SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2005
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission File Number 0-19118
ABRAXAS PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
- --------------------------------------------------------------------------------
Nevada 74-2584033
- --------------------------------------------------------------------------------
(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
500 N. Loop 1604 East, Suite 100
San Antonio, Texas 78232
(Address of principal executive offices)
Registrant's telephone number,
including area code (210) 490-4788
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Common Stock, par value $.01 per share
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. Yes [ ] No [X]
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 or Section 15(d) of the Exchange Act.
Yes [ ] No [X]
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.
Yes [X] 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 registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated
filer, an accelerated filer, or a non-accelerated filer. See definition of
"accelerated filer and large accelerated filer" in Rule 12b-2 of the Exchange
Act.
Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]
Indicate by check mark whether the registrant is a shell company (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]
As of June 30, 2005, the aggregate market value of the common stock
held by non-affiliates of the registrant was $82,831,075 based on the closing
sale price as reported on the American Stock Exchange.
As of March 21, 2006, there were 42,588,327 shares of common stock
outstanding.
Documents Incorporated by Reference:
Document Parts Into Which Incorporated
Portions of the registrant's Proxy Statement Part III
relating to the 2006 Annual Meeting of
Shareholders to be held on May 25, 2006.
2
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
Page
PART I
Item 1. Business......................................................................................5
General.......................................................................................6
Markets and Customers.........................................................................6
Regulation of Natural Gas and Crude Oil Activities............................................7
Environmental Matters.........................................................................9
Title to Properties..........................................................................11
Competition..................................................................................11
Employees....................................................................................12
Available Information........................................................................12
Item 1A. Risk Factors.................................................................................12
Risks Related to Our Business................................................................12
Risks Related to Our Industry................................................................16
Risks Related to the Common Stock............................................................18
Item 1B. Unresolved Staff Comments....................................................................19
Item 2. Properties...................................................................................20
Primary Operating Areas......................................................................20
Exploratory and Developmental Acreage........................................................21
Productive Wells.............................................................................21
Reserves Information.........................................................................21
Crude Oil, Natural Gas Liquids, and Natural Gas Production
and Sales Prices.............................................................................23
Drilling Activities..........................................................................23
Office Facilities............................................................................24
Other Properties.............................................................................24
Item 3. Legal Proceedings............................................................................24
Item 4. Submission of Matters to a Vote of Security Holders..........................................25
PART II 25
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities...............................................................25
Market Information...........................................................................25
Holders......................................................................................25
Dividends....................................................................................25
Item 6. Selected Financial Data......................................................................25
Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of
Operations...................................................................................26
General......................................................................................26
Results of Operations........................................................................29
Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004...................29
Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003...................31
Liquidity and Capital Resources..............................................................33
Critical Accounting Policies.................................................................41
3
New Accounting Pronouncements................................................................43
Item 7A. Quantitative and Qualitative Disclosures about Market Risk...................................45
Commodity Price Risk.........................................................................45
Hedging Sensitivity..........................................................................45
Interest rate risk...........................................................................45
Item 8. Financial Statements.........................................................................46
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.....................................................................46
Item 9A. Controls and Procedures......................................................................46
Item 9B. Other Information............................................................................46
PART III 46
Item 10. Directors and Executive Officers of the Registrant...........................................46
Audit Committee and Audit Committee Financial Expert.........................................47
Section 16(a) Compliance.....................................................................47
Item 11. Executive Compensation.......................................................................47
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters..........................................................................47
Item 13. Certain Relationships and Related Transactions...............................................47
Item 14. Principal Accounting Fees and Services.......................................................47
PART IV 47
Item 15. Exhibits, Financial Statement Schedules......................................................47
SIGNATURES...................................................................................51
4
FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this document. Whenever
you read a statement that is not simply a statement of historical fact (such as
statements including words like "believe", "expect", "anticipate", "intend",
"plan", "seek", "estimate", "could", "potentially" or similar expressions), you
must remember that these are forward-looking statements, and that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the headings "Summary", "Risk Factors", "Business",
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations" but may be found in other locations as well. These forward-looking
statements generally relate to our plans and objectives for future operations
and are based upon our management's reasonable estimates of future results or
trends. The factors that may affect our expectations regarding our operations
include, among others, the following:
o our high debt level;
o our success in development, exploitation and exploration
activities;
o our ability to make planned capital expenditures;
o declines in our production of natural gas and crude oil;
o prices for natural gas and crude oil;
o our ability to raise equity capital or incur additional
indebtedness;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o prices and availability of alternative fuels;
o our restrictive debt covenants;
o our acquisition and divestiture activities;
o results of our hedging activities; and
o other factors discussed elsewhere in this report.
PART I
Item 1. Business
As part of a series of restructuring transactions approved in 2004, we
adopted a plan to dispose of our operations and interest in Grey Wolf
Exploration Inc., a wholly-owned Canadian subsidiary of Abraxas Petroleum
Corporation. In February 2005, Grey Wolf closed on an initial public offering
resulting in our substantial divestiture of our capital stock in Grey Wolf. As a
result of the disposal of Grey Wolf, the results of operations of Grey Wolf are
reflected in our Financial Statements and in this document as "Discontinued
Operations" and our remaining operations are referred to in our Financial
Statements and in this document as "Continuing Operations" or "Continued
Operations". Unless otherwise noted, all disclosures are for continuing
operations. See Note 3 to the financial statements in Item 8.
In this report, PV-10 means estimated future net revenue discounted at
a rate of 10% per annum, before income taxes and with no price or cost
escalation or de-escalation in accordance with guidelines promulgated by the
Securities and Exchange Commission. A Mcf is one thousand cubic feet of natural
gas. MMcf is used to designate one million cubic feet of natural gas and Bcf
refers to one billion cubic feet of natural gas. Mcfe means thousands of cubic
feet of natural gas equivalents, using a conversion ratio of one barrel of crude
oil to six Mcf of natural gas. MMcfe means millions of cubic feet of natural gas
equivalents and Bcfe means billions of cubic feet of natural gas equivalents.
MMBtu means million British Thermal Units. The term Bbl means one barrel of
crude oil or natural gas liquids and MBbls is used to designate one thousand
barrels of crude oil or natural gas liquids.
5
General
We are an independent energy company primarily engaged in the
development and production of natural gas and crude oil. Historically, we have
grown through the acquisition and subsequent development and exploitation of
producing properties, principally through the redevelopment of old fields
utilizing new technologies such as modern log analysis and reservoir modeling
techniques as well as 3-D seismic surveys and horizontal drilling. As a result
of these activities, we believe that we have a substantial inventory of
development opportunities, which provide a basis for significant production and
reserve increases. In addition, we intend to expand upon our exploitation and
development activities with complementary exploration projects in our core areas
of operation.
Our core areas of operation are in south and west Texas and east
central Wyoming. Our current producing properties are typically characterized by
long-lived reserves, established production profiles and an emphasis on natural
gas. At December 31, 2005, we owned interests in 102,356 gross acres (88,374 net
acres) applicable to our continuing operations, and operated properties
accounting for approximately 94% of our PV-10, affording us substantial control
over the timing and incurrence of operating and capital expenditures. At
December 31, 2005, estimated total proved reserves were 104.7 Bcfe with an
aggregate PV-10 of $311.9 million. During 2005, we participated in the drilling
of 12 gross (12 net) wells with 11 gross (11 net) wells being successful. We
invested $35.0 million in capital spending on these activities during 2005. As a
result of these activities we produced 6.1 Bcfe during 2005 and replaced 280% of
2005 production according to our year-end reserve report.
We believe that our high quality asset base, high degree of operational
control and large inventory of drilling projects positions us for future growth.
Our properties are concentrated in locations that facilitate substantial
economies of scale in drilling and production operations and efficient reservoir
management practices. In addition, we have 53 proved undeveloped projects and
have identified over 184 drilling and recompletion opportunities on our existing
acreage, the successful development of which we believe could significantly
increase our daily production and proved reserves. We have approved a capital
budget of approximately $40.0 million for 2006 which will be used primarily for
the development of our current properties as well as to drill and complete wells
that were in progress at the end of 2005. This drilling program will be funded
by cash flow from operations, availability under our revolving credit facility
and if necessary, equity financing. Our ability to complete this drilling
program may also be limited due to the lack of availability of drilling rigs and
other equipment.
Markets and Customers
The revenue generated by our operations is highly dependent upon the
prices of, and demand for, natural gas and crude oil. Historically, the markets
for natural gas and crude oil have been volatile and are likely to continue to
be volatile in the future. The prices we receive for our natural gas and crude
oil production are subject to wide fluctuations and depend on numerous factors
beyond our control including seasonality, the condition of the United States
economy (particularly the manufacturing sector), foreign imports, political
conditions in other crude oil-producing and natural gas-producing countries, the
actions of the Organization of Petroleum Exporting Countries and domestic
regulation, legislation and policies. Decreases in the prices of natural gas and
crude oil have had, and could have in the future, an adverse effect on the
carrying value of our proved reserves and our revenue, profitability and cash
flow from operations. You should read the discussion under "Risk Factors - Risks
Relating to Our Industry -- Market conditions for natural gas and crude oil, and
particularly volatility of prices for natural gas and crude oil, could adversely
affect our revenue, cash flows, profitability and growth" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Critical Accounting Policies" for more information relating to the effects of
decreases in natural gas and crude oil prices on us.
Substantially all of our natural gas and crude oil is sold at current
market prices under short-term arrangements, as is customary in the industry.
During the year ended December 31, 2005, two purchasers accounted for
approximately 61% of our natural gas and crude oil sales. We believe that there
are numerous other companies available to purchase our natural gas and crude oil
and that the loss of one or more of these purchasers would not materially affect
our ability to sell natural gas and crude oil.
6
Regulation of Natural Gas and Crude Oil Activities
The exploration, production and transportation of all types of
hydrocarbons are subject to significant governmental regulations. Our operations
are affected from time to time in varying degrees by political developments and
federal, state and local laws and regulations. In particular, crude oil and
natural gas production operations and economics are, or in the past have been,
affected by industry specific price controls, taxes, conservation, safety,
environmental, and other laws relating to the petroleum industry, and by changes
in such laws and by constantly changing administrative regulations.
Price Regulations
In the past, maximum selling prices for certain categories of crude
oil, natural gas, condensate and NGLs were subject to significant federal
regulation. At the present time, however, all sales of our crude oil, natural
gas, condensate and NGLs produced under private contracts may be sold at market
prices. Congress could, however, re-enact price controls in the future. If
controls that limit prices to below market rates are instituted, our revenue
could be adversely affected.
