Derivatives in | (Loss) Recognized | Gain (Loss) Reclassified from | ||||||||||||||||||
Cash Flow Hedging | in OCI on | Accumulated OCI into Income | Gain (Loss) Recognized in Income on | |||||||||||||||||
Relationships | Derivative (a) | (Effective Portion) (b) | Derivative (Ineffective Portion) | |||||||||||||||||
2010 | Location | 2010 | Location | 2010 | ||||||||||||||||
Commodity contracts |
$ | 1,176 | Operating revenue - oil/gas production | $ | 9,631 | Derivative income, net | $ | 3,265 | ||||||||||||
Total |
$ | 1,176 | $ | 9,631 | $ | 3,265 | ||||||||||||||
2009 | 2009 | 2009 | ||||||||||||||||||
Commodity contracts |
($100,292 | ) | Operating revenue - oil/gas production | $ | 163,176 | Derivative income, net | $ | 3,061 | ||||||||||||
Total |
($100,292 | ) | $ | 163,176 | $ | 3,061 | ||||||||||||||
2008 | 2008 | 2008 | ||||||||||||||||||
Commodity contracts |
$ | 95,647 | Operating revenue - oil/gas production | ($19,162 | ) | Derivative income, net | $ | 3,327 | ||||||||||||
Total |
$ | 95,647 | ($19,162 | ) | $ | 3,327 | ||||||||||||||
(a) | Net of related tax effect. | |
(b) | For the year ended December 31, 2010, effective hedging contracts decreased oil revenue by $29,047 and increased gas revenue by $38,678. For the year ended December 31, 2009, effective hedging contracts increased oil revenue by $61,747 and increased gas revenue by $101,429. For the year ended December 31, 2008, effective hedging contracts decreased oil revenue by $34,435 and increased gas revenue by $15,273. |
On March 3, 2009, we unwound all of our then existing crude oil hedges for the period
from April 2009 through December 2009, resulting in proceeds of approximately $59,007. On March 6,
2009, we unwound two of our natural gas hedges for the period from April 2009 through December
2009, resulting in proceeds of approximately $53,814. These amounts (net of the ineffective
portion and related deferred income tax effect) were recorded in accumulated other comprehensive
income in 2009. As the original time periods for these contracts expired, applicable amounts were
reclassified into earnings.
At December 31, 2010, we had an accumulated other comprehensive loss of $14,204, net of tax,
which related to the fair value of our 2011 and 2012 swap contracts that were outstanding as of
December 31, 2010. We believe that approximately $12,156 of the accumulated other comprehensive
loss will be reclassified into earnings in the next twelve months.
The following table illustrates our hedging positions for calendar years 2011, 2012 and 2013
as of February 22, 2011:
Fixed-Price Swaps | ||||||||||||||||
Natural Gas | Oil | |||||||||||||||
Daily | Daily | |||||||||||||||
Volume | Swap | Volume | Swap | |||||||||||||
(MMBtus/d) | Price | (Bbls/d) | Price | |||||||||||||
2011
|
10,000 | (a) | $ | 4.565 | 1,000 | $ | 70.05 | |||||||||
2011
|
20,000 | 5.200 | 1,000 | 78.20 | ||||||||||||
2011
|
10,000 | 6.830 | 1,000 | 80.20 | ||||||||||||
2011
|
1,000 | 83.00 | ||||||||||||||
2011
|
1,000 | 83.05 | ||||||||||||||
2011
|
1,000 | (b) | 85.20 | |||||||||||||
2011
|
1,000 | 85.25 | ||||||||||||||
2011
|
1,000 | 89.00 | ||||||||||||||
2011
|
1,000 | (c) | 97.75 | |||||||||||||
2012
|
10,000 | 5.035 | 1,000 | 90.30 | ||||||||||||
2012
|
10,000 | 5.040 | 1,000 | 90.41 | ||||||||||||
2012
|
1,000 | 90.45 | ||||||||||||||
2012
|
1,000 | 95.50 | ||||||||||||||
2012
|
1,000 | 97.60 | ||||||||||||||
2012
|
1,000 | 100.00 | ||||||||||||||
2013
|
1,000 | 97.15 |
(a) | February December | |
(b) | January June | |
(c) | July December |
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NOTE 9 FAIR VALUE MEASUREMENTS:
U.S. GAAP establishes a fair value hierarchy which has three levels based on the reliability
of the inputs used to determine the fair value. These levels include: Level 1, defined as inputs
such as unadjusted quoted prices in active markets for identical assets or liabilities; Level 2,
defined as inputs other than quoted prices in active markets that are either directly or indirectly
observable; and Level 3, defined as unobservable inputs for use when little or no market data
exists, therefore requiring an entity to develop its own assumptions.
As of December 31, 2010, we held certain financial assets and liabilities that are required to
be measured at fair value on a recurring basis, including our commodity derivative instruments and
our investments in money market funds. We utilize the services of an independent third party to
assist us in valuing our derivative instruments. We used the income approach in determining the
fair value of our derivative instruments utilizing a proprietary pricing model. The model accounts
for the credit risk of Stone and its counterparties in the discount rate applied to estimated
future cash inflows and outflows. Our swap contracts are included within the Level 2 fair value
hierarchy. For a more detailed description of our derivative instruments, see Note 8 Derivative
Instruments and Hedging Activities. We used the market approach in determining the fair value of
our investments in money market funds, which are included within the Level 1 fair value hierarchy.
The following tables present our assets and liabilities that are measured at fair
value on a recurring basis.
Fair Value Measurements at December 31, 2010 | ||||||||||||||||
Quoted Prices | ||||||||||||||||
in Active Markets | ||||||||||||||||
for Identical | Significant Other | Significant | ||||||||||||||
Assets | Observable Inputs | Unobservable Inputs | ||||||||||||||
Assets | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Money market funds |
$ | 7,306 | $ | 7,306 | $ | | $ | | ||||||||
Hedging contracts |
12,955 | | 12,955 | | ||||||||||||
Total |
$ | 20,261 | $ | 7,306 | $ | 12,955 | $ | | ||||||||
Fair Value Measurements at December 31, 2010 | ||||||||||||||||
Quoted Prices | ||||||||||||||||
in Active Markets | ||||||||||||||||
for Identical | Significant Other | Significant | ||||||||||||||
Liabilities | Observable Inputs | Unobservable Inputs | ||||||||||||||
Liabilities | Total | (Level 1) | (Level 2) | (Level 3) | ||||||||||||
Hedging contracts |
($35,750 | ) | $ | | ($35,750 | ) | $ | | ||||||||
Total |
($35,750 | ) | $ | | ($35,750 | ) | $ | | ||||||||
The fair value of cash and cash equivalents, accounts receivable, accounts payable to vendors
and our variable-rate bank debt approximated book value at December 31, 2010 and 2009. As of
December 31, 2010, the fair value of our $375,000
85/8% Senior Notes due 2017 was approximately
$380,625. As of December 31, 2009, the fair value of our $200,000 81/4% Senior Subordinated Notes
due 2011 was approximately $200,000. In the first quarter of 2010, we
used the proceeds from the 85/8% Senior Notes offering to purchase and redeem our 81/4% Senior Subordinated Notes due 2011. As of
December 31, 2010 and 2009, the fair value of our $200,000 63/4% Senior Subordinated Notes due 2014
was approximately $197,000 and $178,000, respectively. The fair values of our outstanding notes
were determined based upon quotes obtained from brokers.
We applied fair value concepts in recording the assets and liabilities acquired in our
acquisition of Bois dArc (see Note 6 Acquisitions and Divestitures). In determining the fair
value of Bois dArcs most significant assets, proved and unevaluated oil and gas properties, we
used elements of both the income and market approaches. Future income for oil and gas properties
was estimated based on proved, probable, and possible reserve and prospective resource volumes and
quoted commodity prices in the futures markets. We then applied appropriate discount rates based
on the risk profile of the respective reserve categories. Resulting values from the income
approach were compared to ranges of prices paid in the acquisition of similar oil and gas
properties in other transactions. Values determined under the income approach were within market
ranges.
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NOTE 10 ASSET RETIREMENT OBLIGATIONS:
Asset retirement obligations (ARO) relate to the removal of facilities and tangible
equipment at the end of a propertys useful life. U.S. GAAP requires that the fair value of a
liability to retire an asset be recorded on the balance sheet and that the corresponding cost is
capitalized in oil and gas properties. The ARO liability is accreted to its future value and the
capitalized cost is depreciated consistent with the UOP method. The estimate of our asset
retirement obligations does not give consideration to the value the related assets could have to
other parties.
The change in our ARO during 2010, 2009 and 2008 is set forth below:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Asset retirement obligations as of
the beginning of the year, including
current portion |
$ | 320,599 | $ | 275,628 | $ | 289,790 | ||||||
Liabilities incurred |
1,528 | 3,035 | 2,779 | |||||||||
Liabilities settled |
(36,392 | ) | (67,858 | ) | (60,642 | ) | ||||||
Liabilities assumed |
| | 128,023 | |||||||||
Divestment of properties |
(692 | ) | (5,941 | ) | (32,890 | ) | ||||||
Accretion expense |
34,469 | 39,306 | 17,392 | |||||||||
Revision of estimates |
54,408 | 76,429 | (68,824 | ) | ||||||||
Asset retirement obligations as of
the end of the year, including
current portion |
$ | 373,920 | $ | 320,599 | $ | 275,628 | ||||||
In October 2010, we received notification from the Bureau of Ocean Energy Management,
Regulation and Enforcement (BOEMRE) indicating that certain identified wells and facilities
operated by us will need to be retired on a timing schedule, which was accelerated from the timing
estimated in calculating liabilities for asset retirement obligations at December 31, 2009. In
February 2011, we submitted an abandonment plan addressing the identified wells and facilities.
The BOEMRE has indicated they will issue a final order upon review of the plan. During 2010, we
increased our asset retirement obligations in the amount of $54,408 for the estimated impact of the
accelerated timing of the retirement of these assets and other factors. The final order will
ultimately determine the impact on our asset retirement obligations and could result in an
additional upward or downward revision.
Primarily due to changes in estimated reserve lives, the timing on a substantial portion of
our asset retirement obligations was revised in the fourth quarter of 2009 leading to a
redetermination of the present value of these obligations. In this redetermination, our credit
adjusted risk free rate was decreased to account for current credit conditions contributing to a
significant upward revision of our asset retirement obligations.
Due to falling commodity prices and hurricanes, the timing of a substantial portion of our
asset retirement obligations was revised in the fourth quarter of 2008 leading to a redetermination
of the present value of these obligations. In this redetermination, our credit adjusted risk free
interest rate was increased to account for current credit conditions, resulting in a significant
downward revision to our asset retirement obligations.
NOTE 11 INCOME TAXES:
An analysis of our deferred taxes follows:
As of December 31, | ||||||||
2010 | 2009 | |||||||
Tax effect
of temporary differences: |
||||||||
Oil and gas properties full cost |
($224,624 | ) | ($137,797 | ) | ||||
Hurricane insurance receivable |
| (16,316 | ) | |||||
Asset retirement obligations |
134,611 | 112,210 | ||||||
Stock compensation |
4,932 | 4,296 | ||||||
Hedges |
8,205 | 8,605 | ||||||
Other |
4,923 | 7,817 | ||||||
($71,953 | ) | ($21,185 | ) | |||||
We estimate that we have incurred approximately $5,808 of current federal income tax expense
for the year ended December 31, 2010. We have a $239 current income tax payable at December 31,
2010.
F-20
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A reconciliation between the statutory federal income tax rate and our effective income tax
rate as a percentage of income before income taxes follows:
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Income tax expense computed at the statutory federal income tax rate |
35.0 | % | (35.0 | %) | (35.0 | %) | ||||||
Domestic production activities deduction |
(0.6 | ) | | | ||||||||
State taxes and other |
2.6 | 0.2 | | |||||||||
Goodwill impairment |
| | 10.9 | |||||||||
Statutory depletion |
(0.1 | ) | | (0.1 | ) | |||||||
Effective income tax rate |
36.9 | % | (34.8 | %) | (24.2 | %) | ||||||
In 2010 and 2009, we recognized a tax deduction for domestic production activities pursuant to
Internal Revenue Code Section 199.
Income taxes allocated to accumulated other comprehensive income related to oil and gas hedges
amounted to $292, ($54,003) and $51,502 for the years ended December 31, 2010, 2009 and 2008,
respectively.
As of December 31, 2010 and 2009, we had unrecognized tax benefits of $425 and $25,711,
respectively. If recognized, all of our unrecognized tax benefits as of December 31, 2010 would
impact our effective tax rate. A reconciliation of the total amounts of unrecognized tax benefits
follows:
Total unrecognized tax benefits as of December 31, 2009 |
$ | 25,711 | ||
Increases (decreases) in unrecognized tax benefits as a result of: |
||||
Tax positions taken during a prior period |
425 | |||
Tax positions taken during the current period |
| |||
Settlements with taxing authorities |
(24,533 | ) | ||
Lapse of applicable statute of limitations |
(1,178 | ) | ||
Total unrecognized tax benefits as of December 31, 2010 |
$ | 425 | ||
Our unrecognized tax benefits pertain to proposed state income tax audit adjustments. We
believe that our unrecognized tax benefits may be reduced to zero within the next 12 months upon
completion and ultimate settlement of the state examinations.
It is our policy to classify interest and penalties associated with underpayment of income
taxes as interest expense and general and administrative expenses, respectively. We have
recognized ($1,157) and $3,171 of interest expense related to uncertain tax positions for the years
ended December 31, 2010 and 2009, respectively. We have not recognized any penalties in connection
with our uncertain tax positions. The liabilities for unrecognized tax benefits and accrued
interest payable are components of other current liabilities on our balance sheet.
The tax years 2008 through 2010 remain subject to examination by major tax jurisdictions.
NOTE 12 LONG-TERM DEBT:
Long-term debt consisted of the following:
As of December 31, | ||||||||
2010 | 2009 | |||||||
81/4% Senior Subordinated Notes due 2011 |
$ | | $ | 200,000 | ||||
63/4% Senior Subordinated Notes due 2014 |
200,000 | 200,000 | ||||||
85/8% Senior Notes due 2017 |
375,000 | | ||||||
Bank debt |
| 175,000 | ||||||
Total long-term debt |
$ | 575,000 | $ | 575,000 | ||||
Bank Debt
On August 28, 2008, we entered into an amended and restated revolving credit facility totaling
$700,000, maturing on July 1, 2011, with a syndicated bank group. On January 26, 2010, we
completed a public offering of $275,000 aggregate principal amount of 85/8% Senior Notes due 2017.
Upon completion of the offering, our borrowing base under our bank credit facility was
automatically reduced from $425,000 to $395,000. On November 17, 2010, we completed a public
offering of an additional $100,000 aggregate principal amount of the 85/8% Senior Notes due 2017.
Upon completion of this offering, our
F-21
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borrowing base under our bank credit facility was automatically reduced from $395,000 to $365,000.
At December 31, 2010,
we had no outstanding borrowings under our bank credit facility and letters of credit totaling
$63,145 had been issued under the facility. As of February 22, 2011, letters of credit totaling
$63,145 had been issued pursuant to the facility, leaving $301,855 of availability under the
facility.
The borrowing base under the credit facility is redetermined semi-annually, in May and
November, by the lenders taking into consideration the estimated value of our oil and gas
properties and those of our direct and indirect material subsidiaries in accordance with the
lenders customary practices for oil and gas loans. In addition, we and the lenders each have
discretion at any time, but not more than two additional times in any calendar year, to have the
borrowing base redetermined. If a reduction in our borrowing base were to fall below any
outstanding balances under the credit facility plus any outstanding letters of credit, our
agreement with the banks allows us one of three options to cure the borrowing base deficiency: (1)
repay amounts outstanding sufficient to cure the deficiency within 10 days after our written
election to do so; (2) add additional oil and gas properties acceptable to the banks to the
borrowing base and take such actions necessary to grant the banks a mortgage in the properties
within thirty days after our written election to do so or (3) arrange to pay the deficiency in
monthly installments over ninety days or some longer period acceptable to the banks not to exceed
six months.
Our bank credit facility is guaranteed by our only material subsidiary, Stone Offshore. Our
bank credit facility is collateralized by substantially all of Stones and Stone Offshores assets.
Stone and Stone Offshore are required to mortgage, and grant a security interest in, their oil and
gas reserves representing at least 80% of the discounted present value of the future net cash flows
from their oil and gas reserves reviewed in determining the borrowing base. At Stones option,
loans under our bank credit facility will bear interest at a rate based on the adjusted London
Interbank Offering Rate plus an applicable margin, or a rate based on the prime rate or Federal
funds rate plus an applicable margin.
Under the financial covenants of our bank credit facility, we must (i) maintain a ratio of
consolidated debt to consolidated EBITDA, as defined in the credit agreement, for the preceding
four quarterly periods of not greater than 3.25 to 1 and (ii) maintain a ratio of EBITDA to
consolidated Net Interest, as defined in the credit agreement, for the preceding four quarterly
periods of not less than 3.0 to 1.0. As of December 31, 2010, our debt to EBITDA Ratio was 1.43 to
1 and our EBITDA to consolidated Net Interest Ratio was approximately 41.72 to 1. In addition, our
bank credit facility includes 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 but do allow
for limited stock repurchases.
Senior Notes
On January 26, 2010, we completed a public offering of $275,000 aggregate principal amount of
85/8% Senior Notes due 2017 (the 2017 Notes), which are fully and unconditionally guaranteed on a
senior unsecured basis by Stone Offshore and by certain future restricted subsidiaries of Stone.
The net proceeds from the offering after deducting underwriting discounts, commissions, fees and
expenses totaled $265,299. On November 17, 2010, we completed a public offering of an additional
$100,000 aggregate principal amount of our 2017 Notes. The net proceeds from this offering after
deducting underwriting discounts, commissions, fees and expenses totaled approximately $98,227.
The 2017 Notes rank equally in right of payment with all of our existing and future senior debt,
and rank senior in right of payment to all of our existing and future subordinated debt, including
our outstanding senior subordinated notes. The 2017 Notes mature on February 1, 2017, and interest
is payable on each February 1 and August 1, commencing on August 1, 2010. We may, at our option,
redeem all or part of the 2017 Notes at any time prior to February 1, 2014 at a make-whole
redemption price, and at any time on or after February 1, 2014 at fixed redemption prices. In
addition, prior to February 1, 2013, we may, at our option, redeem up to 35% of the 2017 Notes with
the cash proceeds of certain equity offerings. The 2017 Notes provide for certain covenants, which
include, without limitation, restrictions on liens, indebtedness, asset sales, dividend payments
and other restricted payments. The violation of any of these covenants could give rise to a
default, which if not cured could give the holder of the 2017 Notes a right to accelerate payment.
At December 31, 2010, $13,477 had been accrued in connection with the February 1, 2011 interest
payment.
Senior Subordinated Notes
On December 15, 2004, we issued $200,000 63/4% Senior Subordinated Notes due 2014 (the 2014
Notes). The 2014 Notes were sold at par value and we received net proceeds of $195,500. The 2014
Notes are subordinated to our senior unsecured credit facility. There is no sinking fund requirement. Beginning December 15, 2009, the 2014 Notes are redeemable at our option, in whole or in
part, at 103.375% of their principal amount and thereafter at prices declining annually to 100% on
and after December 15, 2012. The 2014 Notes provide for certain covenants, which include, without
limitation, restrictions on liens, indebtedness, asset sales, dividend payments and other
restricted payments. The violation of any of these covenants could give rise to a default, which
if not cured could give the holder of the 2014 Notes a right to accelerate payment. At December
31, 2010, $563 had been accrued in connection with the June 15, 2011 interest payment. On August
28, 2008, we entered into a supplemental indenture governing the terms of our 2014 Notes. The 2014
Notes are now guaranteed by Stone Offshore on an unsecured senior subordinated basis.
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On December 5, 2001, we issued $200,000 81/4% Senior Subordinated Notes due 2011 (the 2011
Notes). In
January 2010 we used the proceeds from the 2017 Notes offering to purchase our 2011 Notes pursuant
to a tender offer and consent solicitation. In February 2010, the remaining 2011 Notes were
redeemed in full. The total cost of the redemption was $202,382 which included $200,483 to redeem
the notes plus accrued and unpaid interest of $1,899. The transaction
resulted in a charge to earnings of $1,820 in 2010.
Deferred Financing Cost and Interest Cost
Other assets at December 31, 2010 and 2009 included approximately $14,764 and $9,430,
respectively, of deferred financing costs, net of accumulated amortization. These costs at December
31, 2010 related primarily to the issuance of the 2017 Notes, the 2014 Notes and our bank credit
facility. The costs associated with the 2017 Notes and the 2014 Notes are being amortized over the
life of the notes using a method that applies effective interest rates of 8.8% and 7.1%,
respectively. The costs associated with our bank credit facility are being amortized over the term
of the facility.
Total interest cost incurred on all obligations for the years ended December 31, 2010, 2009
and 2008 was $42,975, $46,934 and $39,598 respectively.
NOTE 13 INVENTORY IMPAIRMENT:
For the years ended December 31, 2010 and 2009, we recorded a write-down of our tubular
inventory of $129 and $9,398, respectively. These charges were the result of the market value of
these tubulars falling below historical cost.
NOTE 14 STOCK-BASED COMPENSATION:
We record stock compensation expense under U.S. GAAP for stock options and other
equity-based compensation awards based on the fair value on the date of grant. Compensation expense for equity-based compensation awards is recognized in our financial statements
over the vesting period of the award.
For the year ended December 31, 2010, we incurred $8,467 of stock based compensation, of which
$8,268 related to restricted stock issuances, $199 related to stock option grants and of which a
total of approximately $2,775 was capitalized into oil and gas properties. For the year ended
December 31, 2009, we incurred $8,845 of stock based compensation, of which $7,624 related to
restricted stock issuances, $1,221 related to stock option grants and of which a total of
approximately $2,901 was capitalized into oil and gas properties. For the year ended December 31,
2008, we incurred $13,086 of stock based compensation, of which $10,334 related to restricted stock
issuances, $2,572 related to stock option grants and $180 related to employee bonus stock awards
and of which a total of approximately $4,681 was capitalized into oil and gas properties. Because
of the non-cash nature of stock based compensation, the expensed portion of stock based
compensation is added back to the net income (loss) in arriving at net cash provided by operating
activities in our statement of cash flows. The capitalized portion is not included in net cash
used in investing activities.
Under our 2009 Amended and Restated Stock Incentive Plan (the 2009 Plan), we may grant both
incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that
are not qualified as incentive stock options to all employees and directors. All such options must
have an exercise price of not less than the fair market value of the common stock on the date of
grant and may not be re-priced without stockholder approval. Stock options to all employees vest
ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock
options issued to non-employee directors vest ratably over a three-year service-vesting period and
expire ten years subsequent to award. In addition, the 2009 Plan provides that shares available
under the 2009 Plan may be granted as restricted stock. Restricted stock typically vests over a
three-year period.
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Stock Options. There were no stock option grants during the year ended December 31, 2010.
Stock options granted and related fair values for the years ended December 31, 2009 and 2008 are
listed in the following table. The fair value was determined using the Black-Scholes option
pricing model with the following assumptions:
Year Ended December 31, | ||||||||
2009 | 2008 | |||||||
(Amounts in table represent | ||||||||
actual values except where | ||||||||
indicated otherwise) | ||||||||
Stock options granted |
64,474 | 40,000 | ||||||
Fair value of stock options granted ($ in
thousands) |
$ | 321 | $ | 980 | ||||
Weighted average grant date fair value |
$ | 4.98 | $ | 24.51 | ||||
Assumptions: |
||||||||
Dividend yield |
0.00 | % | 0.00 | % | ||||
Expected volatility |
44.66 | % | 37.70 | % | ||||
Risk-free rate |
2.39 | % | 3.65 | % | ||||
Expected option life |
10.0 years | 10.0 years | ||||||
Forfeiture rate |
0.00 | % | 0.00 | % |
Expected volatility and expected option life are based on a historical average. The risk-free
rate is based on quoted rates on zero-coupon Treasury Securities for terms consistent with the
expected option life.