Natural Gas Regulation
Historically, the natural gas industry as a whole has been more heavily
regulated than the crude oil or other liquid hydrocarbons market. Most
regulations focused on transportation practices. Currently, the Federal Energy
Regulatory Commission ("FERC), requires each interstate pipeline to, among other
things, "unbundle" its traditional bundled sales services and create and make
available on an open and nondiscriminatory basis numerous constituent services
(such as gathering services, storage services, firm and interruptible
transportation services, and standby sales and natural gas balancing services),
and to adopt a new ratemaking methodology to determine appropriate rates for
those services. To the extent the pipeline company or its sales affiliate
markets natural gas as a merchant, it does so pursuant to private contracts in
direct competition with all of the sellers, such as us; however, pipeline
companies and their affiliates are not required to remain "merchants" of natural
gas, and most of the interstate pipeline companies have become "transporters
only", although many have affiliated marketers.
Transportation pipeline availability and shipping cost are major
factors affecting the production and sale of natural gas. Our physical sales of
natural gas are affected by the actual availability, terms and cost of pipeline
transportation. The price and terms for access into the pipeline transportation
systems remain subject to extensive Federal regulation. Although FERC does not
directly regulate our production and marketing activities, it does affect how
buyers and sellers gain access to and use of the necessary transportation
facilities and how we and our competitors sell natural gas in the marketplace.
FERC continues to review and modify its regulations regarding the transportation
of natural gas. The 2005 Energy Policy Act recently authorized FERC to allow
natural gas companies subject to the FERC's Natural Gas Act jurisdiction to
provide gas storage and storage-related services at market-based rates for new
storage capacity of a storage facility placed in service after the date of the
Act's August 2005 passage, thereby enhancing competition in the market for
interstate natural gas storage service.
In recent years FERC also has pursued a number of important policy
initiatives which could significantly affect the marketing of natural gas in the
United States. Most of these initiatives are intended to enhance competition in
natural gas markets. FERC rules encouraging "spin downs", or the breakout of
unregulated gathering activities from regulated transportation services, may
have the adverse effect of increasing the cost of doing business on some in the
industry, including us, as a result of the geographic monopolization of certain
facilities by their new, unregulated owners. Note, however, that FERC currently
is pursuing an inquiry into whether it should revise its test for determining
whether and under what circumstances FERC may reassert jurisdiction over natural
gas gathering companies that have been "spun-down" from an affiliated interstate
natural gas pipeline to prevent abusive practices by the gatherer and its
pipeline affiliate. Any action taken by FERC in this proceeding will be intended
by it to enhance competition in the gas transportation sector. As to all FERC
initiatives, the ongoing, or, in some instances, preliminary and evolving nature
of such matters makes it impossible at this time to predict their ultimate
impact on our business. However, we do not believe that any FERC initiatives
will affect us any differently than other natural gas producers and marketers
with which we compete.
7
FERC decisions involving onshore facilities are more liberal in their
reliance upon traditional tests for determining what facilities are "gathering"
and therefore are exempt from federal regulatory control. In many instances,
what was in the past classified as "transmission" may now be classified as
"gathering". We ship certain of our natural gas through gathering facilities
owned by others. Although FERC decisions create the potential for increasing the
cost of shipping our natural gas on third party gathering facilities, our
shipping activities have not been materially affected by these decisions.
In summary, all FERC activities related to the transportation of
natural gas result in improved opportunities to market our physical production
to a variety of buyers and market places, while at the same time increasing
access to pipeline transportation and delivery services. Additional proposals
and proceedings that might affect the natural gas industry in the United States
are considered from time to time by Congress, FERC, state regulatory bodies and
the courts. We cannot predict when or if any such proposals might become
effective or their effect, if any, on our operations. The natural gas and crude
oil industry historically has been very heavily regulated; thus there is no
assurance that the less stringent regulatory approach recently pursued by FERC
and Congress will continue indefinitely into the future.
State and Other Regulation
All of the jurisdictions in which we own producing natural gas and
crude oil properties have statutory provisions regulating the exploration for
and production of natural gas and crude oil. These include 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 plugging and abandoning 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 on an acreage basis and the density of wells which may
be drilled and the unitization or pooling of natural gas and crude oil
properties. In this regard, some states allow the forced 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 natural gas and crude oil wells, generally prohibit the
venting or flaring of natural gas and impose certain requirements regarding the
ratability of production. Some states, such as Texas and Oklahoma, have, in
recent years, reviewed and substantially revised methods previously used to make
monthly determinations of allowable rates of production from fields and
individual wells. The effect of all of these conservation regulations has the
potential to limit the speed, timing and amounts of crude oil and natural gas we
can produce from our wells, and to limit the number of wells or the location at
which we can drill.
State regulation of gathering facilities generally includes various
safety, environmental, and in some circumstances, non-discriminatory take or
service requirements, but does not generally entail rate regulation. In the
United States, natural gas gathering has received greater regulatory scrutiny at
both the state and federal levels in the wake of the interstate pipeline
restructuring under FERC Order 636. For example, the Texas Railroad Commission
enacted a Natural Gas Transportation Standards and Code of Conduct to provide
regulatory support for the State's more active review of rates, services and
practices associated with the gathering and transportation of natural gas by an
entity that provides such services to others for a fee, in order to prohibit
such entities from unduly discriminating in favor of their affiliates.
For those operations on Federal or Indian oil and gas leases, such
operations must comply with numerous regulatory restrictions, including various
non-discrimination statutes, and certain of such operations must be conducted
pursuant to certain on-site security regulations and other permits issued by
various federal agencies. In addition, on Federal Lands in the United States,
the Minerals Management Service ("MMS") prescribes or severely limits the types
of costs that are deductible transportation costs for purposes of royalty
valuation of production sold off the lease. In particular, MMS prohibits
deduction of costs associated with marketer fees, cash out and other pipeline
imbalance penalties, or long-term storage fees. Further, the MMS has been
engaged in a process of promulgating new rules and procedures for determining
the value of crude oil produced from federal lands for purposes of calculating
royalties owed to the government. The natural gas and crude oil industry as a
whole has resisted the proposed rules under an assumption that royalty burdens
will substantially increase. We cannot predict what, if any, effect any new rule
will have on our operations.
8
Environmental Matters
Our operations are subject to numerous federal, state and local laws
and regulations controlling the generation, use, storage, and discharge of
materials into the environment or otherwise relating to the protection of the
environment. These laws and regulations may require the acquisition of a permit
or other authorization before construction or drilling commences; restrict the
types, quantities, and concentrations of various substances that can be released
into the environment in connection with drilling, production, and natural gas
processing activities; suspend, limit or prohibit construction, drilling and
other activities in certain lands lying within wilderness, wetlands, and other
protected areas; require remedial measures to mitigate pollution from historical
and on-going operations such as use of pits and plugging of abandoned wells;
restrict injection of liquids into subsurface strata that may contaminate
groundwater; and impose substantial liabilities for pollution resulting from our
operations. Environmental permits required for our operations may be subject to
revocation, modification, and renewal by issuing authorities. Governmental
authorities have the power to enforce compliance with their regulations and
permits, and violations are subject to injunction, civil fines, and even
criminal penalties. Our management believes that we are in substantial
compliance with current environmental laws and regulations, and that we will not
be required to make material capital expenditures to comply with existing laws.
Nevertheless, changes in existing environmental laws and regulations or
interpretations thereof could have a significant impact on us as well as the
natural gas and crude oil industry in general, and thus we are unable to predict
the ultimate cost and effects of future changes in environmental laws and
regulations.
We are not currently involved in any administrative, judicial or legal
proceedings arising under domestic or foreign federal, state, or local
environmental protection laws and regulations, or under federal or state common
law, which would have a material adverse effect on our financial position or
results of operations. Moreover, we maintain insurance against costs of clean-up
operations, but we are not fully insured against all such risks. A serious
incident of pollution may result in the suspension or cessation of operations in
the affected area.
Superfund. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as "Superfund," and comparable state
statutes impose strict, joint, and several liability on certain classes of
persons who are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
a disposal site or sites where a release occurred and companies that generated,
disposed or arranged for the disposal of the hazardous substances released at
the site. Under CERCLA, such persons or companies may be retroactively liable
for the costs of cleaning up the hazardous substances that have been released
into the environment and for damages to natural resources, and it is common for
neighboring land owners and other third parties to file claims for personal
injury, property damage, and recovery of response costs allegedly caused by the
hazardous substances released into the environment. In the course of our
ordinary operations, we may generate waste that may fall within CERCLA's
definition of a "hazardous substance." We may be jointly and severally liable
under CERCLA or comparable state statutes for all or part of the costs required
to clean up sites at which these wastes have been disposed. Although CERCLA
currently contains a "petroleum exclusion" from the definition of "hazardous
substance," state laws affecting our operations impose cleanup liability
relating to petroleum and petroleum related products, including crude oil
cleanups. In addition, although RCRA regulations currently classify certain
oilfield wastes which are uniquely associated with field operations as
"non-hazardous," such exploration, development and production wastes could be
reclassified by regulation as hazardous wastes thereby administratively making
such wastes subject to more stringent handling and disposal requirements.
We currently own or lease, and have in the past owned or leased,
numerous properties that for many years have been used for the exploration and
production of natural gas and crude oil. Although we utilized standard industry
operating and disposal practices at the time, hydrocarbons or other wastes may
have been disposed of or released on or under the properties we owned or leased
or on or under other locations where such wastes have been taken for disposal.
In addition, many of these properties have been operated by third parties whose
treatment and disposal or release of hydrocarbons or other wastes was not under
our control. These properties and the wastes disposed thereon may be subject to
CERCLA, RCRA (as defined below), and analogous state laws. Under these laws, we
could be required to remove or remediate previously disposed wastes, including
wastes disposed or released by prior owners or operators; to clean up
contaminated property, including contaminated groundwater; or to perform
remedial operations to prevent future contamination.
9
Oil Pollution Act of 1990. United States federal regulations also
require certain owners and operators of facilities that store or otherwise
handle crude oil, such as us, to prepare and implement spill prevention, control
and countermeasure plans and spill response plans relating to possible discharge
of crude oil into surface waters. The federal Oil Pollution Act ("OPA") contains
numerous requirements relating to prevention of, reporting of, and response to
crude oil spills into waters of the United States. For facilities that may
affect state waters, OPA requires an operator to demonstrate $10 million in
financial responsibility. State laws mandate crude oil cleanup programs with
respect to contaminated soil. A failure to comply with OPA's requirements or
inadequate cooperation during a spill response action may subject a responsible
party to civil or criminal enforcement actions. We are not aware of any action
or event that would subject us to liability under OPA, and we believe that
compliance with OPA's financial responsibility and other operating requirements
will not have a material adverse effect on us.