A summary of stock option activity under the Plan during the year ended December 31, 2010 is
as follows (amounts in table represent actual values except where indicated otherwise):
Aggregate | ||||||||||||||||
Number | Wgtd. Avg. | Intrinsic | ||||||||||||||
of | Exercise | Wgtd. Avg. | Value | |||||||||||||
Options | Price | Term | (in thousands) | |||||||||||||
Options outstanding, beginning of period |
495,283 | $ | 39.61 | |||||||||||||
Granted |
| | ||||||||||||||
Exercised |
| | ||||||||||||||
Forfeited |
(6,190 | ) | 40.85 | |||||||||||||
Expired |
(4,399 | ) | 57.76 | |||||||||||||
Options outstanding, end of period |
484,694 | 39.43 | 3.8 years | $ | 880 | |||||||||||
Options exercisable, end of period |
396,115 | 43.21 | 3.4 years | 176 | ||||||||||||
Options unvested, end of period |
88,579 | 22.50 | 6.9 years | 704 | ||||||||||||
Exercise prices for stock options outstanding at December 31, 2010 range from $6.97 to $61.58.
A summary of stock option activity under the Plan during the year ended December 31, 2009 is
as follows (amounts in table represent actual values except where indicated otherwise):
Aggregate | ||||||||||||||||
Number | Wgtd. Avg. | Intrinsic | ||||||||||||||
of | Exercise | Wgtd. Avg. | Value | |||||||||||||
Options | Price | Term | (in thousands) | |||||||||||||
Options outstanding, beginning of period |
510,779 | $ | 45.21 | |||||||||||||
Granted |
64,474 | 8.64 | ||||||||||||||
Exercised |
| | ||||||||||||||
Forfeited |
(14,470 | ) | 33.59 | |||||||||||||
Expired |
(65,500 | ) | 54.15 | |||||||||||||
Options outstanding, end of period |
495,283 | 39.61 | 4.7 years | $ | 607 | |||||||||||
Options exercisable, end of period |
363,709 | 44.40 | 4.1 years | | ||||||||||||
Options unvested, end of period |
131,574 | 26.37 | 7.3 years | 607 | ||||||||||||
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Table of Contents
A summary of stock option activity under the Plan during the year ended December 31, 2008 is
as follows (amounts in table represent actual values except where indicated otherwise):
Aggregate | ||||||||||||||||
Number | Wgtd. Avg. | Intrinsic | ||||||||||||||
of | Exercise | Wgtd. Avg. | Value | |||||||||||||
Options | Price | Term | (in thousands) | |||||||||||||
Options outstanding, beginning of period |
931,589 | $ | 43.72 | |||||||||||||
Granted |
40,000 | 44.67 | ||||||||||||||
Exercised |
(447,330 | ) | 41.84 | $ | 9,514 | |||||||||||
Forfeited |
(13,480 | ) | 54.74 | |||||||||||||
Expired |
| | ||||||||||||||
Options outstanding, end of period |
510,779 | 45.21 | 5.0 years | | ||||||||||||
Options exercisable, end of period |
382,679 | 45.34 | 4.3 years | | ||||||||||||
Options unvested, end of period |
128,100 | 44.83 | 7.2 years | | ||||||||||||
Restricted Stock. The fair value of restricted shares is determined based on the average of
the high and low prices on the issuance date and assumes a 5% forfeiture rate in 2010 and 2009.
During the year ended December 31, 2010, we issued 395,869 shares of restricted stock valued at
$6,251. During the year ended December 31, 2009, we issued 538,635 shares of restricted stock
valued at $5,831. During the year ended December 31, 2008, we issued 278,646 shares of restricted
stock valued at $13,352.
A summary of the restricted stock activity under the Plan for the years ended December 31,
2010, 2009 and 2008 is as follows (amounts in table represent actual values):
2010 | 2009 | 2008 | ||||||||||||||||||||||
Number of | Wgtd. Avg. | Number of | Wgtd. Avg. | Number of | Wgtd. Avg. | |||||||||||||||||||
Restricted | Fair Value | Restricted | Fair Value | Restricted | Fair Value | |||||||||||||||||||
Shares | Per Share | Shares | Per Share | Shares | Per Share | |||||||||||||||||||
Restricted stock outstanding,
beginning of period |
751,437 | $ | 20.68 | 408,383 | $ | 43.31 | 311,486 | $ | 39.86 | |||||||||||||||
Issuances |
395,869 | 15.79 | 538,635 | 10.83 | 278,646 | 47.92 | ||||||||||||||||||
Lapse of restrictions |
(343,657 | ) | 23.09 | (177,123 | ) | 41.73 | (167,818 | ) | 44.62 | |||||||||||||||
Forfeitures |
(20,043 | ) | 18.07 | (18,458 | ) | 26.74 | (13,931 | ) | 44.99 | |||||||||||||||
Restricted stock outstanding,
end of period |
783,606 | $ | 17.24 | 751,437 | $ | 20.68 | 408,383 | $ | 43.31 | |||||||||||||||
As of December 31, 2010, there was $6,784 of unrecognized compensation cost related to all
non-vested share-based compensation arrangements under the Plan. That cost is being amortized on a
straight-line basis over the vesting period and is expected to be recognized over a
weighted-average period of 1.7 years. Subsequent to December 31, 2010, 557,620 shares of restricted
stock were granted under the Plan.
Under U.S. GAAP, if tax deductions exceed book compensation expense, then excess tax benefits
are credited to additional paid-in capital to the extent realized. If book compensation expense
exceeds tax deductions, the tax deficit results in either a reduction in additional paid-in capital
or an increase in income tax expense depending on certain circumstances. Credits to additional
paid-in capital for net tax benefits were ($2), ($1,647) and $2,740 in 2010, 2009 and 2008,
respectively.
NOTE 15 SHARE REPURCHASE PROGRAM:
On September 24, 2007, our Board of Directors authorized a share repurchase program for an
aggregate amount of up to $100,000. The shares may be repurchased from time to time in the open
market or through privately negotiated transactions. The repurchase program is subject to business
and market conditions, and may be suspended or discontinued at any time. Through December 31,
2010, 300,000 shares had been repurchased under this program at a total cost of $7,071, or an
average price of $23.57 per share. During the year ended December 31, 2009, 100,000 shares were
repurchased under this program, and during the year ended December 31, 2008, 200,000 shares were
repurchased under this program. No shares were repurchased during the year ended December 31,
2010.
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NOTE 16 COMMITMENTS AND CONTINGENCIES:
Lease Commitments
We lease office facilities in New Orleans, Louisiana, Houston, Texas and Morgantown, West
Virginia under the terms of long-term, non-cancelable leases expiring on various dates through
2015. We also lease certain equipment on our oil and gas properties typically on a month-to-month
basis. The minimum net annual commitments under all leases, subleases and contracts with
non-cancelable terms in excess of 12 months at December 31, 2010 were as follows:
2012
|
$ | 507 | ||
2013
|
538 | |||
2014
|
409 | |||
2015
|
425 |
Payments related to our lease obligations for the years ended December 31, 2010, 2009 and 2008
were approximately $703, $738 and $489, respectively.
Other Commitments
We are contingently liable to surety insurance companies in the amount of $60,477 relative to
bonds issued on our behalf to the BOEMRE, federal and state agencies and certain third parties from
which we purchased oil and gas working interests. The bonds represent guarantees by the surety
insurance companies that we will operate in accordance with applicable rules and regulations and
perform certain plugging and abandonment obligations as specified by applicable working interest
purchase and sale agreements.
In connection with our exploration and development efforts, we are contractually committed to
the use of drilling rigs and the acquisition of seismic data in the aggregate amount of $13,428 to
be incurred over the next year.
The Oil Pollution Act of 1990 (OPA) imposes ongoing requirements on a responsible party,
including the preparation of oil spill response plans and proof of financial responsibility to
cover environmental cleanup and restoration costs that could be incurred in connection with an oil
spill. Under OPA and a final rule adopted by the BOEMRE in August 1998, responsible parties of
covered offshore facilities that have a worst case oil spill of more than 1,000 barrels must
demonstrate financial responsibility in amounts ranging from at least $10,000 in specified state
waters to at least $35,000 in Outer Continental Shelf (OCS) waters, with higher amounts of up to
$150,000 in certain limited circumstances where the BOEMRE believes such a level is justified by
the risks posed by the operations, or if the worst case oil-spill discharge volume possible at the
facility may exceed the applicable threshold volumes specified under the BOEMREs final rule. We
do not anticipate that we will experience any difficulty in continuing to satisfy the BOEMREs
requirements for demonstrating financial responsibility under OPA and the BOEMREs regulations.
Litigation
We are also named as a defendant in certain lawsuits and are a party to certain regulatory
proceedings arising in the ordinary course of business. We do not expect these matters,
individually or in the aggregate, will have a material adverse effect on our financial condition.
Franchise Tax Action. We have been served with several petitions filed by the Louisiana
Department of Revenue (LDR) in Louisiana state court claiming additional franchise taxes due. In
addition, we have received preliminary assessments from the LDR for additional franchise taxes
resulting from audits of a subsidiary. These assessments all relate to the LDRs assertion that
sales of crude oil and natural gas from properties located on the OCS, 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. Total asserted claims plus estimated
accrued interest amount to approximately $20,450. The franchise tax years 2007 through 2010 for
Stone remain subject to examination, which potentially exposes us to additional estimated
assessments of $7,000 including accrued interest.
Ad Valorem Tax Suit. In August 2009, Gene P. Bonvillain, in his capacity as Assessor for the
Parish of Terrebonne, State of Louisiana, filed civil action No. 90-03540 and other consolidated
cases in the United States District Court for the Eastern District of Louisiana against
approximately thirty oil and gas companies, including Stone, and their respective chief executive
officers for allegedly unpaid ad valorem taxes. The amount originally alleged to be due by Stone
for the years 1998 through 2008 was $11,300. The defendants were subsequently served and filed
motions to dismiss this litigation pursuant to Rule 12(b)(6) of the Federal Rules of Civil
Procedure. On March 29, 2010, the trial court judge dismissed plaintiffs claims without
prejudice, with the dismissal to become effective within ten days unless plaintiff filed an amended
complaint correcting its deficiencies. On April 8, 2010, plaintiff filed a first amended complaint
without naming any of the chief executive officers as defendants and with an amount allegedly due
by Stone of not less than $3,500. Defendants filed motions to dismiss this
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litigation, and the trial court judge granted these motions to dismiss on July 26, 2010.
Subsequently, Bonvillain appealed the dismissal, and the appeal is currently pending before the
5th Circuit Court of Appeals. In its appellate brief, Bonvillain stated that its appeal
against Stone is hereby waived. On January 26, 2011, an order was entered formally dismissing
Stone from this appeal, and this matter is now concluded.
Lafourche Parish, Louisiana, Landowner Action. In December 2008, Stephen E. Coignet, et al.,
filed civil action No. 110741 in the 17th Judicial District Court, Lafourche Parish,
Louisiana, against Stone. Plaintiffs have since filed three supplemental petitions, including a
third supplemental and restated petition on October 25, 2010. Plaintiffs are landowners of
approximately sixty acres that are subject to mineral leases in favor of Stone. Plaintiffs allege
that Stone conducted its mineral operations imprudently resulting in damages to plaintiffs in
excess of $60,000. Plaintiffs expert witness provided his report, dated December 28, 2010,
stating his opinion that one well did not produce as much production as it should have, resulting
in a loss to plaintiffs in excess of $4,000, that imprudent operations destroyed hydrocarbon
bearing zones resulting in a loss to plaintiffs in excess of $20,000, and that imprudent
operation of a water injection secondary recovery project resulted in damages to plaintiffs of
approximately $4,755. There are also allegations of failure to protect from drainage from a well
on adjoining land, trespass, and various other breaches of the mineral leases. The Company
disagrees with plaintiffs contentions and intends to vigorously defend itself against these
claims.
NOTE 17 EMPLOYEE BENEFIT PLANS:
We have entered into deferred compensation and disability agreements with certain of our
officers and former officers. We have purchased a split-dollar life insurance policy to provide
certain retirement and death benefits for one of our officers and death benefits payable to us.
The aggregate death benefit of the policy was $448 at December 31, 2010, of which $325 was payable
to the officer or his beneficiaries and $123 was payable to us. Total cash surrender value of the
policy, net of related surrender charges at December 31, 2010, was approximately $27 and is
recorded in other assets. The benefits under the deferred compensation agreements vest after
certain periods of employment, and at December 31, 2010, the liability for such vested benefits was
approximately $976 and is recorded in other long-term liabilities.
The following is a brief description of each incentive compensation plan applicable to our
employees:
i. | The Amended and Restated Revised Annual Incentive Compensation Plan, which was adopted in November 2007, provides for annual cash incentive bonuses that are tied to the achievement of certain strategic objectives as defined by our board of directors on an annual basis. Stone incurred expenses of $5,888, $6,402, and $2,315, net of amounts capitalized, for each of the years ended December 31, 2010, 2009 and 2008, respectively, related to incentive compensation bonuses to be paid under the revised plan. | ||
ii. | At the 2009 Annual Meeting of Stockholders, the stockholders approved the 2009 Amended and Restated Stock Incentive Plan (the 2009 Plan). The 2009 Plan is an amendment and restatement of the companys 2004 Amended and Restated Stock Incentive Plan (the 2004 Plan) and it supersedes and replaces in its entirety the 2004 Plan. The 2009 Plan provides for the granting of incentive stock options and restricted stock awards or any combination as is best suited to the circumstances of the particular employee or nonemployee director. The number of shares subject to the 2009 Plan was increased by 1,500,000 shares from the 4,225,000 shares of common stock to be reserved for issuance pursuant to the 2004 plan. The 2009 Plan eliminates the automatic grant of stock options or restricted stock awards to Nonemployee Directors that was provided for in the 2004 Plan so that awards under the 2009 Plan are entirely at the discretion of the Board of Directors. Under the 2009 Plan, we may grant both incentive stock options qualifying under Section 422 of the Internal Revenue Code and options that are not qualified as incentive stock options to all employees and directors. All such options must have an exercise price of not less than the fair market value of the common stock on the date of grant and may not be re-priced without stockholder approval. Stock options to all employees vest ratably over a five-year service-vesting period and expire ten years subsequent to award. Stock options issued to non-employee directors vest ratably over a three-year service-vesting period and expire ten years subsequent to award. In addition, the 2009 Plan provides that shares available under the 2009 Plan may be granted as restricted stock. Restricted stock grants typically vest in two or more years at the discretion of the Compensation Committee of the board of directors. At December 31, 2010, we had approximately 1,018,518 additional shares available for issuance pursuant to the Plan. | ||
iii. | The Stone Energy 401(k) Profit Sharing Plan provides eligible employees with the option to defer receipt of a portion of their compensation and we may, at our discretion, match a portion or all of the employees deferral. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the directions of each employee. An employee is 20% vested in matching contributions (if any) for each year of service and is fully vested upon five years of service. For the years ended December 31, 2010, 2009 and 2008, Stone contributed $1,301, $1,161 and $1,119, respectively, to the plan. |
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iv. | The Stone Energy Corporation Deferred Compensation Plan provides eligible executives with the option to defer up to 100% of their compensation for a calendar year and we may, at our discretion, match a portion or all of the participants deferral based upon a percentage determined by the board of directors. To date there have been no matching contributions made by Stone. The amounts held under the plan are invested in various investment funds maintained by a third party in accordance with the direction of each participant. At December 31, 2010 and 2009, plan assets of $6,314 and $5,149, respectively, were included in other assets. An equal amount of plan liabilities were included in other long-term liabilities. | ||
v. | On April 7, 2009, we amended and restated our Executive Change of Control and Severance Plan effective as of December 31, 2008 (as so amended and restated, the Executive Plan). The amended and restated Executive Plan also replaced and superseded our Executive Change in Control and Severance Policy that was maintained for certain designated executives (specifically, the CEO and CFO). The Executive Plan will provide the companys officers that are terminated in the event of a change of control and upon certain other terminations of employment with change of control and severance benefits as defined in the Executive Plan. Executives who are terminated within the scope of the Executive Plan will be entitled to certain payments and benefits including the following: a base salary up to the date of termination; in the case of the CEO and CFO, a lump sum severance payment of 2.99 times the sum of his annual pay and any target bonus at the one hundred percent level; a lump sum amount representing a pro rata share of the bonus opportunity up to the date of termination at the then projected rate of payout; in the case of officers other than the CEO and CFO and an involuntary termination occurring outside a change of control period, a lump sum severance payment in an amount equal to the executives annual base salary; in the case of officers other than the CEO and CFO and an involuntary termination occurring during a change of control period, a lump sum severance payment in an amount equal to 2.99 times the executives annual base salary; continued health plan coverage for six months and outplacement services. In the case of the CEO and CFO, if the payments would be excess parachute payments, they will be reduced as necessary to avoid the 20% excise tax under Section 4999 of the Internal Revenue Code (the Code) but only if the executive is in a better net after-tax position after such reduction. Also, if a payment would be to a key employee for purposes of Section 409A of the Code, payment will be delayed until six months after his termination if required to comply with Section 409A. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a pro-rated portion of the projected bonus, if any, for the year of change of control. | ||
On December 7, 2007, our board of directors approved and adopted the Stone Energy Corporation Employee Change of Control Severance Plan (Employee Severance Plan), as amended and restated to comply with the final regulations under Section 409A of the Internal Revenue Code and to provide that said plan will remain in force and effect unless and until terminated by the board. The Employee Severance Plan amended and restated the companys previous Employee Change of Control Severance Plan dated November 16, 2006. The Employee Severance Plan covers all full-time employees other than officers. Severance is triggered by an involuntary termination of employment on and during the 6 month period following a change of control, including a resignation by the employee relating to a change in duties. Employees who are terminated within the scope of the Employee Severance Plan will be entitled to certain payments and benefits including the following: a lump sum equal to (1) his weekly pay times his full years of service, plus (2) one weeks pay for each full $10,000 of annual pay, but the sum of (1) and (2) cannot be less than 12 weeks of pay or greater than 52 weeks of pay; continued health plan coverage for six months; and a pro-rated portion of the employees targeted bonus for the year. Benefits paid upon a change of control, without regard to whether there is a termination of employment, include the following: lapse of restrictions on restricted stock, accelerated vesting and cash-out of all in-the-money stock options, a 401(k) plan employer matching contribution at the rate of 50%, and a lump sum cash payment equal to the product of (i) the number of restricted shares of company stock that the employee would have received under the companys stock plan but did not receive for the time-vested portion of his long-term stock incentive award, if any, for the calendar year in which the change of control occurs times (ii) the price per share of the companys common stock utilized in effecting the change of control, provided that such amount shall be prorated by multiplying such amount by the number of full months that have elapsed from January 1 of that calendar year to the effective date of the change of control and then dividing the result by twelve (12). |
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NOTE 18 OIL AND GAS RESERVE INFORMATION UNAUDITED:
Our estimated net proved oil and gas reserves at December 31, 2010 have been prepared in
accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are
based upon existing economic and operating conditions at the respective dates. In December 2008,
the SEC issued a final rule, Modernization of Oil and Gas Reporting, which adopted revisions to
the SECs oil and gas reporting requirements. Among other things, the revisions: (1) replaced the
single-day year-end pricing with a twelve-month average pricing assumption; (2) permit the
reporting of probable and possible reserves in addition to the existing requirement to disclose
proved reserves; (3) allow the use of new technologies to determine proved reserves if those
technologies have been demonstrated empirically to lead to reliable conclusions about reserve
volumes; (4) require the disclosure of the independence and qualifications of third party preparers
of reserves; and (5) require the filing of reports when a third party is relied upon to prepare or
audit reserve estimates. We were required to adopt the provisions of the new rule as of December
31, 2009. In January 2010, the FASB issued its final standard on oil and gas reserves estimation
and disclosures aligning its requirements with the SECs final rule. The new rules were considered
a change in accounting principle that is inseparable from a change in accounting estimate, which
did not require retroactive revision.
There are numerous uncertainties inherent in estimating quantities of proved reserves and in
providing the future rates of production and timing of development expenditures. The following
reserve data represents estimates only and should not be construed as being exact. In addition,
the present values should not be construed as the market value of the oil and gas properties or the
cost that would be incurred to obtain equivalent reserves.
The following table sets forth an analysis of the estimated quantities of net proved and
proved developed oil (including condensate) and natural gas reserves, all of which are located
onshore and offshore the continental United States. Estimated proved oil and natural gas reserves
at December 31, 2010 and 2009 are prepared in accordance with the SECs new rule, Modernization of
Oil and Gas Reporting.
Oil and | ||||||||||||
Oil | Natural Gas | Natural Gas | ||||||||||
(MBbls) | (MMcf) | (MMcfe) | ||||||||||
Estimated proved reserves as of December 31, 2007 |
31,586 | 213,083 | 402,598 | |||||||||
Revisions of previous estimates |
(4,416 | ) | (37,509 | ) | (64,007 | ) | ||||||
Extensions, discoveries and other additions |
625 | 6,246 | 9,996 | |||||||||
Purchase of producing properties |
14,680 | 164,408 | 252,489 | |||||||||
Sale of reserves |
(995 | ) | (12,265 | ) | (18,238 | ) | ||||||
Production |
(4,916 | ) | (34,409 | ) | (63,903 | ) | ||||||
Estimated proved reserves as of December 31, 2008 |
36,564 | 299,554 | 518,935 | |||||||||
Revisions of previous estimates |
1,964 | (53,423 | ) | (41,636 | ) | |||||||
Extensions, discoveries and other additions |
417 | 12,198 | 14,703 | |||||||||
Sale of reserves |
(402 | ) | (300 | ) | (2,714 | ) | ||||||
Production |
(6,207 | ) | (41,335 | ) | (78,577 | ) | ||||||
Estimated proved reserves as of December 31, 2009 |
32,336 | 216,694 | 410,711 | |||||||||
Revisions of previous estimates |
3,299 | 13,439 | 33,231 | |||||||||
Extensions, discoveries and other additions |
2,668 | 82,846 | 98,854 | |||||||||
Purchase of producing properties |
637 | 3,816 | 7,637 | |||||||||
Sale of reserves |
(23 | ) | (153 | ) | (289 | ) | ||||||
Production |
(5,714 | ) | (41,937 | ) | (76,221 | ) | ||||||
Estimated proved reserves as of December 31, 2010 |
33,203 | 274,705 | 473,923 | |||||||||
Estimated proved developed reserves: |
||||||||||||
as of December 31, 2008 |
28,410 | 227,857 | 398,317 | |||||||||
as of December 31, 2009 |
24,380 | 172,452 | 318,729 | |||||||||
as of December 31, 2010 |
25,000 | 174,876 | 324,876 | |||||||||
The following narrative provides the reasons for the significant changes in the quantities of
our estimated proved reserves by year.
Year Ended December 31, 2010. Revisions of previous estimates were the result of positive
reserve report pricing changes extending the economic limits of reservoirs (28 Bcfe) and well
performance (5 Bcfe). Extensions, discoveries and other additions were primarily the result of our
Appalachia drilling program (77 Bcfe) and our GOM drilling program primarily at Mississippi Canyon
Block 109 (18 Bcfe).
F-29
Table of Contents
Year Ended December 31, 2009. Revisions of previous estimates were almost entirely the result
of changes in reserve report prices for oil and natural gas increasing (in the case of oil) or
decreasing (in the case of gas) economic limits of reservoirs.
Year Ended December 31, 2008. Revisions of previous estimates were almost entirely the result
of negative reserve report pricing changes reducing the economic limits of reservoirs. Purchase of
producing properties consisted almost entirely of the acquisition of Bois dArc. On August 28,
2008, we completed the acquisition of Bois dArc in a cash and stock transaction totaling
approximately $1,653,312. Bois dArc was an independent exploration company engaged in the
discovery and production of oil and natural gas in the Gulf of Mexico. Sale of reserves consisted
primarily of the divestment of a small package of GOM properties.