U.S. Environmental Protection Agency. U.S. Environmental Protection
Agency regulations address the disposal of crude oil and natural gas operational
wastes under three federal acts more fully discussed in the paragraphs that
follow. The Resource Conservation and Recovery Act of 1976, as amended ("RCRA"),
provides a framework for the safe disposal of discarded materials and the
management of solid and hazardous wastes. The direct disposal of operational
wastes into offshore waters is also limited under the authority of the Clean
Water Act. When injected underground, crude oil and natural gas wastes are
regulated by the Underground Injection Control program under the Safe Drinking
Water Act. If wastes are classified as hazardous, they must be properly
transported, using a uniform hazardous waste manifest, documented, and disposed
of at an approved hazardous waste facility. We have coverage under the
applicable Clean Water Act permitting requirements for discharges associated
with exploration and development activities. Resource Conservation Recovery Act.
RCRA is the principal federal statute governing the treatment, storage and
disposal of hazardous wastes. RCRA imposes stringent operating requirements, and
liability for failure to meet such requirements, on a person who is either a
"generator" or "transporter" of hazardous waste or an "owner" or "operator" of a
hazardous waste treatment, storage or disposal facility. At present, RCRA
includes a statutory exemption that allows most crude oil and natural gas
exploration and production waste to be classified as nonhazardous waste. A
similar exemption is contained in many of the state counterparts to RCRA. As a
result, we are not required to comply with a substantial portion of RCRA's
requirements because our operations generate minimal quantities of hazardous
wastes. At various times in the past, proposals have been made to amend RCRA to
rescind the exemption that excludes crude oil and natural gas exploration and
production wastes from regulation as hazardous waste. Repeal or modification of
the exemption by administrative, legislative or judicial process, or
modification of similar exemptions in applicable state statutes, would increase
the volume of hazardous waste we are required to manage and dispose of and would
cause us to incur increased operating expenses.
Clean Water Act. The Clean Water Act imposes restrictions and controls
on the discharge of produced waters and other wastes into navigable waters.
Permits must be obtained to discharge pollutants into state and federal waters
and to conduct construction activities in waters and wetlands. Certain state
regulations and the general permits issued under the Federal National Pollutant
Discharge Elimination System program prohibit the discharge of produced waters
and sand, drilling fluids, drill cuttings and certain other substances related
to the crude oil and natural gas industry into certain coastal and offshore
waters. Further, the EPA has adopted regulations requiring certain crude oil and
natural gas exploration and production facilities to obtain permits for storm
water discharges. Costs may be associated with the treatment of wastewater or
developing and implementing storm water pollution prevention plans. The Clean
Water Act and comparable state statutes provide for civil, criminal and
administrative penalties for unauthorized discharges for crude oil and other
pollutants and impose liability on parties responsible for those discharges for
the costs of cleaning up any environmental damage caused by the release and for
natural resource damages resulting from the release. We believe that our
operations comply in all material respects with the requirements of the Clean
Water Act and state statutes enacted to control water pollution.
Safe Drinking Water Act. Underground injection is the subsurface
placement of fluid through a well, such as the reinjection of brine produced and
separated from crude oil and natural gas production. The Safe Drinking Water Act
of 1974, as amended establishes a regulatory framework for underground
injection, with the main goal being the protection of usable aquifers. The
primary objective of injection well operating requirements is to ensure the
mechanical integrity of the injection apparatus and to prevent migration of
fluids from the injection zone into underground sources of drinking water.
Hazardous-waste injection well operations are strictly controlled, and certain
wastes, absent an exemption, cannot be injected into underground injection
control wells. In Texas, no underground injection may take place except as
10
authorized by permit or rule. We currently own and operate various underground
injection wells. Failure to abide by our permits could subject us to civil
and/or criminal enforcement. We believe that we are in compliance in all
material respects with the requirements of applicable state underground
injection control programs and our permits.
Air Pollution Control. The Clean Air Act and state air pollution laws
adopted to fulfill its mandate provide a framework for national, state and local
efforts to protect air quality. Our operations utilize equipment that emits air
pollutants which may be subject to federal and state air pollution control laws.
These laws require utilization of air emissions abatement equipment to achieve
prescribed emissions limitations and ambient air quality standards, as well as
operating permits for existing equipment and construction permits for new and
modified equipment. We believe that we are in compliance in all material
respects with the requirements of applicable federal and state air pollution
control laws.
Naturally Occurring Radioactive Materials ("NORM"). NORM are materials
not covered by the Atomic Energy Act, whose radioactivity is enhanced by
technological processing such as mineral extraction or processing through
exploration and production conducted by the crude oil and natural gas industry.
NORM wastes are regulated under the RCRA framework, but primary responsibility
for NORM regulation has been a state function. Standards have been developed for
worker protection; treatment, storage and disposal of NORM waste; management of
waste piles, containers and tanks; and limitations upon the release of NORM
contaminated land for unrestricted use. We believe that our operations are in
material compliance with all applicable NORM standards established by the State
of Texas.
Abandonment Costs. All of our crude oil and natural gas wells will
require proper plugging and abandonment when they are no longer producing. We
post bonds with most regulatory agencies to ensure compliance with our plugging
responsibility. Plugging and abandonment operations and associated reclamation
of the surface production site are important components of our environmental
management system. We plan accordingly for the ultimate disposition of
properties that are no longer producing.
Title to Properties
As is customary in the natural gas and crude oil industry, we make only
a cursory review of title to undeveloped natural gas and crude oil leases at the
time we acquire them. However, before drilling commences, we require a thorough
title search to be conducted, and any material defects in title are remedied
prior to the time actual drilling of a well begins. To the extent title opinions
or other investigations reflect title defects, we, rather than the seller/lessor
of the undeveloped property, are typically obligated to cure any title defect at
our expense. If we were unable to remedy or cure any title defect of a nature
such that it would not be prudent to commence drilling operations on the
property, we could suffer a loss of our entire investment in the property. We
believe that we have good title to our natural gas and crude oil properties,
some of which are subject to immaterial encumbrances, easements and
restrictions. The natural gas and crude oil properties we own are also typically
subject to royalty and other similar non-cost bearing interests customary in the
industry. We do not believe that any of these encumbrances or burdens will
materially affect our ownership or use of our properties.
Competition
We operate in a highly competitive environment. The principal resources
necessary for the exploration and production of natural gas and crude oil are
leasehold prospects under which natural gas and crude oil reserves may be
discovered, drilling rigs and related equipment to explore for such reserves and
knowledgeable personnel to conduct all phases of natural gas and crude oil
operations. We must compete for such resources with both major natural gas and
crude oil companies and independent operators. Many of these competitors have
financial and other resources substantially greater than ours. Although we
believe our current operating and financial resources are adequate to preclude
any significant disruption of our operations in the immediate future, we cannot
assure you that such materials and resources will be available to us. For more
information, you should read "Risk Factors - Risks Related to Our Industry - We
operate in a highly competitive industry which may adversely affect our
operations." and "- The unavailability or high cost of drilling rigs, equipment,
supplies, insurance, personnel and crude oil field services could adversely
affect our ability to execute our exploration and development plans on a timely
basis and within our budget."
11
Employees
As of March 21, 2006 we had 48 full-time employees in the United
States, including two executive officers, three non-executive officers, one
petroleum engineer, one geologist, five managers, one landman, ten
administrative and support personnel and 25 field personnel. Additionally, we
retain contract gaugers on a month-to-month basis. We retain independent
geological and engineering consultants from time to time on a limited basis and
expect to continue to do so in the future.
Available Information
Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current
Reports on Form 8-K and other reports and amendments filed with the Securities
and Exchange Commission are available free of charge on our web site at
www.abraxaspetroleum.com in the Investor Relations section as soon as
practicable after such reports are filed.
Item 1A. Risk Factors
Risks Related to Our Business
We have a highly leveraged capital structure, which limits our operating and
financial flexibility.
We have a highly leveraged capital structure. At March 21, 2006, we had
total indebtedness, including our floating rate senior secured notes due 2009,
or notes, which we issued in connection with our October 2004 refinancing, of
approximately $130.8 million, all of which is secured indebtedness. We also had
availability of $9.2 million under our $15.0 million senior secured revolving
credit facility, all of which is also secured indebtedness.
Our highly leveraged capital structure will have several important effects on
our future operations, including:
o a substantial amount of our cash flow from operations will be
required to service our indebtedness, which will reduce the
funds that would otherwise be available for operations, capital
expenditures and expansion opportunities, including developing
our properties;
o the covenants contained in our revolving credit facility require
us to meet certain financial tests and comply with certain other
restrictions, including limitations on capital expenditures.
These restrictions, together with those in the indenture
governing the notes, may limit our ability to undertake certain
activities and respond to changes in our business and our
industry;
o our debt level may impair our ability to obtain additional
capital, through equity offerings or debt financings, for
working capital, capital expenditures, or refinancing of
indebtedness;
o our debt level makes us more vulnerable to economic downturns
and adverse developments in our industry (especially declines in
natural gas and crude oil prices) and the economy in general;
and
o the notes and our revolving credit facility are subject to
variable interest rates which makes us vulnerable to interest
rate increases.
We may not be able to fund the substantial capital expenditures that will be
required for us to increase our reserves and our production.
We are required to make substantial capital expenditures to develop our
existing reserves and to discover new reserves. Historically, we have financed
our capital expenditures primarily with cash flow from operations, borrowings
under credit facilities, sales of producing properties, and sales of equity
securities and we expect to continue to do so in the future; however, we cannot
assure you that we will have sufficient capital resources in the future to
finance our capital expenditures.
12
Volatility in natural gas and crude oil prices, the timing of our
drilling program and our drilling results will affect our cash flow from
operations. Lower prices and/or lower production will also decrease revenues and
cash flow, thus reducing the amount of financial resources available to meet our
capital requirements, including reducing the amount available to pursue our
drilling opportunities. If our cash flow from operations does not increase as a
result of our planned capital expenditures, a greater percentage of our cash
flow from operations will be required for debt service and our planned capital
expenditures would, by necessity, be decreased.
The borrowing base under our revolving credit facility will be
determined from time to time by our lenders, consistent with their customary
natural gas and crude oil lending practices. Reductions in estimates of our
natural gas and crude oil reserves could result in a reduction in our borrowing
base, which would reduce the amount of financial resources available under our
revolving credit facility to meet our capital requirements. Such a reduction
could be the result of lower commodity prices or production, inability to drill
or unfavorable drilling results, changes in natural gas and crude oil reserve
engineering, the lenders' inability to agree to an adequate borrowing base or
adverse changes in the lenders' practices regarding estimation of reserves.
If cash flow from operations or our borrowing base decrease for any
reason, our ability to undertake exploitation and development activities could
be adversely affected. As a result, our ability to replace production may be
limited. In addition, if the borrowing base under our revolving credit facility
is reduced, we would be required to reduce our borrowings under our revolving
credit facility so that such borrowings do not exceed the borrowing base. This
could further reduce the cash available to us for capital spending and, if we
did not have sufficient capital to reduce our borrowing level, could cause us to
default under our revolving credit facility and the notes.