The following tables present the standardized measure of future net cash flows related to
estimated proved oil and gas reserves together with changes therein, including a reduction for
estimated plugging and abandonment costs that are also reflected as a liability on the balance
sheet at December 31, 2010. You should not assume that the future net cash flows or the discounted
future net cash flows, referred to in the tables below, represent the fair value of our estimated
oil and gas reserves. Prior to December 31, 2009, we were required to 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. Effective December 31, 2009, the SEC issued a final rule which
changed prices used in reserves calculations. Prices are no longer based on a single-day,
period-end price. Rather, they are now based on either the preceding 12-months average price
based on closing prices on the first day of each month, or prices defined by existing contractual
arrangements. The 2010 average 12-month oil and gas prices net of differentials were $77.68 per
barrel of oil and $4.46 per Mcf of gas. The 2009 average 12-month oil and gas prices net of
differentials were $58.95 per barrel of oil and $3.49 per Mcf of gas. The average 2008 year-end
oil and gas prices net of differentials were $39.70 per barrel of oil and $5.87 per Mcf of gas.
Future production and development costs are based on current costs with no escalations. Estimated
future cash flows net of future income taxes have been discounted to their present values based on
a 10% annual discount rate.
Standardized Measure Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Future cash inflows |
$ | 3,803,004 | $ | 2,663,285 | $ | 3,210,283 | ||||||
Future production costs |
(1,191,718 | ) | (950,434 | ) | (1,131,548 | ) | ||||||
Future development costs |
(907,956 | ) | (912,500 | ) | (1,153,950 | ) | ||||||
Future income taxes |
(330,651 | ) | (38,845 | ) | (8,989 | ) | ||||||
Future net cash flows |
1,372,679 | 761,506 | 915,796 | |||||||||
10% annual discount |
(415,050 | ) | (146,519 | ) | (122,692 | ) | ||||||
Standardized measure of discounted future net cash flows |
$ | 957,629 | $ | 614,987 | $ | 793,104 | ||||||
Changes in Standardized Measure | ||||||||||||
Year Ended December 31, | ||||||||||||
2010 | 2009 | 2008 | ||||||||||
Standardized measure at beginning of year |
$ | 614,987 | $ | 793,104 | $ | 1,521,589 | ||||||
Sales and transfers of oil and gas produced, net of
production costs |
(487,418 | ) | (546,737 | ) | (618,618 | ) | ||||||
Changes in price, net of future production costs |
485,272 | 284,504 | (2,209,114 | ) | ||||||||
Extensions and discoveries, net of future production
and development costs |
270,629 | 21,249 | 37,201 | |||||||||
Changes in estimated future development costs, net of
development costs incurred during the period |
119,986 | 183,058 | 98,029 | |||||||||
Revisions of quantity estimates |
147,509 | (150,609 | ) | (220,387 | ) | |||||||
Accretion of discount |
64,836 | 79,904 | 203,715 | |||||||||
Net change in income taxes |
(196,219 | ) | (27,436 | ) | 509,621 | |||||||
Purchases of reserves in-place |
21,264 | | 1,514,487 | |||||||||
Sales of reserves in-place |
1,424 | 3,152 | (45,822 | ) | ||||||||
Changes in production rates due to timing and other |
(84,641 | ) | (25,202 | ) | 2,403 | |||||||
Net increase (decrease) in standardized measure |
342,642 | (178,117 | ) | (728,485 | ) | |||||||
Standardized measure at end of year |
$ | 957,629 | $ | 614,987 | $ | 793,104 | ||||||
F-30
Table of Contents
NOTE 19 SUMMARIZED QUARTERLY FINANCIAL INFORMATION UNAUDITED:
First Qtr. | Second Qtr. | |||||||||||||||||||||||
As | Adjust- | Adjust- | As | |||||||||||||||||||||
Reported | ment | As Adjusted | As Reported | ment | Adjusted | |||||||||||||||||||
2010 (a) |
||||||||||||||||||||||||
Operating revenue |
$ | 164,979 | $ | | $ | 164,979 | $ | 166,207 | $ | | $ | 166,207 | ||||||||||||
Income from operations |
45,992 | (1,856 | ) | 44,136 | 44,532 | (1,856 | ) | 42,676 | ||||||||||||||||
Net income attributable to Stone Energy |
26,624 | (1,206 | ) | 25,418 | 29,079 | (1,207 | ) | 27,872 | ||||||||||||||||
Basic earnings per share attributable to Stone Energy Corporation stockholders |
$ | 0.55 | ($0.03 | ) | $ | 0.52 | $ | 0.60 | ($0.03 | ) | $ | 0.57 | ||||||||||||
Diluted earnings per share attributable to Stone Energy Corporation stockholders |
$ | 0.55 | ($0.03 | ) | $ | 0.52 | $ | 0.60 | ($0.03 | ) | $ | 0.57 |
Third Qtr. | Fourth Qtr. | |||||||||||||||
As | Adjust- | |||||||||||||||
Reported | ment | As Adjusted | As Reported | |||||||||||||
2010 (a) |
||||||||||||||||
Operating revenue |
$ | 153,615 | $ | | $ | 153,615 | $ | 170,020 | ||||||||
Income from operations |
34,608 | (1,855 | ) | 32,753 | 39,673 | |||||||||||
Net income attributable to Stone Energy |
20,281 | (899 | ) | 19,382 | 23,757 | |||||||||||
Basic earnings per share attributable to Stone Energy Corporation stockholders |
$ | 0.42 | ($0.02 | ) | $ | 0.40 | $ | 0.49 | ||||||||
Diluted earnings per share attributable to Stone Energy Corporation stockholders |
$ | 0.42 | ($0.02 | ) | $ | 0.40 | $ | 0.49 |
First Qtr. | Second Qtr. | |||||||||||||||||||||||
As | Adjust- | Adjust- | ||||||||||||||||||||||
Reported | ment | As Adjusted | As Reported | ment | As Adjusted | |||||||||||||||||||
2009 (a) |
||||||||||||||||||||||||
Operating revenue |
$ | 142,943 | $ | | $ | 142,943 | $ | 170,312 | $ | | $ | 170,312 | ||||||||||||
Income (loss) from operations |
(343,368 | ) | (5,421 | ) | (348,789 | ) (b) | 45,679 | (1,573 | ) | 44,106 | ||||||||||||||
Net inc.(loss) attributable to Stone Energy |
(225,866 | ) | (3,523 | ) | (229,389 | ) (b) | 27,168 | (1,022 | ) | 26,146 | ||||||||||||||
Basic earnings (loss) per share attributable to Stone Energy Corporation stockholders |
($5.73 | ) | ($0.08 | ) | ($5.81 | ) | $ | 0.65 | ($0.03 | ) | $ | 0.62 | ||||||||||||
Diluted earnings (loss) per share attributable to Stone Energy Corporation stockholders |
($5.73 | ) | ($0.08 | ) | ($5.81 | ) | $ | 0.65 | ($0.03 | ) | $ | 0.62 |
Third Qtr. | Fourth Qtr. | |||||||||||||||||||||||
As | Adjust- | Adjust- | ||||||||||||||||||||||
Reported | ment | As Adjusted | As Reported | ment | As Adjusted | |||||||||||||||||||
2009 (a) |
||||||||||||||||||||||||
Operating revenue |
$ | 202,719 | $ | | $ | 202,719 | $ | 199,260 | $ | | $ | 199,260 | ||||||||||||
Income (loss) from operations |
82,886 | (1,572 | ) | 81,314 | (92,909 | ) | (1,573 | ) | (94,482 | ) (c) | ||||||||||||||
Net inc.(loss) attributable to Stone Energy |
51,053 | (1,022 | ) | 50,031 | (64,063 | ) | (1,023 | ) | (65,086 | ) (c) | ||||||||||||||
Basic earnings (loss) per share attributable to Stone Energy Corporation stockholders |
$ | 1.06 | ($0.02 | ) | $ | 1.04 | ($1.35 | ) | ($0.02 | ) | ($1.37 | ) | ||||||||||||
Diluted earnings (loss) per share attributable to Stone Energy Corporation stockholders |
$ | 1.06 | ($0.02 | ) | $ | 1.04 | ($1.35 | ) | ($0.02 | ) | ($1.37 | ) |
(a) | Certain amounts for the first through third quarters of 2010 and for each quarter of 2009 have been corrected from amounts originally presented. See Note 2 Prior Period Correction of Immaterial Errors. | |
(b) | Includes a ceiling test write-down of $343,932 before taxes ($223,556 after taxes). | |
(c) | Includes a ceiling test write-down of $165,057 before taxes ($107,287 after taxes). |
F-31
Table of Contents
NOTE 20 GUARANTOR FINANCIAL STATEMENTS:
Stone Offshore is an unconditional guarantor (the Guarantor Subsidiary) of our 63/4% Senior
Subordinated Notes due 2014 and our
85/8% Senior Notes due 2017 (see Note 12 Long-Term Debt). Our
remaining subsidiaries (the Non-Guarantor Subsidiaries) have not provided guarantees. The
following presents consolidating financial information as of December 31, 2010 and 2009 and for the
years ended December 31, 2010, 2009 and 2008 on an issuer (parent company), guarantor subsidiary,
non-guarantor subsidiaries, and consolidated basis. Elimination entries presented are necessary to
combine the entities.
CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2010
(In thousands of dollars)
DECEMBER 31, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Assets |
||||||||||||||||||||
Current assets: |
||||||||||||||||||||
Cash and cash equivalents |
$ | 105,115 | $ | 1,659 | $ | 182 | $ | | $ | 106,956 | ||||||||||
Restricted cash |
5,500 | | | | 5,500 | |||||||||||||||
Accounts receivable |
26,760 | 61,560 | 902 | (693 | ) | 88,529 | ||||||||||||||
Fair value of hedging contracts |
12,955 | | | | 12,955 | |||||||||||||||
Deferred tax asset |
27,274 | | | | 27,274 | |||||||||||||||
Inventory |
6,168 | 297 | | | 6,465 | |||||||||||||||
Other current assets |
753 | 15 | | | 768 | |||||||||||||||
Total current assets |
184,525 | 63,531 | 1,084 | (693 | ) | 248,447 | ||||||||||||||
Oil and gas properties United States
Proved, net |
260,434 | 720,309 | 3,886 | | 984,629 | |||||||||||||||
Unevaluated |
337,725 | 75,455 | | | 413,180 | |||||||||||||||
Building and land, net |
6,273 | | | | 6,273 | |||||||||||||||
Fixed assets, net |
4,449 | | | | 4,449 | |||||||||||||||
Other assets, net |
22,112 | | | | 22,112 | |||||||||||||||
Investment in subsidiary |
427,273 | 1,561 | | (428,834 | ) | | ||||||||||||||
Total assets |
$ | 1,242,791 | $ | 860,856 | $ | 4,970 | ($429,527 | ) | $ | 1,679,090 | ||||||||||
Liabilities and Stockholders Equity |
||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||
Accounts payable to vendors |
$ | 60,019 | $ | 43,881 | $ | | ($692 | ) | $ | 103,208 | ||||||||||
Undistributed oil and gas proceeds |
9,491 | 546 | | | 10,037 | |||||||||||||||
Fair value of hedging contracts |
32,144 | | | | 32,144 | |||||||||||||||
Asset retirement obligations |
| 42,300 | | | 42,300 | |||||||||||||||
Current income taxes payable |
239 | | | | 239 | |||||||||||||||
Other current liabilities |
30,137 | | | | 30,137 | |||||||||||||||
Total current liabilities |
132,030 | 86,727 | | (692 | ) | 218,065 | ||||||||||||||
Long-term debt |
575,000 | | | | 575,000 | |||||||||||||||
Deferred taxes * |
(41,804 | ) | 141,031 | | | 99,227 | ||||||||||||||
Asset retirement obligations |
129,100 | 198,105 | 4,415 | | 331,620 | |||||||||||||||
Fair value of hedging contracts |
3,606 | | | | 3,606 | |||||||||||||||
Other long-term liabilities |
14,502 | 6,713 | | | 21,215 | |||||||||||||||
Total liabilities |
812,434 | 432,576 | 4,415 | (692 | ) | 1,248,733 | ||||||||||||||
Commitments and contingencies |
||||||||||||||||||||
Stockholders equity: |
||||||||||||||||||||
Common stock |
478 | | | | 478 | |||||||||||||||
Treasury stock |
(860 | ) | | | | (860 | ) | |||||||||||||
Additional paid-in capital |
1,331,500 | 1,673,598 | 1,640 | (1,675,238 | ) | 1,331,500 | ||||||||||||||
Accumulated earnings (deficit) |
(886,557 | ) | (1,245,318 | ) | (1,085 | ) | 1,246,403 | (886,557 | ) | |||||||||||
Accumulated
other comprehensive loss |
(14,204 | ) | | | | (14,204 | ) | |||||||||||||
Total stockholders equity |
430,357 | 428,280 | 555 | (428,835 | ) | 430,357 | ||||||||||||||
Total liabilities and stockholders equity |
$ | 1,242,791 | $ | 860,856 | $ | 4,970 | ($429,527 | ) | $ | 1,679,090 | ||||||||||
* | Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside. |
F-32
Table of Contents
CONDENSED CONSOLIDATING BALANCE SHEET (UNAUDITED)
DECEMBER 31, 2009
(In thousands of dollars)
DECEMBER 31, 2009
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Assets |
||||||||||||||||||||
Current assets: |
||||||||||||||||||||
Cash and cash equivalents |
$ | 64,830 | $ | 3,963 | $ | 500 | $ | | $ | 69,293 | ||||||||||
Accounts receivable |
53,396 | 169,053 | 144 | (104,464 | ) | 118,129 | ||||||||||||||
Fair value of hedging contracts |
16,223 | | | | 16,223 | |||||||||||||||
Deferred tax asset |
14,571 | | | | 14,571 | |||||||||||||||
Inventory |
8,145 | 572 | | | 8,717 | |||||||||||||||
Other current assets |
771 | 43 | | | 814 | |||||||||||||||
Total current assets |
157,936 | 173,631 | 644 | (104,464 | ) | 227,747 | ||||||||||||||
Oil and gas properties United States
Proved, net |
76,066 | 774,980 | 5,421 | | 856,467 | |||||||||||||||
Unevaluated |
226,289 | 102,953 | | | 329,242 | |||||||||||||||
Building and land, net |
5,723 | | | | 5,723 | |||||||||||||||
Fair value of hedging contracts |
1,771 | | | | 1,771 | |||||||||||||||
Fixed assets, net |
4,084 | | | | 4,084 | |||||||||||||||
Other assets, net |
29,208 | | | | 29,208 | |||||||||||||||
Investment in subsidiary |
739,834 | 890 | | (740,724 | ) | | ||||||||||||||
Total assets |
$ | 1,240,911 | $ | 1,052,454 | $ | 6,065 | ($845,188 | ) | $ | 1,454,242 | ||||||||||
Liabilities and Stockholders Equity |
||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||
Accounts payable to vendors |
$ | 135,518 | $ | 35,247 | $ | 562 | ($104,464 | ) | $ | 66,863 | ||||||||||
Undistributed oil and gas proceeds |
14,828 | 452 | | | 15,280 | |||||||||||||||
Fair value of hedging contracts |
34,859 | | | | 34,859 | |||||||||||||||
Asset retirement obligations |
9,597 | 20,918 | | | 30,515 | |||||||||||||||
Current income tax payable |
11,110 | | | | 11,110 | |||||||||||||||
Other current liabilities |
42,223 | 760 | | | 42,983 | |||||||||||||||
Total current liabilities |
248,135 | 57,377 | 562 | (104,464 | ) | 201,610 | ||||||||||||||
Long-term debt |
575,000 | | | | 575,000 | |||||||||||||||
Deferred taxes * |
(26,231 | ) | 61,987 | | | 35,756 | ||||||||||||||
Asset retirement obligations |
98,927 | 186,545 | 4,612 | | 290,084 | |||||||||||||||
Fair value of hedging contracts |
7,721 | | | | 7,721 | |||||||||||||||
Other long-term liabilities |
11,700 | 6,712 | | | 18,412 | |||||||||||||||
Total liabilities |
915,252 | 312,621 | 5,174 | (104,464 | ) | 1,128,583 | ||||||||||||||
Commitments and contingencies |
||||||||||||||||||||
Stockholders equity: |
||||||||||||||||||||
Common stock |
475 | | | | 475 | |||||||||||||||
Treasury stock |
(860 | ) | | | | (860 | ) | |||||||||||||
Additional paid-in capital |
1,324,410 | 2,125,517 | 1,639 | (2,127,156 | ) | 1,324,410 | ||||||||||||||
Accumulated earnings (deficit) |
(982,986 | ) | (1,385,684 | ) | (748 | ) | 1,386,432 | (982,986 | ) | |||||||||||
Accumulated other comprehensive loss |
(15,380 | ) | | | | (15,380 | ) | |||||||||||||
Total stockholders equity |
325,659 | 739,833 | 891 | (740,724 | ) | 325,659 | ||||||||||||||
Total liabilities and stockholders equity |
$ | 1,240,911 | $ | 1,052,454 | $ | 6,065 | ($845,188 | ) | $ | 1,454,242 | ||||||||||
* | Deferred income taxes have been allocated to guarantor subsidiary where related oil and gas properties reside. |
F-33
Table of Contents
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2010
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2010
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 51,357 | $ | 366,591 | $ | | $ | | $ | 417,948 | ||||||||||
Gas production |
61,137 | 171,918 | | | 233,055 | |||||||||||||||
Derivative income, net |
3,265 | | | | 3,265 | |||||||||||||||
Total operating revenue |
115,759 | 538,509 | | | 654,268 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
64,868 | 87,458 | | | 152,326 | |||||||||||||||
Other operational expense |
1,968 | 3,482 | | | 5,450 | |||||||||||||||
Production taxes |
3,631 | 2,177 | | | 5,808 | |||||||||||||||
Depreciation, depletion, amortization |
40,351 | 206,856 | 994 | | 248,201 | |||||||||||||||
Accretion expense |
14,503 | 19,524 | 442 | | 34,469 | |||||||||||||||
Salaries, general and administrative |
42,741 | 17 | 1 | | 42,759 | |||||||||||||||
Incentive compensation expense |
5,888 | | | | 5,888 | |||||||||||||||
Impairment of inventory |
129 | | | | 129 | |||||||||||||||
Total operating expenses |
174,079 | 319,514 | 1,437 | | 495,030 | |||||||||||||||
Income (loss) from operations |
(58,320 | ) | 218,995 | (1,437 | ) | | 159,238 | |||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
12,192 | | | | 12,192 | |||||||||||||||
Interest income |
(1,439 | ) | (25 | ) | | | (1,464 | ) | ||||||||||||
Other (income) expense, net |
(4,283 | ) | (638 | ) | (1,100 | ) | | (6,021 | ) | |||||||||||
Loss on early extinguishment of debt |
1,820 | | | | 1,820 | |||||||||||||||
(Income) loss from investment in subsidiary |
(140,366 | ) | 337 | | 140,029 | | ||||||||||||||
Total other (income) expenses |
(132,076 | ) | (326 | ) | (1,100 | ) | 140,029 | 6,527 | ||||||||||||
Income (loss) before taxes |
73,756 | 219,321 | (337 | ) | (140,029 | ) | 152,711 | |||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
5,896 | (88 | ) | | | 5,808 | ||||||||||||||
Deferred |
(28,569 | ) | 79,043 | | | 50,474 | ||||||||||||||
Total income taxes |
(22,673 | ) | 78,955 | | | 56,282 | ||||||||||||||
Net income (loss) |
$ | 96,429 | $ | 140,366 | ($337 | ) | ($140,029 | ) | $ | 96,429 | ||||||||||
F-34
Table of Contents
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2009
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2009
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 136,513 | $ | 302,429 | $ | | $ | | $ | 438,942 | ||||||||||
Gas production |
123,511 | 148,842 | | | 272,353 | |||||||||||||||
Derivative income, net |
3,061 | | | | 3,061 | |||||||||||||||
Total operating revenue |
263,085 | 451,271 | | | 714,356 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
36,563 | 120,223 | | | 156,786 | |||||||||||||||
Other operational expense |
2,400 | | | | 2,400 | |||||||||||||||
Production taxes |
6,022 | 1,898 | | | 7,920 | |||||||||||||||
Depreciation, depletion, amortization |
47,695 | 211,465 | 479 | | 259,639 | |||||||||||||||
Write-down of oil and gas properties |
3,849 | 505,140 | | | 508,989 | |||||||||||||||
Accretion expense |
16,058 | 23,203 | 45 | | 39,306 | |||||||||||||||
Salaries, general and administrative |
41,178 | 184 | 5 | | 41,367 | |||||||||||||||
Incentive compensation expense |
6,402 | | | | 6,402 | |||||||||||||||
Impairment of inventory |
8,342 | 1,056 | | | 9,398 | |||||||||||||||
Total operating expenses |
168,509 | 863,169 | 529 | | 1,032,207 | |||||||||||||||
Income (loss) from operations |
94,576 | (411,898 | ) | (529 | ) | | (317,851 | ) | ||||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
21,183 | 178 | | | 21,361 | |||||||||||||||
Interest income |
(515 | ) | (13 | ) | | | (528 | ) | ||||||||||||
Other (income) expense, net |
(3,524 | ) | 223 | (553 | ) | | (3,854 | ) | ||||||||||||
(Income) loss from investment in subsidiary |
268,011 | 3 | | (268,014 | ) | | ||||||||||||||
Total other (income) expenses |
285,155 | 391 | (553 | ) | (268,014 | ) | 16,979 | |||||||||||||
Income (loss) before taxes |
(190,579 | ) | (412,289 | ) | 24 | 268,014 | (334,830 | ) | ||||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
30,376 | | | | 30,376 | |||||||||||||||
Deferred |
(2,657 | ) | (144,278 | ) | | | (146,935 | ) | ||||||||||||
Total income taxes |
27,719 | (144,278 | ) | | | (116,559 | ) | |||||||||||||
Net income (loss) |
(218,298 | ) | (268,011 | ) | 24 | 268,014 | (218,271 | ) | ||||||||||||
Less: net income attributable to non-controlling interest |
| | | 27 | 27 | |||||||||||||||
Net income (loss) attributable to Stone Energy Corporation |
($218,298 | ) | ($268,011 | ) | $ | 24 | $ | 267,987 | ($218,298 | ) | ||||||||||
F-35
Table of Contents
CONSOLIDATING STATEMENT OF OPERATIONS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2008
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2008
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Operating revenue: |
||||||||||||||||||||
Oil production |
$ | 444,825 | $ | 16,225 | $ | | $ | | $ | 461,050 | ||||||||||
Gas production |
305,637 | 31,028 | | | 336,665 | |||||||||||||||
Derivative income, net |
3,327 | | | | 3,327 | |||||||||||||||
Total operating revenue |
753,789 | 47,253 | | | 801,042 | |||||||||||||||
Operating expenses: |
||||||||||||||||||||
Lease operating expenses |
142,513 | 28,594 | | | 171,107 | |||||||||||||||
Production taxes |
7,722 | 268 | | | 7,990 | |||||||||||||||
Depreciation, depletion, amortization |
252,021 | 36,310 | 53 | | 288,384 | |||||||||||||||
Write-down of oil and gas properties |
342,815 | 981,512 | | | 1,324,327 | |||||||||||||||
Goodwill impairment |
| 465,985 | | | 465,985 | |||||||||||||||
Accretion expense |
15,886 | 1,492 | 14 | | 17,392 | |||||||||||||||
Salaries, general and administrative |
42,948 | 555 | 1 | | 43,504 | |||||||||||||||
Incentive compensation expense |
2,315 | | | | 2,315 | |||||||||||||||
Total operating expenses |
806,220 | 1,514,716 | 68 | | 2,321,004 | |||||||||||||||
Income (loss) from operations |
(52,431 | ) | (1,467,463 | ) | (68 | ) | | (1,519,962 | ) | |||||||||||
Other (income) expenses: |
||||||||||||||||||||
Interest expense |
13,212 | 31 | | | 13,243 | |||||||||||||||
Interest income |
(11,223 | ) | (27 | ) | | | (11,250 | ) | ||||||||||||
Other (income) expense, net |
(6,551 | ) | 46 | 705 | | (5,800 | ) | |||||||||||||
(Income) loss from investment in
subsidiary |
1,117,673 | 695 | | (1,118,368 | ) | | ||||||||||||||
Total other (income) expenses |
1,113,111 | 745 | 705 | (1,118,368 | ) | (3,807 | ) | |||||||||||||
Income (loss) before taxes |
(1,165,542 | ) | (1,468,208 | ) | (773 | ) | 1,118,368 | (1,516,155 | ) | |||||||||||
Provision (benefit) for income taxes: |
||||||||||||||||||||
Current |
6,998 | | | | 6,998 | |||||||||||||||
Deferred |
(25,609 | ) | (350,535 | ) | | | (376,144 | ) | ||||||||||||
Total income taxes |
(18,611 | ) | (350,535 | ) | | | (369,146 | ) | ||||||||||||
Net income (loss) |
(1,146,931 | ) | (1,117,673 | ) | (773 | ) | 1,118,368 | (1,147,009 | ) | |||||||||||
Less: net loss attributable to
non-controlling interest |
| | | (77 | ) | (77 | ) | |||||||||||||
Net income (loss) attributable to
Stone Energy Corporation |
$ | (1,146,931 | ) | $ | (1,117,673 | ) | $ | (773 | ) | $ | 1,118,445 | $ | (1,146,932 | ) | ||||||
F-36
Table of Contents
CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2010
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2010
(In thousands of dollars)
Non-Guarantor | ||||||||||||||||||||
Parent | Guarantor Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: |
||||||||||||||||||||
Net income (loss) |
$ | 96,429 | $ | 140,366 | $ | (337 | ) | $ | (140,029 | ) | $ | 96,429 | ||||||||
Adjustments to reconcile net income (loss) to
net cash provided by operating activities: |
||||||||||||||||||||
Depreciation, depletion and amortization |
40,351 | 206,856 | 994 | | 248,201 | |||||||||||||||
Impairment of inventory |
129 | | | | 129 | |||||||||||||||
Accretion expense |
14,503 | 19,524 | 442 | | 34,469 | |||||||||||||||
Deferred income tax provision (benefit) |
(28,569 | ) | 79,043 | | | 50,474 | ||||||||||||||
Settlement of asset retirement obligations |
(6,461 | ) | (30,440 | ) | | | (36,901 | ) | ||||||||||||
Non-cash stock compensation expense |
5,692 | | | | 5,692 | |||||||||||||||
Excess tax benefits |
(299 | ) | | | | (299 | ) | |||||||||||||
Non-cash derivative income |
(324 | ) | | | | (324 | ) | |||||||||||||
Loss on early extinguishment of debt |
1,820 | | | | 1,820 | |||||||||||||||
Non-cash (income) loss from investment in
subsidiary |
(140,366 | ) | 337 | | 140,029 | | ||||||||||||||
Other non-cash expenses |
1,708 | | | | 1,708 | |||||||||||||||
Change in current income taxes |
(10,783 | ) | (88 | ) | | | (10,871 | ) | ||||||||||||
Change in intercompany receivable/payables |
349,118 | (347,941 | ) | (1,177 | ) | | | |||||||||||||
(Increase) decrease in accounts receivable |
(11,556 | ) | 61,254 | (65 | ) | | 49,633 | |||||||||||||
Decrease in other current assets |
18 | 56 | | | 74 | |||||||||||||||
Decrease in inventory |
1,848 | 275 | | | 2,123 | |||||||||||||||
Increase (decrease) in accounts payable |
(1,045 | ) | 272 | | | (773 | ) | |||||||||||||
Decrease in other current liabilities |
(17,423 | ) | (665 | ) | | | (18,088 | ) | ||||||||||||
Other expenses |
1,230 | 68 | | | 1,298 | |||||||||||||||
Net cash provided by (used in) operating
activities |
296,020 | 128,917 | (143 | ) | | 424,794 | ||||||||||||||
Cash flows from investing activities: |
||||||||||||||||||||
Investment in oil and gas properties |
(265,198 | ) | (136,394 | ) | (175 | ) | | (401,767 | ) | |||||||||||
Proceeds from sale of oil and gas properties,
net of expenses |
25,455 | 6,180 | | | 31,635 | |||||||||||||||
Acquisition of non-controlling interest |
| (1,007 | ) | | | (1,007 | ) | |||||||||||||
Investment in fixed and other assets |
(2,949 | ) | | | | (2,949 | ) | |||||||||||||
Net cash used in investing activities |
(242,692 | ) | (131,221 | ) | (175 | ) | | (374,088 | ) | |||||||||||
Cash flows from financing activities: |
||||||||||||||||||||
Repayment of bank borrowings |
(175,000 | ) | | | | (175,000 | ) | |||||||||||||
Redemption of senior subordinated notes |
(200,503 | ) | | | | (200,503 | ) | |||||||||||||
Proceeds from issuance of senior notes |
375,000 | | | | 375,000 | |||||||||||||||
Deferred financing costs |
(11,474 | ) | | | | (11,474 | ) | |||||||||||||
Excess tax benefits |
299 | | | | 299 | |||||||||||||||
Net payments for share based compensation |
(1,365 | ) | | | | (1,365 | ) | |||||||||||||
Net cash used in financing activities |
(13,043 | ) | | | | (13,043 | ) | |||||||||||||
Net increase (decrease) in cash and cash
equivalents |
40,285 | (2,304 | ) | (318 | ) | | 37,663 | |||||||||||||
Cash and cash equivalents, beginning of period |
64,830 | 3,963 | 500 | | 69,293 | |||||||||||||||
Cash and cash equivalents, end of period |
$ | 105,115 | $ | 1,659 | $ | 182 | $ | | $ | 106,956 | ||||||||||
F-37
Table of Contents
CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2009
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2009
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: |
||||||||||||||||||||
Net income (loss) |
$ | (218,298 | ) | $ | (268,011 | ) | $ | 24 | $ | 268,014 | $ | (218,271 | ) | |||||||
Adjustments to reconcile net income
(loss) to net cash provided by operating
activities: |
||||||||||||||||||||
Depreciation, depletion and amortization |
47,695 | 211,465 | 479 | | 259,639 | |||||||||||||||
Write-down of oil and gas properties |
3,849 | 505,140 | | | 508,989 | |||||||||||||||
Impairment of inventory |
8,342 | 1,056 | | | 9,398 | |||||||||||||||
Accretion expense |
16,058 | 23,203 | 45 | | 39,306 | |||||||||||||||
Deferred income tax benefit |
(2,657 | ) | (144,278 | ) | | | (146,935 | ) | ||||||||||||
Settlement of asset retirement obligations |
(9,364 | ) | (57,416 | ) | | | (66,780 | ) | ||||||||||||
Non-cash stock compensation expense |
5,944 | | | | 5,944 | |||||||||||||||
Excess tax benefits |
(2 | ) | | | | (2 | ) | |||||||||||||
Non-cash derivative expense |
5,142 | | | | 5,142 | |||||||||||||||
Non-cash (income) loss from investment in
subsidiary |
268,011 | 3 | | (268,014 | ) | | ||||||||||||||
Other non-cash expenses |
1,573 | | | | 1,573 | |||||||||||||||
Change in current income taxes |
64,481 | 1,704 | | | 66,185 | |||||||||||||||
(Increase) decrease in accounts receivable |
177,984 | (127,809 | ) | 440 | (456 | ) | 50,159 | |||||||||||||
Decrease in other current assets |
585 | 42 | | | 627 | |||||||||||||||
Decrease in inventory |
16,478 | 1,083 | | | 17,561 | |||||||||||||||
Decrease in accounts payable |
(5,652 | ) | (3,787 | ) | (761 | ) | | (10,200 | ) | |||||||||||
Increase (decrease) in other current
liabilities |
(19,448 | ) | 5,017 | | | (14,431 | ) | |||||||||||||
Other expenses |
739 | (856 | ) | | | (117 | ) | |||||||||||||
Net cash provided by (used in) operating
activities |
361,460 | 146,556 | 227 | (456 | ) | 507,787 | ||||||||||||||
Cash flows from investing activities: |
||||||||||||||||||||
Investment in oil and gas properties |
(177,341 | ) | (143,405 | ) | 76 | 456 | (320,214 | ) | ||||||||||||
Proceeds from sale of oil and gas
properties, net of expenses |
5,553 | | | | 5,553 | |||||||||||||||
Sale of fixed assets |
| 35 | | | 35 | |||||||||||||||
Investment in fixed and other assets |
(1,412 | ) | | | | (1,412 | ) | |||||||||||||
Acquisition of non-controlling interest
in subsidiary |
| (41 | ) | | | (41 | ) | |||||||||||||
Net cash provided by (used in) investing
activities |
(173,200 | ) | (143,411 | ) | 76 | 456 | (316,079 | ) | ||||||||||||
Cash flows from financing activities: |
||||||||||||||||||||
Repayments of bank borrowings |
(250,000 | ) | | | | (250,000 | ) | |||||||||||||
Proceeds from stock offering |
60,447 | | | | 60,447 | |||||||||||||||
Deferred financing costs |
(141 | ) | | | | (141 | ) | |||||||||||||
Excess tax benefits |
2 | | | | 2 | |||||||||||||||
Purchase of treasury stock |
(347 | ) | | | | (347 | ) | |||||||||||||
Net payments for share based compensation |
(513 | ) | | | | (513 | ) | |||||||||||||
Net cash used in financing activities |
(190,552 | ) | | | | (190,552 | ) | |||||||||||||
Net increase (decrease) in cash and cash
equivalents |
(2,292 | ) | 3,145 | 303 | | 1,156 | ||||||||||||||
Cash and cash equivalents, beginning of
period |
67,122 | 818 | 197 | | 68,137 | |||||||||||||||
Cash and cash equivalents, end of period |
$ | 64,830 | $ | 3,963 | $ | 500 | $ | | $ | 69,293 | ||||||||||
F-38
Table of Contents
CONSOLIDATING STATEMENT OF CASH FLOWS (UNAUDITED)
YEAR ENDED DECEMBER 31, 2008
(In thousands of dollars)
YEAR ENDED DECEMBER 31, 2008
(In thousands of dollars)
Non- | ||||||||||||||||||||
Guarantor | Guarantor | |||||||||||||||||||
Parent | Subsidiary | Subsidiaries | Eliminations | Consolidated | ||||||||||||||||
Cash flows from operating activities: |
||||||||||||||||||||
Net income (loss) |
$ | (1,146,931 | ) | $ | (1,117,673 | ) | $ | (773 | ) | $ | 1,118,368 | $ | (1,147,009 | ) | ||||||
Adjustments to reconcile net income
(loss) to net cash provided by operating
activities: |
||||||||||||||||||||
Depreciation, depletion and amortization |
252,021 | 36,310 | 53 | | 288,384 | |||||||||||||||
Write-down of oil and gas properties |
342,815 | 981,512 | | | 1,324,327 | |||||||||||||||
Goodwill impairment |
| 465,985 | | | 465,985 | |||||||||||||||
Accretion expense |
15,886 | 1,492 | 14 | | 17,392 | |||||||||||||||
Deferred income tax benefit |
(25,609 | ) | (350,535 | ) | | | (376,144 | ) | ||||||||||||
Settlement of asset retirement obligations |
(47,617 | ) | (1,625 | ) | | | (49,242 | ) | ||||||||||||
Non-cash stock compensation expense |
8,405 | | | | 8,405 | |||||||||||||||
Excess tax benefits |
(3,045 | ) | | | | (3,045 | ) | |||||||||||||
Non-cash derivative expense |
(2,592 | ) | | | | (2,592 | ) | |||||||||||||
Non-cash (income) loss from investment in
subsidiary |
1,117,673 | 695 | | (1,118,368 | ) | | ||||||||||||||
Other non-cash expenses |
1,687 | | | | 1,687 | |||||||||||||||
Change in current income taxes |
(87,110 | ) | | | | (87,110 | ) | |||||||||||||
Decrease in accounts receivable |
70,982 | 39,182 | 69 | 456 | 110,689 | |||||||||||||||
Increase in other current assets |
(824 | ) | (42 | ) | | | (866 | ) | ||||||||||||
Increase in inventory |
(32,965 | ) | (565 | ) | | | (33,530 | ) | ||||||||||||
Increase in accounts payable |
12,717 | 11,455 | 778 | | 24,950 | |||||||||||||||
Decrease in other current liabilities |
(299 | ) | (17,481 | ) | | | (17,780 | ) | ||||||||||||
Investment in hedging contracts |
(1,914 | ) | | | | (1,914 | ) | |||||||||||||
Other expenses |
3,725 | (3,833 | ) | (1 | ) | | (109 | ) | ||||||||||||
Net cash provided by operating activities |
477,005 | 44,877 | 140 | 456 | 522,478 | |||||||||||||||
Cash flows from investing activities: |
||||||||||||||||||||
Acquisition of Bois dArc Energy, Inc. |
(929,542 | ) | 6,771 | 57 | | (922,714 | ) | |||||||||||||
Investment in oil and gas properties |
(395,848 | ) | (50,467 | ) | | (456 | ) | (446,771 | ) | |||||||||||
Proceeds from sale of oil and gas
properties, net of expenses |
13,339 | | | | 13,339 | |||||||||||||||
Sale of fixed assets |
4 | | | | 4 | |||||||||||||||
Investment in fixed and other assets |
(1,402 | ) | (363 | ) | | | (1,765 | ) | ||||||||||||
Net cash provided by (used in) investing
activities |
(1,313,449 | ) | (44,059 | ) | 57 | (456 | ) | (1,357,907 | ) | |||||||||||
Cash flows from financing activities: |
||||||||||||||||||||
Proceeds from bank borrowings |
425,000 | | | | 425,000 | |||||||||||||||
Deferred financing costs |
(8,766 | ) | | | | (8,766 | ) | |||||||||||||
Excess tax benefits |
3,045 | | | | 3,045 | |||||||||||||||
Expenses for stock offering |
(54 | ) | | | | (54 | ) | |||||||||||||
Purchase of treasury stock |
(6,724 | ) | | | | (6,724 | ) | |||||||||||||
Net payments for share based compensation |
15,939 | | | | 15,939 | |||||||||||||||
Net cash provided by financing activities |
428,440 | | | | 428,440 | |||||||||||||||
Net increase (decrease) in cash and cash
equivalents |
(408,004 | ) | 818 | 197 | | (406,989 | ) | |||||||||||||
Cash and cash equivalents, beginning of
period |
475,126 | | | | 475,126 | |||||||||||||||
Cash and cash equivalents, end of period |
$ | 67,122 | $ | 818 | $ | 197 | $ | | $ | 68,137 | ||||||||||
F-39
Table of Contents
GLOSSARY OF CERTAIN INDUSTRY TERMS
The following is a description of the meanings of some of the oil and gas industry terms used
in this Form 10-K. The revisions and additions to the definition section in Rule 4-10(a) of
Regulation S-X contained in the SECs new rule, Modernization of Oil and Gas Reporting, are
included. The definitions of proved developed reserves, proved reserves and proved undeveloped
reserves have been abbreviated from the new rule.