We have sold producing properties to provide us with liquidity and
capital resources in the past and may do so in the future. After any such sale,
we would expect to utilize the proceeds to drill new wells. If we cannot replace
the production lost from properties sold with production from new properties,
our cash flow from operations will likely decrease which, in turn, would
decrease the amount of cash available for debt service and additional capital
spending.
We may be unable to acquire or develop additional reserves, in which case our
results of operations and financial condition would be adversely affected.
Our future natural gas and crude oil production, and therefore our
success, is highly dependent upon our ability to find, acquire and develop
additional reserves that are profitable to produce. The rate of production from
our natural gas and crude oil properties and our proved reserves will decline as
our reserves are produced unless we acquire additional properties containing
proved reserves, conduct successful development and exploitation activities or,
through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves. We cannot assure you that our exploration, exploitation and
development activities will result in increases in our proved reserves. As our
proved reserves, and consequently our production decline, our cash flow from
operations and the amount that we are able to borrow under our revolving credit
facility will also decline. In addition, approximately 52% of our total
estimated proved reserves at December 31, 2005 were undeveloped. By their
nature, estimates of undeveloped reserves are less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations.
Our production is currently concentrated in one well
Approximately 30% of our current production is from a single well in
west Texas. If production from this well decreases, it would have a material
impact on our revenues, cash flow from operations and financial condition. This
well is subject to all of the risks typically associated with natural gas wells,
including the risks described in "Risks Related to Our Industry - Our operations
are subject to the numerous risks of natural gas and crude oil drilling and
production activities."
We may not find any commercially productive natural gas or crude oil reservoirs.
We cannot assure you that the new wells we drill will be productive or
that we will recover all or any portion of our capital investment. Drilling for
natural gas and crude oil may be unprofitable. Dry holes and wells that are
13
productive but do not produce sufficient net revenues after drilling, operating
and other costs are unprofitable. The inherent risk of not finding commercially
productive reservoirs will be compounded by the fact that 52% of our total
estimated proved reserves at December 31, 2005 were undeveloped. By their
nature, estimates of undeveloped reserves are less certain. Recovery of such
reserves will require significant capital expenditures and successful drilling
operations. In addition, our properties may be susceptible to drainage from
production by other operations on adjacent properties. If the volume of natural
gas and crude oil we produce decreases, our cash flow from operations will
decrease.
Restrictive debt covenants could limit our growth and our ability to finance our
operations, fund our capital needs, respond to changing conditions and engage in
other business activities that may be in our best interest.
Our revolving credit facility and the indenture governing the notes
contain a number of significant covenants that, among other things, limit our
ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
In addition, our revolving credit facility requires us to maintain
compliance with specified financial ratios and satisfy certain financial
condition tests. Our ability to comply with these ratios and financial condition
tests may be affected by events beyond our control, and we cannot assure you
that we will meet these ratios and financial condition tests. These financial
ratio restrictions and financial condition tests could limit our ability to
obtain future financings, make needed capital expenditures, withstand a future
downturn in our business or the economy in general or otherwise conduct
necessary or desirable corporate activities.
A breach of any of these covenants or our inability to comply with the
required financial ratios or financial condition tests could result in a default
under our revolving credit facility and the notes. A default, if not cured or
waived, could result in all of our indebtedness, including the notes, becoming
immediately due and payable. If that should occur, we may not be able to pay all
such debt or to borrow sufficient funds to refinance it. Even if new financing
were then available, it may not be on terms that are acceptable to us.
The marketability of our production depends largely upon the availability,
proximity and capacity of natural gas gathering systems, pipelines and
processing facilities.
The marketability of our production depends in part upon processing and
transportation facilities. Transportation space on such gathering systems and
pipelines is occasionally limited and at times unavailable due to repairs or
14
improvements being made to such facilities or due to such space being utilized
by other companies with priority transportation agreements. Our access to
transportation options can also be affected by U.S. Federal and state regulation
of natural gas and crude oil production and transportation, general economic
conditions and changes in supply and demand. These factors and the availability
of markets are beyond our control. If market factors dramatically change, the
financial impact on us could be substantial and adversely affect our ability to
produce and market natural gas and crude oil.
Hedging transactions have in the past and may in the future impact our cash flow
from operations.
We enter into hedging arrangements from time to time to reduce our
exposure to fluctuations in natural gas and crude oil prices and to achieve more
predictable cash flow. In 2003 and 2005, we incurred hedging costs of $842,000
and $592,000, respectively, resulting from the price floors we established . For
the year ended December 31, 2004, we recognized a gain from hedging activities
of approximately $118,000. Currently, we believe our hedging arrangements, which
are in the form of price floors, do not expose us to significant financial risk.
We cannot assure you that the hedging transactions we have entered
into, or will enter into, will adequately protect us from financial loss due to
circumstances such as:
o highly volatile natural gas and crude oil prices;
o our production being less than expected; or
o a counterparty to one of our hedging transactions defaulting on
our contractual obligations.
We have experienced significant operating losses in the past.
We recorded net losses from continuing operations for 2003 of $12.8
million. We recorded net income from continuing operations for 2004 and 2005 of
$3.0 million and $6.3 million, respectively. Net income from continuing
operations in 2004 included $12.6 million of gain on debt extinguishment
relating to our October 2004 refinancing and a deferred tax benefit of $6.1
million. We cannot assure you that we will continue to be profitable in the
future.
Lower natural gas and crude oil prices increase the risk of ceiling limitation
write-downs.
We use the full cost method to account for our natural gas and crude
oil operations. Accordingly, we capitalize the cost to acquire, explore for and
develop natural gas and crude oil properties. Under full cost accounting rules,
the net capitalized cost of natural gas and crude oil properties may not exceed
a "ceiling limit" which is based upon the present value of estimated future net
cash flows from proved reserves, discounted at 10%. If net capitalized costs of
natural gas and crude oil properties exceed the ceiling limit, we must charge
the amount of the excess to earnings. This is called a "ceiling limitation
write-down." This charge does not impact cash flow from operating activities,
but does reduce our stockholders' equity and earnings. The risk that we will be
required to write-down the carrying value of natural gas and crude oil
properties increases when natural gas and crude oil prices are low. In addition,
write-downs may occur if we experience substantial downward adjustments to our
estimated proved reserves. An expense recorded in one period may not be reversed
in a subsequent period even though higher natural gas and crude oil prices may
have increased the ceiling applicable to the subsequent period.
We have incurred ceiling limitation write-downs in the past. We cannot assure
you that we will not experience additional ceiling limitation write-downs in the
future.
Use of our net operating loss carryforwards may be limited.
At December 31, 2005, we had, subject to the limitation discussed
below, $190.0 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire through 2025 if not utilized. In addition,
as to a portion of the U.S. net operating loss carryforwards, the amount of such
carryforwards that we can use annually is limited under U.S. tax law. Moreover,
uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
15
Therefore, we have established a valuation allowance of $73.0 million and $67.0
million for deferred tax assets at December 31, 2004 and 2005, respectively.
We depend on our Chairman, President and CEO and the loss of his services could
have an adverse effect on our operations.
We depend to a large extent on Robert L. G. Watson, our Chairman of the
Board, President and Chief Executive Officer, for our management and business
and financial contacts. Mr. Watson may terminate his employment agreement with
us at any time on 30 days notice, but, if he terminates without cause, he would
not be entitled to the severance benefits provided under the terms of that
agreement. Mr. Watson is not precluded from working for, with or on behalf of a
competitor upon termination of his employment with us. If Mr. Watson were no
longer able or willing to act as our Chairman, the loss of his services could
have an adverse effect on our operations. In addition, in connection with the
initial public offering by our previously wholly-owned subsidiary, Grey Wolf
Exploration Inc., we, Grey Wolf and Mr. Watson agreed that Mr. Watson would
continue to serve as our Chief Executive Officer and President and as the Chief
Executive Officer for Grey Wolf, with Mr. Watson devoting two-thirds of his time
to his positions and duties with us and one-third of his time to his position
and duties with Grey Wolf. In consideration for receiving Mr. Watson's services,
Grey Wolf makes an annual payment to Abraxas of US$100,000 and reimburses
Abraxas for Mr. Watson's expenses incurred in connection with providing such
services.
Risks Related to Our Industry
Market conditions for natural gas and crude oil, and particularly volatility of
prices for natural gas and crude oil, could adversely affect our revenue, cash
flows, profitability and growth.
Our revenue, cash flows, profitability and future rate of growth depend
substantially upon prevailing prices for natural gas and crude oil. Natural gas
prices affect us more than crude oil prices because most of our production and
reserves are natural gas. Prices also affect the amount of cash flow available
for capital expenditures and our ability to borrow money or raise additional
capital. Lower prices may also make it uneconomical for us to increase or even
continue current production levels of natural gas and crude oil.
Prices for natural gas and crude oil are subject to large fluctuations
in response to relatively minor changes in the supply and demand for natural gas
and crude oil, market uncertainty and a variety of other factors beyond our
control, including:
o changes in foreign and domestic supply and demand for natural
gas and crude oil;
o political stability and economic conditions in oil producing
countries, particularly in the Middle East;
o general economic conditions;
o domestic and foreign governmental regulation; and
o the price and availability of alternative fuel sources.
In addition to decreasing our revenue and cash flow from operations,
low or declining natural gas and crude oil prices could have additional material
adverse effects on us, such as:
o reducing the overall volume of natural gas and crude oil that we
can produce economically, thereby adversely affecting our
revenue, profitability and cash flow and our ability to perform
our obligations with respect to the notes;
o reducing our borrowing base under the credit facility; and
o impairing our borrowing capacity and our ability to obtain
equity capital.
16
Estimates of our proved reserves and future net revenue are uncertain and
inherently imprecise.
The process of estimating natural gas and crude oil reserves is complex
involving decisions and assumptions in evaluating the available geological,
geophysical, engineering and economic data. Accordingly, these estimates are
imprecise. Actual future production, natural gas and crude oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and crude oil reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this report. In addition,
we may adjust estimates of proved reserves to reflect production history,
results of exploitation and development, prevailing natural gas and crude oil
prices and other factors, many of which are beyond our control.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of natural gas and crude oil reserves, future net
revenue from proved reserves and the PV-10 thereof for our natural gas and crude
oil properties are based on the assumption that future natural gas and crude oil
prices remain the same as natural gas and crude oil prices at December 31, 2005.
The sales prices as of such date used for purposes of such estimates were $8.84
per Mcf of natural gas and $56.92 per Bbl of crude oil. This compares with $4.94
per Mcf of natural gas and $41.01 per Bbl of crude oil as of December 31, 2004.
These estimates also assume that we will make future capital expenditures of
approximately $84.2 million in the aggregate through 2024, with the majority
expected to be incurred from 2006 to 2009, which are necessary to develop and
realize the value of proved undeveloped reserves on our properties. Any
significant variance in actual results from these assumptions could also
materially affect the estimated quantity and value of reserves set forth in this
report.
The present value of future net revenues we disclose may not be the
current market value of our estimated natural gas and crude oil reserves. In
accordance with SEC requirements, the estimated discounted future net cash flows
from proved reserves are generally based on prices and costs as of the end of
the period of the estimate. Actual future prices and costs may be materially
higher or lower than the prices and costs as of the end of the year of the
estimate. Any changes in consumption by natural gas purchasers or in
governmental regulations or taxation will also affect actual future net cash
flows. The timing of both the production and the expenses from the development
and production of natural gas and crude oil properties will affect the timing of
actual future net cash flows from proved reserves and their present value. In
addition, the 10% discount factor, which is required by the SEC to be used in
calculating discounted future net cash flows for reporting purposes, is not
necessarily the most accurate discount factor. The effective interest rate at
various times and the risks associated with us or the natural gas and crude oil
industry in general will affect the accuracy of the 10% discount factor.
Our operations are subject to the numerous risks of natural gas and crude oil
drilling and production activities.
Our natural gas and crude oil drilling and production activities are
subject to numerous risks, many of which are beyond our control. These risks
include the risk of fire, explosions, blow-outs, pipe failure, abnormally
pressured formations and environmental hazards. Environmental hazards include
oil spills, natural gas leaks, ruptures and discharges of toxic gases. In
addition, title problems, weather conditions and mechanical difficulties or
shortages or delays in delivery of drilling rigs and other equipment could
negatively affect our operations. If any of these or other similar industry
operating risks occur, we could have substantial losses. Substantial losses also
may result from injury or loss of life, severe damage to or destruction of
property, clean-up responsibilities, regulatory investigation and penalties and
suspension of operations. In accordance with industry practice, we maintain
insurance against some, but not all, of the risks described above. We cannot
assure you that our insurance will be adequate to cover losses or liabilities.
Also, we cannot predict the continued availability of insurance at premium
levels that justify its purchase.
We operate in a highly competitive industry which may adversely affect our
operations.
We operate in a highly competitive environment. The principal resources
necessary for the exploration and production of natural gas and crude oil are
leasehold prospects under which natural gas and crude oil reserves may be
discovered, drilling rigs and related equipment to explore for such reserves and
knowledgeable personnel to conduct all phases of natural gas and crude oil
operations. We must compete for such resources with both major natural gas and
17
crude oil companies and independent operators. Many of these competitors have
financial and other resources substantially greater than ours. Although we
believe our current operating and financial resources are adequate to preclude
any significant disruption of our operations in the immediate future, we cannot
assure you that such materials and resources will be available to us.
The unavailability or high cost of drilling rigs, equipment, supplies,
insurance, personnel and crude oil field services could adversely affect our
ability to execute our exploration and development plans on a timely basis and
within our budget.
Our industry is cyclical and, from time to time, there is a shortage of
drilling rigs, equipment, supplies, insurance or qualified personnel. During
these periods, the costs and delivery times of rigs, equipment and supplies are
substantially greater. In addition, the demand for, and wage rates of, qualified
drilling rig crews rise as the number of active rigs in service increases. As a
result of increasing levels of exploration and production in response to strong
prices of natural gas and crude oil, the demand for oilfield services has risen
and the costs of these services are increasing.
Our natural gas and crude oil operations are subject to various Federal, state
and local regulations that materially affect our operations.
Matters regulated include permits for drilling operations, drilling and
abandonment bonds, reports concerning operations, the spacing of wells and
unitization and pooling of properties and taxation. At various times, regulatory
agencies have imposed price controls and limitations on production. In order to
conserve supplies of natural gas and crude oil, these agencies have restricted
the rates of flow of natural gas and crude oil wells below actual production
capacity. Federal, state and local laws regulate production, handling, storage,
transportation and disposal of natural gas and crude oil, by-products from
natural gas and crude oil and other substances and materials produced or used in
connection with natural gas and crude oil operations. To date, our expenditures
related to complying with these laws and for remediation of existing
environmental contamination have not been significant. We believe that we are in
substantial compliance with all applicable laws and regulations. However, the
requirements of such laws and regulations are frequently changed. We cannot
predict the ultimate cost of compliance with these requirements or their effect
on our operations.
Risks Related to the Common Stock
We do not pay dividends on common stock.
We have never paid a cash dividend on our common stock and the terms of
the revolving credit facility and the indenture relating to the notes limit our
ability to pay dividends on our common stock.
Shares eligible for future sale may depress our stock price.
At March 21, 2006, we had 42,588,327 shares of common stock outstanding
of which 3,991,679 shares were held by affiliates and, in addition, 2,588,963
shares of common stock were subject to outstanding options granted under certain
stock option plans (of which 1,699,838 shares were vested at March 21, 2006).
All of the shares of common stock held by affiliates are restricted or
control securities under Rule 144 promulgated under the Securities Act of 1933,
as amended (the "Securities Act"). The shares of the common stock issuable upon
exercise of the stock options have been registered under the Securities Act.
Sales of shares of common stock under Rule 144 or another exemption under the
Securities Act or pursuant to a registration statement could have a material
adverse effect on the price of the common stock and could impair our ability to
raise additional capital through the sale of equity securities.
18
The price of our common stock has been volatile and could continue to fluctuate
substantially.
Our common stock is traded on The American Stock Exchange. The market
price of our common stock has been volatile and could fluctuate substantially
based on a variety of factors, including the following:
o fluctuations in commodity prices;
o variations in results of operations;
o legislative or regulatory changes;
o general trends in the industry;
o market conditions; and
o analysts' estimates and other events in the natural gas and
crude oil industry.
We may issue shares of preferred stock with greater rights than our common
stock.
Subject to the rules of The American Stock Exchange, our articles of
incorporation authorize our board of directors to issue one or more series of
preferred stock and set the terms of the preferred stock without seeking any
further approval from holders of our common stock. Any preferred stock that is
issued may rank ahead of our common stock in terms of dividends, priority and
liquidation premiums and may have greater voting rights than our common stock.
Anti-takeover provisions could make a third party acquisition of Abraxas
difficult.
Our articles of incorporation and bylaws provide for a classified board
of directors, with each member serving a three-year term, and eliminate the
ability of stockholders to call special meetings or take action by written
consent. Each of the provisions in the articles of incorporation and bylaws
could make it more difficult for a third party to acquire Abraxas without the
approval of our board. In addition, the Nevada corporate statute also contains
certain provisions that could make an acquisition by a third party more
difficult.
An active market may not develop for our common stock.
Our common stock is quoted on The American Stock Exchange. While there
is currently one specialist in our common stock, this specialist is not
obligated to continue to make a market in our common stock. In this event, the
liquidity of our common stock could be adversely impacted and a stockholder
could have difficulty obtaining accurate stock quotes.
Future issuance of additional shares of our common stock could cause dilution of
ownership interests and adversely affect our stock price.
We may in the future issue our previously authorized and unissued
securities, resulting in the dilution of the ownership interests of our current
stockholders. We are currently authorized to issue 200,000,000 shares of common
stock with such rights as determined by our board of directors. The potential
issuance of such additional shares of common stock may create downward pressure
on the trading price of our common stock. We may also issue additional shares of
our common stock or other securities that are convertible into or exercisable
for common stock for capital raising or other business purposes. Future sales of
substantial amounts of common stock, or the perception that sales could occur,
could have a material adverse effect on the price of our common stock.
Item 1B. Unresolved Staff Comments
None.
19
Item 2. Properties
Primary Operating Areas
Texas
Our operations are concentrated in south and west Texas with over 99%
of the PV-10 of our natural gas and crude oil properties at December 31, 2005
located in those two regions. We operate 91% of our wells in Texas. During 2005,
we drilled a total of eight new wells (eight net) in Texas with an 88% success
rate, with a total of 1.1 Bcfe of our 2005 production attributable to new wells
drilled in Texas. Operations in south Texas are concentrated along the Edwards
trend in Live Oak, DeWitt and Lavaca Counties, the Frio/Vicksburg trend in San
Patricio County and the Wilcox trend in Goliad and DeWitt Counties. In total in
south Texas, we own an average 93% working interest in 46 wells with average
production of 200 net Bbls of crude oil and 6,778 net Mcf of natural gas per day
for the year ended December 31, 2005. As of December 31, 2005, we had estimated
net proved reserves in South Texas of 30.3 Bcfe (84% natural gas) with a PV-10
of $107.0 million, 61% of which was attributable to proved developed reserves.
Our west Texas operations are concentrated along the deep
Devonian/Montoya/Ellenburger formations and shallow Cherry Canyon sandstones in
Ward County, the Sharon Ridge Clearfork Field in Scurry and Mitchell Counties
and Devonian, Woodford and Wolfcamp formations in Pecos County. We drilled one
well in west Texas that contributed approximately 10% of our 2005 production and
is currently contributing approximately 30% of our production.
In total in west Texas, we own an average 74% working interest in 165
wells with average daily production of 296 net Bbls of crude oil and NGLs and
9,735 net Mcf of natural gas per day for the year ended December 31, 2005. As of
December 31, 2005, we had estimated net proved reserves in west Texas of 73.0
Bcfe (83% natural gas) with a PV-10 of $201.9 million, 42% of which was
attributable to proved developed reserves.
In the Oates SW Field of west Texas, our workover rig continues to
clean out the vertical section on a Devonian re-entry well, which after reaching
approximately 12,500', we plan to drill horizontally. We plan to continue
development of the Oates SW Field throughout 2006, targeting the shallower
Wolfcamp, Atoka and Woodford formations in addition to the deeper Devonian. In
the multi-well re-completion program elsewhere in the Delaware Basin of West
Texas, we are currently recovering completion fluid from two wells that were
fracture stimulated in the Atoka formation while a third well, which was
re-completed to the Wolfcamp formation, is flowing oil and gas. We plan to
re-complete or fracture stimulate four to six additional wells in this program
during 2006. In the Sharon Ridge Field located in Scurry County, Texas, we have
begun drilling a shallow well targeting the Clear Fork formation at a depth of
3,500'. We plan to drill one additional in-fill well in this field in 2006.
Wyoming
We currently hold 52,994 acres in the Powder River Basin in east
central Wyoming. We have drilled and operate ten wells in Converse and Niobrara
counties that were completed in the Muddy, Mowry, Turner, and Niobrara
formations. Four of these wells were drilled in the latter part of 2005 and are
currently undergoing completion and stimulation. We own a 100% working interest
in these wells that produced an average of 37 net barrels of crude oil per day
in 2005. As of December 31, 2005, we had estimated net proved producing reserves
in Wyoming of 242,036 barrels of crude oil with a PV-10 of $3.0 million.