Bcf. One billion cubic feet of gas.
Bcfe. One billion cubic feet of gas equivalent. Determined using the ratio of one barrel of
crude oil to six mcf of natural gas.
Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to
crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound
mass of water from 58.5 to 59.5 degrees Fahrenheit.
Development well. A well drilled within the proved area of an oil or gas reservoir to the
depth of a stratigraphic horizon known to be productive.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field
previously found to be productive of oil or gas in another reservoir.
Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or
related to the same individual geological structural feature and/or stratigraphic condition. There
may be two or more reservoirs in a field that are separated vertically by intervening impervious,
strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by
being in overlapping or adjacent fields may be treated as a single or common operational field.
The geological terms structural feature and stratigraphic condition are intended to identify
localized geological features as opposed to the broader terms of basins, trends, provinces, plays,
areas-of-interest, etc.
Gross acreage or gross wells. The total acres or wells, as the case may be, in which a
working interest is owned.
LIBOR. Represents the London Inter-Bank Offering Rate of interest.
Liquidity. The ability to obtain cash quickly either through the conversion of assets or the
incurrence of liabilities.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of gas.
Mcfe. One thousand cubic feet of gas equivalent. Determined using the ratio of one barrel of
crude oil to six mcf of natural gas.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMcf. One million cubic feet of gas.
MMcfe. One million cubic feet of gas equivalent. Determined using the ratio of one barrel of
crude oil to six mcf of natural gas.
Net acres or net wells. The sum of the fractional working interests owned in gross acres or
gross wells expressed as whole numbers and fractions of whole numbers.
Overriding royalty interest. An interest in an oil and gas property entitling the owner to a
share of oil or gas production free of production and capital costs.
G-1
Table of Contents
Pari Passu. The term is Latin and translates to without partiality. Commonly refers to two
securities or obligations having equal rights to payment.
Primary term lease. An oil and gas property with no existing production, in which Stone has a
specific time frame to establish production without losing the rights to explore the property.
Productive well. A well that is found to be mechanically capable of producing hydrocarbons in
sufficient quantities that proceeds from the sale of such production exceeds production expenses
and taxes.
Proved developed reserves. Proved reserves that can be expected to be recovered (i) through
existing wells with existing equipment and operating methods or in which the cost of the required
equipment is relatively minor compared to the cost of a new well; and (ii) through installed
extraction technology equipment and infrastructure operational at the time of the reserves estimate
if the extraction is by means not involving a well.
Proved oil and gas reserves. Those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically
produciblefrom a given date forward, from known reservoirs, and under existing economic
conditions, operating methods, and government regulationsprior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably
certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract hydrocarbons must have commenced or the operator must be reasonably certain
that it will commence the project within a reasonable time. Reasonable certainty is defined as
much more likely to be achieved than not.
Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells
on undrilled acreage, or from existing wells where a relatively major expenditure is required for
recompletion.
Standardized measure of discounted future net cash flows. The standardized measure represents
value-based information about an enterprises proved oil and gas reserves based on estimates of
future cash flows, including income taxes, from production of proved reserves assuming continuation
of certain economic and operating conditions. Future cash flows are based on a twelve-month
average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price
for each month within the twelve month period prior to the end of the reporting period.
Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a
point that would permit the production of economic quantities of oil and gas regardless of whether
such acreage contains proved reserves.
Working interest. An operating interest that gives the owner the right to drill, produce and
conduct operating activities on the property and to receive a share of production.
G-2
Table of Contents
EXHIBIT INDEX
Exhibit | ||
Number | Description | |
3.1
|
Certificate of Incorporation of the Registrant, as amended (incorporated by reference to Exhibit 3.1 to the Registrants Registration Statement on Form S-1 (Registration No. 33-62362)). | |
3.2
|
Certificate of Amendment of the Certificate of Incorporation of Stone Energy Corporation, dated February 1, 2001 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed February 7, 2001). | |
3.3
|
Amended & Restated Bylaws of Stone Energy Corporation, dated May 15, 2008 (incorporated by reference to Exhibit 3.1 to the Registrants Current Report on Form 8-K filed May 21, 2008 (File No. 001-12074)). | |
4.1
|
Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed on December 15, 2004.) | |
4.2
|
First Supplemental Indenture, dated August 28, 2008, to the Indenture between Stone Energy Corporation and JPMorgan Chase Bank, National Association, as trustee, dated December 15, 2004 (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed August 29, 2008 (File No. 001-12074)). | |
4.3
|
Second Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., successor to JPMorgan Chase Bank, as trustee (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.4
|
Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
4.5
|
First Supplemental Indenture, dated January 26, 2010, among Stone Energy Corporation, Stone Energy Offshore, L.L.C., and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.3 to the Registrants Current Report on Form 8-K filed January 29, 2010 (File No. 001-12074)). | |
10.1
|
Deferred Compensation and Disability Agreement between TSPC and E. J. Louviere dated July 16, 1981 (incorporated by reference to Exhibit 10.10 to the Registrants Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 001-12074)). | |
10.2
|
Stone Energy Corporation 2009 Amended and Restated Stock Incentive Plan (incorporated by reference to Appendix A to the Registrants Definitive Proxy Statement on Schedule 14A for Stones 2009 Annual Meeting of Stockholders (File No. 001-12074)). | |
10.3
|
Stone Energy Corporation Revised (2005) Annual Incentive Compensation Plan (incorporated by reference to Exhibit 10.11 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). | |
10.4
|
Stone Energy Corporation Amended and Restated Revised Annual Incentive Compensation Plan, dated November 14, 2007 (incorporated by reference to Exhibit 10.10 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 001-12074)). | |
10.5
|
Stone Energy Corporation Deferred Compensation Plan (incorporated by reference to Exhibit 4.5 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). |
Table of Contents
Exhibit | ||
Number | Description | |
10.6
|
Adoption Agreement between Fidelity Management Trust Company and Stone Energy Corporation for the Stone Energy Corporation Deferred Compensation Plan dated December 1, 2004 (incorporated by reference to Exhibit 4.6 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2004 (File No. 001-12074)). | |
10.7
|
Letter Agreement dated May 19, 2005 between Stone Energy Corporation and Kenneth H. Beer (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed May 24, 2005 (File No. 001-12074)). | |
10.8
|
Letter Agreement dated December 2, 2008 between Stone Energy Corporation and David H. Welch (incorporated by reference to Exhibit 10.8 to the Registrants Annual Report on Form 10-K for the year ended December 31, 2008 (File No. 001-12074)). | |
10.9
|
Letter Agreement dated June 28, 2007 between Stone Energy Corporation and Richard L. Smith (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K filed July 2, 2007 (File No. 001-12074)). | |
10.10
|
Amendment No.1, dated as of April 28, 2009, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008, among Stone Energy Corporation, Stone Energy Offshore, L.L.C. and the financial institutions named therein (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed April 30, 2009 (File No. 001-12074)). | |
10.11
|
Amendment No. 2, dated January 11, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed January 12, 2010 (File No. 001-12074)). | |
10.12
|
Amendment No. 3, dated November 9, 2010, to the Second Amended and Restated Credit Agreement dated as of August 28, 2008 (incorporated by reference to Exhibit 4.1 to the Registrants Current Report on Form 8-K, filed November 12, 2010 (File No. 001-12074)). | |
10.13
|
Amended and Restated Security Agreement, dated as of August 28, 2008, among Stone Energy Corporation and the other Debtors parties hereto in favor of Bank of America, N.A., as Administrative Agent (incorporated by reference to Exhibit 4.5 to the Registrants Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 (File No. 001-12074)). | |
10.14
|
Stone Energy Corporation Executive Change of Control and Severance Plan (as amended and restated effective December 31, 2008) (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed April 8, 2009 (File No. 001-12074)). | |
10.15
|
Stone Energy Corporation Employee Change of Control Severance Plan (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.3 to the Registrants Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)). | |
10.16
|
Stone Energy Corporation Executive Change in Control Severance Policy (as amended and restated) dated December 7, 2007 (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed December 12, 2007 (File No. 001-12074)). | |
10.17
|
Form of Indemnification Agreement between Stone Energy Corporation and each of its directors and executive officers (incorporated by reference to Exhibit 10.1 to the Registrants Current Report on Form 8-K, filed March 27, 2009 (File No. 001-12074)). | |
*21.1
|
Subsidiaries of the Registrant. | |
*23.1
|
Consent of Independent Registered Public Accounting Firm. | |
*23.2
|
Consent of Netherland, Sewell & Associates, Inc. |
Table of Contents
Exhibit | ||
Number | Description | |
*31.1
|
Certification of Principal Executive Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*31.2
|
Certification of Principal Financial Officer of Stone Energy Corporation as required by Rule 13a-14(a) of the Securities Exchange Act of 1934. | |
*#32.1
|
Certification of Chief Executive Officer and Chief Financial Officer of Stone Energy Corporation pursuant to 18 U.S.C. § 1350. | |
*99.1
|
Report of Netherland, Sewell & Associates, Inc. | |
* | Filed herewith. | |
| Identifies management contracts and compensatory plans or arrangements. | |
# | Not considered to be filed for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. |