In Brooks Draw, Wyoming, production testing continues on the four wells
drilled in late 2005. Since the beginning of 2006, one additional formation has
been perforated and awaits fracture stimulation and a previously completed
formation has been re-stimulated. We plan to complete additional zones as
service equipment becomes available. Once all of the formations are completed
and tested individually, they will be commingled and an ultimate sustained rate
of production can be obtained. We plan to drill several more wells in Wyoming
during the second half of 2006.
20
Exploratory and Developmental Acreage
Our principal natural gas and crude oil properties consist of
non-producing and producing natural gas and crude oil leases, including reserves
of natural gas and crude oil in place. The following table indicates our
interest in developed and undeveloped acreage and fee mineral acreage applicable
to continuing operations as of December 31, 2005:
Developed Undeveloped Fee Mineral
Acreage (1) Acreage (2) Acreage (3)
------------------------ --------------------------- ----------------------- --------------
Total
Gross Net Gross Net Gross Net Net
Acres(4) Acres (5) Acres(4) Acres (5) Acres (6) Acres Acres
------------ ------------ ------------ ------------- ------------- --------- --------------
South Texas 6,271 5,842 1,236 1,158 - - 7,000
West Texas 19,117 14,570 18,135 12,315 12,007 5,272 32,157
Wyoming 3,360 3,360 49,634 45,833 - - 49,193
N. Dakota - - 80 24 - - 24
------------ ------------ ------------ ------------- ------------- --------- --------------
Total 28,748 23,772 69,085 59,330 12,007 5,272 88,374
============ ============ ============ ============= ============= ========= ==============
- ---------------
(1) Developed acreage consists of leased acres spaced or assignable to
productive wells.
(2) Undeveloped acreage is considered to be those leased acres on which
wells have not been drilled or completed to a point that would permit
the production of commercial quantities of natural gas and crude oil,
regardless of whether or not such acreage contains proved reserves.
(3) Fee mineral acreage represents fee simple absolute ownership of the
mineral estate or fraction thereof.
(4) Gross acres refers to the number of acres in which we own a working
interest.
(5) Net acres represents the number of acres attributable to an owner's
proportionate working interest (e.g., a 50% working interest in a lease
covering 320 acres is equivalent to 160 net acres).
(6) Includes 7,484 acres that are included in developed and undeveloped
gross acres.
Productive Wells
The following table sets forth our total gross and net productive wells
applicable to continuing operations, expressed separately for natural gas and
crude oil, as of December 31, 2005:
Productive Wells (1)
As of December 31, 2005
---------------------------------------------------------------------
State Crude Oil Natural Gas
------------------------------- -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
South Texas 17.0 17.0 29.0 26.0
West Texas 128.0 99.5 37.0 22.6
Wyoming 10.0 10.0 18.0 -
N. Dakota - - 1.0 -
--------------- -------------- --------------- ----------------
Total 155.0 126.5 85.0 48.6
=============== ============== =============== ================
- ------------
(1) Productive wells are producing wells and wells capable of production.
(2) A gross well is a well in which we own an interest.
(3) A net well is deemed to exist when the sum of fractional ownership
working interests in gross wells equals one.
Reserves Information
The natural gas and crude oil reserves have been estimated as of
December 31, 2005, December 31, 2004, and December 31, 2003, by DeGolyer and
MacNaughton, of Dallas, Texas. Natural gas and crude oil reserves, and the
estimates of the present value of future net revenues there-from, were
determined based on then current prices and costs. Reserve calculations involve
21
the estimate of future net recoverable reserves of natural gas and crude oil and
the timing and amount of future net revenues to be received therefrom. Such
estimates are not precise and are based on assumptions regarding a variety of
factors, many of which are variable and uncertain.
The following table sets forth certain information regarding estimates
of our crude oil, natural gas liquids and natural gas reserves as of December
31, 2003, December 31, 2005 and December 31, 2005 relating to continuing
operations.
Estimated Proved Reserves
------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of December 31, 2005
Crude oil (MBbls) 1,942 1,142 3,084
Natural gas (MMcf) 38,794 47,409 86,203
As of December 31, 2004
Crude oil (MBbls) 1,878 1,223 3,101
Natural gas (MMcf) 36,241 38,877 75,118
As of December 31, 2003
Crude oil (MBbls) 1,791 1,264 3,055
NGLs (MBbls) 95 170 265
Natural gas (MMcf) 39,371 40,831 80,202
The process of estimating crude oil and natural gas reserves is complex
and involves decisions and assumptions in the evaluation of available
geological, geophysical, engineering and economic data. Therefore, these
estimates are imprecise.
Actual future production, natural gas and crude oil prices, revenues,
taxes, development expenditures, operating expenses and quantities of
recoverable natural gas and crude oil reserves most likely will vary from those
estimated. Any significant variance could materially affect the estimated
quantities and present value of reserves set forth in this annual report. In
addition, we may adjust estimates of proved reserves to reflect production
history, results of exploitation and development, prevailing natural gas and
crude oil prices and other factors, many of which are beyond our control.
You should not assume that the present value of future net revenues
referred to in this annual statement is the current market value of our
estimated natural gas and crude oil reserves. In accordance with SEC
requirements, the estimated discounted future net cash flows from proved
reserves are generally based on prices and costs as of the end of the year of
the estimate, or alternatively, if prices subsequent to that date have
increased, a price near the periodic filing date of the Company's financial
statements. Because we use the full cost method to account for our natural gas
and crude oil operations, we are susceptible to significant non-cash charges
during times of volatile commodity prices because the full cost pool may be
impaired when prices are low. This is known as a "ceiling limitation
write-down". This charge does not impact cash flow from operating activities but
does reduce our stockholders' equity and reported earnings. We have experienced
ceiling limitation write-downs in the past and we cannot assure you that we will
not experience additional ceiling limitation write-downs in the future. For more
information regarding the full cost method of accounting, you should read the
information under "Management's Discussion and Analysis of Financial Condition
and Results of Operation - Critical Accounting Policies".
Actual future prices and costs may be materially higher or lower than
the prices and costs as of the end of the year of the estimate. Any changes in
consumption by natural gas purchasers or in governmental regulations or taxation
will also affect actual future net cash flows. The timing of both the production
and the expenses from the development and production of natural gas and crude
oil properties will affect the timing of actual future net cash flows from
proved reserves and their present value. In addition, the 10% discount factor,
which is required by the SEC to be used in calculating discounted future net
cash flows for reporting purposes, is not necessarily the most accurate discount
22
factor. The effective interest rate at various times and the risks associated
with us or the natural gas and crude oil industry in general will affect the
accuracy of the 10% discount factor.
The estimates of our reserves are based upon various assumptions about
future production levels, prices and costs that may not prove to be correct over
time. In particular, estimates of natural gas and crude oil reserves, future net
revenue from proved reserves and the PV-10 thereof for the natural gas and crude
oil properties described in this report are based on the assumption that future
natural gas and crude oil prices remain the same as natural gas and crude oil
prices at December 31, 2005. The average sales prices as of such date used for
purposes of such estimates were $56.92 per Bbl of crude oil and $8.84 per Mcf of
natural gas. It is also assumed that we will make future capital expenditures of
approximately $84.2 million in the aggregate, most of which is in the years 2006
through 2009, which are necessary to develop and realize the value of proved
undeveloped reserves on our properties. Any significant variance in actual
results from these assumptions could also materially affect the estimated
quantity and value of reserves set forth herein.
We file reports of our estimated natural gas and crude oil reserves
with the Department of Energy. The reserves reported to this agency are required
to be reported on a gross operated basis and therefore are not comparable to the
reserve data reported herein.
Crude Oil, Natural Gas Liquids, and Natural Gas Production and Sales Prices
The following table presents our net crude oil, net natural gas liquids
and net natural gas production, the average sales price per Bbl of crude oil and
natural gas liquids and per Mcf of natural gas produced and the average cost of
production per Mcfe of production sold, for the three years ended December 31,
2005 related to continuing operations:
2005 2004 2003
--------------- -------------- --------------
Crude oil production (Bbls) 194,366 220,409 220,135
Natural gas production (Mcf) 4,942,355 4,403,030 4,780,739
Natural gas liquids production (Bbls) - 8,875 9,439
Total production (Mmcfe) (2) 6,109 5,779 6,158
Average sales price per Bbl of crude oil $ 53.27 $ 40.12 $ 30.43
Average sales price per Mcf of natural
gas (1) $ 7.48 $ 5.45 $ 4.77
Average sales price per Bbl of natural
gas liquids $ - $ 26.32 $ 20.46
Average sales price per Mcfe $ 7.75 $ 5.72 $ 4.82
Average cost of production per Mcfe
produced (2) $ 1.82 $ 1.48 $ 1.35
- ------------------
(1) Average sales prices are net of hedging activity.
(2) Natural gas and crude oil were combined by converting crude oil and
natural gas liquids to a Mcf equivalent on the basis of 1 Bbl of crude
oil and natural gas liquid equals 6 Mcf of natural gas. Production
costs include direct operating costs, ad valorem taxes and gross
production taxes.
Drilling Activities
The following table sets forth our gross and net working interests in
exploratory and development wells drilled, related to continuing operations
during the three years ended December 31, 2005:
23
2005 2004 2003
-------------------------- ----------------------------- -----------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ----------- ---------- --------
Exploratory(3)
Productive(4)
Crude oil 1.0 1.0 2.0 2.0 1.0 1.0
Natural gas 1.0 1.0 - - - -
Dry holes(5) - - - - - -
------------ ---------- ------------ ---------- ---------- --------
Total 2.0 2.0 2.0 2.0 1.0 1.0
============ ========== ============ ========== ========== ========
Development(6)
Productive (4)
Crude oil 4.0 4.0 - - - -
Natural gas 5.0 5.0 1.0 1.0 5.0 5.0
Dry holes (5) 1.0 1.0 1.0 1.0 - -
------------ ---------- ------------ ---------- ---------- --------
Total 10.0 10.0 2.0 2.0 5.0 5.0
============ ========== ============ ========== ========== ========
- ------------------
(1) A gross well is a well in which we own an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce natural gas
or crude oil in an unproved area, to find a new reservoir in a field
previously found to be producing natural gas or crude oil in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable
of producing either natural gas or crude oil in sufficient quantities
to justify completion as a natural gas or crude oil well.
(6) A development well is a well drilled within the proved area of a
natural gas or crude oil reservoir to the depth of stratigraphic
horizon (rock layer or formation) noted to be productive for the
purpose of extracting proved natural gas or crude oil reserves.
As of March 21, 2006, we had 7 wells in process of drilling and/or
completing.
Office Facilities
Our executive and administrative offices are located at 500 North Loop
1604 East, Suite 100, San Antonio, Texas 78232, consisting of approximately
12,650 square feet leased through January 2009 at an aggregate base rate of
$20,773 per month. We also have an office in Midland, Texas consisting of 570
square feet leased through February 2008 at an aggregate base rate of $439 per
month.
Other Properties
We own 10 acres of land, an office building, workshop, warehouse and
house in Sinton, Texas, 2.8 acres of land, an office building in Scurry County,
Texas, 600 acres of fee land in Scurry County, Texas, 160 acres of land in Coke
County, Texas and 11,537 acres of fee land in Pecos County, Texas. We also own
22 vehicles which are used in the field by employees. We own 2 workover rigs,
which are used for servicing our wells.
Item 3. Legal Proceedings
From time to time, Abraxas is involved in litigation relating to claims
arising out of its operations in the normal course of business. At December 31,
2005, Abraxas was not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on Abraxas.
24
Item 4. Submission of Matters to a Vote of Security Holders
No matter was submitted to a vote of our security holders during the
fourth quarter of the fiscal year ended December 31, 2005.
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities
Market Information
Our common stock began trading on the American Stock Exchange on August
18, 2000, under the symbol "ABP." The following table sets forth certain
information as to the high and low sales price quoted for our common stock on
the American Stock Exchange.
Period High Low
------------- -------- ----------
2004
First Quarter $ 3.64 $ 1.29
Second Quarter 2.89 1.50
Third Quarter 2.37 1.09
Fourth Quarter 2.99 1.91
2005
First Quarter $ 2.92 $ 1.92
Second Quarter 3.38 2.15
Third Quarter 8.99 2.71
Fourth Quarter 9.25 5.15
2006 First Quarter (Through March 21, 2006) $ 7.25 $ 5.24
Holders
As of March 21, 2006, we had 42,588,327 shares of common stock
outstanding and had approximately 1,226 stockholders of record.
Dividends
We have not paid any cash dividends on our common stock and it is not
presently determinable when, if ever, we will pay cash dividends in the future.
In addition, the indenture governing our notes and our revolving credit facility
prohibit the payment of cash dividends and stock dividends on our common stock.
You should read the discussion under "Management's Discussion and Analysis of
Financial Condition and Results of Operations - Liquidity and Capital Resources"
for more information regarding the restrictions on our ability to pay dividends.
Item 6. Selected Financial Data
The following selected financial data as of and for the years ended is
derived from our Consolidated Financial Statements. The data should be read in
conjunction with our Consolidated Financial Statements and Notes thereto, and
other financial information included herein. See "Financial Statements" in Item
8.
Year Ended December 31,
----------------------------------------------------------------------------------
2005 2004 * 2003 * 2002* 2001 *
-------------- ------------- --------------- ---------------- ---------------
(Dollars in thousands except per share data)
Total revenue - continuing operations $ 48,625 $ 33,854 $ 30,380 $ 21,541 $ 35,775
Net income (loss) $ 19,117 (5) $ 12,360 (1) $ 56,798 (2) $ (119,197) (3) $ (23,769) (4)
Net income (loss) - discontinued
operations $ 12,846 (5) $ 3,323 $ 70,024 (2) $ (63,355) $ (4,870)
Net income (loss) - continuing
operations $ 6,271 $ 9,037 $ (13,226) $ (55,842) $ (18,899)
25
Net income (loss) per common share -
diluted $ 0.46 $ 0.32 $ 1.61 $ (3.98) $ (0.92)
Weighted average shares outstanding -
diluted (in thousands) 41,164 38,895 35,364 (6) 29,979 25,789
Total assets $ 121,866 $ 152,685 $ 126,437 $ 181,425 $ 303,616
Long-term debt, excluding current
maturities $ 129,527 $ 126,425 $ 184,649 $ 201,850 $ 209,611
Total stockholders' equity (deficit) $ (23,701) $ (53,464) $ (72,203) $ (142,254) $ (28,585)
* Net income (loss) and net income (loss) from continuing operations for 2004,
2003, 2002 and 2001 reflect the retrospective adoption of SFAS 123R.
------------------
(1) Includes gain on debt extinguishment of $12.6 million and a deferred tax
benefit of $6.1 million.
(2) Includes gain on sale of foreign subsidiaries of $ 68.9 million in 2003.
(3) Includes ceiling limitation write-down of $116.0 million ($28.2 million
related to continuing operations).
(4) Includes ceiling test write-down of $2.6 million in 2001, based on
subsequent (March 22, 2002) realized prices, related to discontinued
operations.
(5) Includes gain on the sale of foreign subsidiary of $17.3 million net of
non-cash tax of $6.1 million.
(6) For the year ended December 31, 2003, 711,928 shares were excluded from the
calculation of diluted earnings per share since their inclusion would have
been antidilutive.
Item 7. Management's Discussion And Analysis Of Financial Condition And Results
Of Operations
Prior to February 2005, Grey Wolf Exploration Inc. was a wholly-owned
Canadian subsidiary of Abraxas. In February 2005, Grey Wolf closed on an initial
public offering resulting in the substantial divestiture of our capital stock in
Grey Wolf. As a result of the Grey Wolf IPO, and the significant divestiture of
our interest in Grey Wolf, the results of operations of Grey Wolf are reflected
in our Financial Statements and in this document as "Discontinued Operations"
and our remaining operations are referred to in our Financial Statements and in
this document as "Continuing Operations" or "Continued Operations". Unless
otherwise noted, all disclosures are for continuing operations.
The following is a discussion of our consolidated financial condition,
results of continuing operations, liquidity and capital resources. This
discussion should be read in conjunction with our Consolidated Financial
Statements and the Notes thereto. See "Financial Statements" in Item 8.
General
We are an independent energy company primarily engaged in the
development, and production of natural gas and crude oil. Historically, we have
grown through the acquisition and subsequent development and exploitation of
producing properties, principally through the redevelopment of old fields
utilizing new technologies such as modern log analysis and reservoir modeling
techniques as well as 3-D seismic surveys and horizontal drilling. As a result
of these activities, we believe that we have a substantial inventory of
development opportunities, which provide a basis for significant production and
reserve increases. In addition, we intend to expand upon our exploitation and
development activities with complementary exploration projects in our core areas
of operation.
We have incurred net losses in two of the last five years, and there
can be no assurance that operating income and net earnings will be achieved in
future periods. Our financial results depend upon many factors which
significantly affect our results of operations including the following:
o the sales prices of natural gas and crude oil ;
o the level of total sales volumes of natural gas, natural gas
liquids and crude oil;
o the availability of, and our ability to raise additional capital
resources and provide liquidity to meet, cash flow needs;
26
o the level of and interest rates on borrowings; and
o the level and success of exploitation, exploration and
development activity.
Commodity Prices and Hedging Activities. Our results of operations are
significantly affected by fluctuations in commodity prices. Price volatility in
the natural gas market has remained prevalent in the last few years. In January
2001, our realized price for natural gas sales was at its highest level in our
operating history and the price of crude oil was also at a high level. However,
over the course of 2001 and the beginning of the first quarter of 2002, prices
again became depressed, primarily due to the economic downturn. Beginning in
March 2002, commodity prices began to increase and continued higher through
December 2005. Prices have continued to remain strong during the beginning of
2006 compared to historical levels, but have weakened from levels during the
latter part of 2005 and early 2006. If prices continue to weaken, our cash flow
from operations will be adversely affected.
The table below illustrates how natural gas prices have fluctuated over
the eight quarters prior to and including the quarter ended December 31, 2005
and contains the last three day average of NYMEX traded contracts price and the
prices we realized during each quarter presented, including the impact of our
hedging activities.
Natural Gas Prices by Quarter (in $ per Mcf)
Quarter Ended
----------------------------------------------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31, Mar. 31, June 30, Sept. 30, Dec. 31,
2004 2004 2004 2004 2005 2005 2005 2005
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
Index $5.69 $5.97 $5.85 $6.77 $6.30 $ 6.80 $ 8.21 $ 12.85
Realized $4.98 $5.52 $5.24 $6.14 $5.26 $ 6.33 $ 8.15 $ 9.12
The NYMEX natural gas price on March 21, 2006 was $6.87 per Mcf.
The table below illustrates how crude oil prices have fluctuated over
the eight quarters prior to and including the quarter ended December 31, 2005
and contains the last three day average of NYMEX traded contracts price and the
prices we realized during each quarter presented, including the impact of our
hedging activities.
Crude Oil Prices by Quarter (in $ per Bbl)
Quarter Ended
---------------------------------------------------------------------------------------------------------------
Mar. 31, June 30, Sept. 30, Dec. 31, Mar. 31, June 30, Sept. 30, Dec. 31,
2004 2004 2004 2004 2005 2005 2005 2005
---------- ---------- ----------- ---------- ---------- ---------- ---------- ----------
Index $34.76 $38.48 $42.32 $49.46 $47.33 $ 51.76 $ 60.26 $ 61.51
Realized $34.18 $37.29 $42.43 $46.81 $47.13 $ 49.43 $ 60.24 $ 57.18
The NYMEX crude oil price on March 21, 2006 was $60.57 per Bbl.
We seek to reduce our exposure to price volatility by hedging our
production primarily through price floors. In 2003 and 2005, we incurred hedging
cost of $842,000 and $592,000, respectively. For the year ended December 31,
2004, we recognized a gain from hedging activities of approximately $118,000.
Under the terms of our revolving credit facility, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our natural gas and crude oil production, on an equivalent basis, for a
rolling six month period. We currently have the following hedges in place:
Time Period Notional Quantities Price
- ------------------ --------------------------------------- ----------------
April 2006 10,000 MMbtu of production per day Floor of $7.00
May 2006 10,000 MMbtu of production per day Floor of $8.00
June 2006 10,000 MMbtu of production per day Floor of $8.00
July 2006 10,000 MMbtu of production per day Floor of $7.00
27
August 2006 10,000 MMbtu of production per day Floor of $6.00
September 2006 10,000 MMbtu of production per day Floor of $5.00
At December 31, 2005 the aggregate fair market value of our hedges was
approximately $76,000.
Production Volumes. Because our proved reserves will decline as natural
gas, natural gas liquids and crude oil are produced, unless we acquire
additional properties containing proved reserves or conduct successful
exploitation and development activities, our reserves and production will
decrease. Our ability to acquire or find additional reserves in the near future
will be dependent, in part, upon the amount of available funds for acquisition,
exploitation and development projects.
We had capital expenditures for 2005 of $35 million and have budgeted
approximately $40 million in 2006. Capital spending limitations that existed
under the terms of our prior senior credit agreement and our 11 1/2% notes due
2007 were removed in connection with the refinancing that closed in October
2004. As a result of the limitations, we were limited for most of 2004 in our
ability to replace existing production with new production. If crude oil and
natural gas prices return to depressed levels or if our production levels
continue to decrease, our revenues, cash flow from operations and financial
condition will be materially adversely affected.
Availability of Capital. As described more fully under "Liquidity and
Capital Resources" below, our sources of capital going forward will primarily be
cash from operating activities, funding under our revolving credit facility,
cash on hand, and if an appropriate opportunity presents itself, proceeds from
the sale of properties. We currently have approximately $9.2 million of
availability under our revolving credit facility. We may also seek equity
capital in order to fund our planned drilling expenditures.
Exploitation and Development Activity. We believe that our high quality
asset base, high degree of operational control and large inventory of drilling
projects position us for future growth. Our properties are concentrated in
locations that facilitate substantial economies of scale in drilling and
production operations and more efficient reservoir management practices. We
operate 95% of the properties accounting for approximately 94% of our PV-10,
giving us substantial control over the timing and incurrence of operating and
capital expenditures. In addition, we have 53 proved undeveloped projects and
have identified over 184 drilling and recompletion opportunities on our existing
acreage, the successful development of which we believe could significantly
increase our daily production and proved reserves.
Our future natural gas and crude oil production, and therefore our
success, is highly dependent upon our ability to find, acquire and develop
additional reserves that are profitable to produce. The rate of production from
our natural gas and crude oil properties and our proved reserves will decline as
our reserves are produced unless we acquire additional properties containing
proved reserves, conduct successful development and exploitation activities or,
through engineering studies, identify additional behind-pipe zones or secondary
recovery reserves. We cannot assure you that our exploitation and development
activities will result in increases in our proved reserves. In addition,
approximately 52% of our total estimated proved reserves at December 31, 2005
were undeveloped. By their nature, estimates of undeveloped reserves are less
certain. Recovery of such reserves will require significant capital expenditures
and successful drilling operations. For a more complete discussion of these
risks please see "Risk Factors--We may be unable to acquire or develop
additional reserves, in which case our results of operations and financial
condition would be adversely affected."
Borrowings and Interest. We currently have indebtedness of
approximately $130.8 million and availability of $9.2 million under the
revolving credit facility. We paid interest under our 11 1/2% secured notes due
2007 by the issuance of additional notes, which resulted in our interest paid in
cash to be $7.6 million during 2004. In connection with the refinancing
transactions completed in October 2004, interest on the notes, unlike interest
on the notes which were repaid in 2004, is paid in cash. Cash interest expense
was $14.0 million during 2005 and based on current interest rates and our
outstanding indebtedness at March 13, 2006, would be approximately $15.6 million
for 2006. This increase in cash interest expense has required us to increase our
production and cash flow from operations in order to meet our debt service
requirements, as well as to fund the development of our numerous drilling
opportunities.
28
Outlook for 2006. As a result of final 2005 financial results and
current market conditions, we have updated our operating and financial guidance
for year 2006 as follows:
Production:
BCFE (approximately 80% gas)....................... 7.5 - 8.5
Exit Rate (Mmcfe/d)................................... 22 - 24
Price Differentials (Pre Hedge):
Gas (% Mcf)........................................ 5%
Oil ($/Bbl)........................................ 1.00
Production taxes (% of Revenue) 10%
Direct Lease Operating Expenses ($/ Mcfe)............. 1.10
G&A ($/ Mcfe)......................................... 0.55
Interest ($/Mcfe)..................................... 2.00
DD&A ($/Mcfe)......................................... 1.50
Capital Expenditures ($ Millions)..................... 40.0
Results of Operations
Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented. All data has been restated to reflect
continuing operations.
Years Ended December 31
--------------------------------------------------------------
(dollars in thousands, except per unit data)
2005 2004 2003
------------------- ------------------- -------------------
Operating revenue(1):
Crude oil sales............................. $ 10,354 $ 8,843 $ 6,699
NGLs sales ................................. - 234 193
Natural gas sales........................... 36,960 23,996 22,818
Rig and other............................... 1,311 781 670
------------------- ------------------- -------------------
Total operating revenues ................... $ 48,625 $ 33,854 $ 30,380
=================== =================== ===================
Operating income (2)....................... $ 22,104 $ 12,165 $ 9,598
Crude oil production (MBbls)................ 194.4 220.4 220.1
NGLs production (MBbls)..................... - 8.9 9.4
Natural gas production (MMcf)............... 4,942.4 4,403.0 4,780.7
Average crude oil sales price (per Bbl) $ 53.27 $ 40.12 $ 30.43
Average NGLs sales price (per Bbl) $ - $ 26.32 $ 20.46
Average natural gas sales price (per Mcf) $ 7.48 $ 5.45 $ 4.77
- -------------------
(1) Revenue and average sales prices are net of hedging activities.
(2) Operating income for 2004 and 2003 reflect the retrospective adoption of
SFAS No. 123R "Share-Based Payment"
Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004
Operating Revenue. During the year ended December 31, 2005, operating
revenue from natural gas and crude oil sales increased by $14.2 million from
$33.1 million in 2004 to $47.3 million in 2005. The increase in revenue was
primarily due to increased commodity prices realized in 2005 as compared to
2004, as well as an increase in natural gas production volumes. Higher commodity
prices contributed $12.6 million to natural gas and crude oil revenue while
increased production volumes contributed $1.6 million to revenue.
In prior years we were being paid on certain wells for the natural gas
liquid content of the gas as a separate component as well as the value of the
residue gas after processing. In 2005 we elected to be paid for this natural gas
at the wellhead. Accordingly, we did not recognize any natural gas liquids
29
revenue in 2005. Crude oil sales volumes decreased slightly from 220.4 MBbls in
2004 to 194.4 MBbls during 2005. The decrease is primarily due to natural field
declines. In late 2005, we drilled four additional crude oil wells in Wyoming.
These wells are currently in various stages of completion, testing and
stimulation. Natural gas sales volumes increased from 4.4 Bcf in 2004 to 4.9 Bcf
in 2005. This increase is primarily due to new production during 2005 offset by
natural field declines. New production brought on line at various times during
2005 contributed 1.1 Bcf to natural gas production and was partially offset by
natural field decline.
Average sales prices in 2005 net of hedging costs were:
o $53.27 per Bbl of crude oil,
o $ 7.48 per Mcf of natural gas.
Average sales prices in 2004 net of hedging costs were:
o $40.12 per Bbl of crude oil,
o $26.32 per Bbl of natural gas liquids, and
o $ 5.45 per Mcf of natural gas.
Lease Operating Expense and Production Taxes. Lease operating expense,
or LOE, increased from $8.6 million in 2004 to $11.1 million in 2005. The
increase in LOE was primarily due to higher production taxes associated with
higher commodity prices in 2005 as compared to 2004 as well as a general
increase in the cost of field services and the amount of services required by us
as we increased our drilling activity during 2005 as compared to 2004. Our LOE
on a per Mcfe basis for the year ended December 31, 2005 was $1.82 per Mcfe
compared to $1.48 per Mcfe in 2004. The increase on a per Mcfe basis was due to
increased cost in 2005 as compared to 2004.
G&A Expense. G&A expense increased from $5.1 million in 2004 to $5.5
million in 2005. The increase in G&A expense in 2005 was primarily due to higher
performance bonuses in 2005 as compared to 2004. Our G&A expense on a per Mcfe
basis increased from $0.89 in 2004 to $0.90 in 2005. The increase in the per
Mcfe cost was due to increased expense in 2005 as compared to 2004.
Stock-based Compensation. Effective July 1, 2000, the Financial
Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain
Transactions Involving Stock Compensation", an interpretation of Accounting
Principles Board Opinion No. ("APB") 25. Under the interpretation, certain
modifications to fixed stock option awards, which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price on all options with an
existing exercise price greater than $2.06 to $2.06. In January 2003, we amended
the exercise price to $0.66 per share on certain options with an existing
exercise price greater than $0.66 per share which resulted in variable
accounting treatment on these options. Under the rules of variable accounting,
we recognized the difference in the market price of our common stock as of the
end of the period and the exercise price of $0.66. Subsequently, if the market
price of our common stock increased from the previous period, we recognized
expense; conversely, if the price decreased we recognized a gain. Prior to the
adoption of SFAS No.123R, as discussed below, we had charged approximately $1.3
million to stock based compensation expense in 2004 related to these repricings.
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment".
SFAS No. 123R is a revision of SFAS No. 123, "Accounting for Stock Based
Compensation", and supersedes APB 25. Among other items, SFAS 123R eliminates
the use of APB 25 and the intrinsic value method of accounting, and requires
companies to recognize the cost of employee services received in exchange for
awards of equity instruments, based on the grant date fair value of those
awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. In December 2005, we elected early adoption
of SFAS 123R.
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method or a "modified retrospective" method. Under the
"modified prospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
30
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. Under the "modified retrospective" method, the requirements
are the same as under the "modified prospective" method, but also permits
entities to restate financial statements of previous periods based on proforma
disclosures made in accordance with SFAS 123. We elected to use the "modified
retrospective" method, and have accordingly restated prior year financial
statements to reflect this method.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized stock-based compensation of $247,000 during 2005 as a result of
the adoption of this accounting change compared to $112,000 in 2004, as
restated.
We currently utilize a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by us on the alternative models available to value option grants,
and in conjunction with the type and number of stock options expected to be
issued in the future, we have determined that we will continue to use the
Black-Scholes model for option valuation as of the current time.
DD&A Expense. Depreciation, depletion and amortization expense
increased from $7.2 million in 2004 to $8.9 million in 2005. The increase in
DD&A was primarily due to increased production volumes in 2005 and increased
capital expenditures in 2005 as compared to 2004. Our DD&A expense on a per Mcfe
basis for 2005 was $1.46 per Mcfe as compared to $1.25 per Mcfe in 2004.
Interest Expense. Interest expense decreased from $17.9 million to
$14.0 million for 2005 compared to 2004. The decrease in interest expense was
due to decreased debt levels during 2005. While the outstanding debt at December
31, 2005 was slightly higher than the balance as December 31, 2004, the level of
debt during the course of 2004, prior to the financial restructuring that
occurred in October 2004, was significantly higher. In addition, during most of
2004, interest on our then outstanding secured notes was payable by the issuance
of additional notes, which caused our cash interest expense in 2004 to be $7.6
million. With the issuance of the notes in October 2004, interest is payable in
cash, which led to all of the interest paid in 2005 being paid in cash.
Financing Costs. Financing costs in 2004 were $1.7 million compared to
zero in 2005. Financing costs represent costs related to refinancing activities,
which do not qualify for amortization over the life of the debt. The 2004 costs
relate to the refinancing activities during 2004. We did not undertake any
refinancing activities in 2005.
Income from discontinued operations. Income from discontinued
operations was $12.8 million in 2005 compared to $3.3 million in 2004. On
February 28, 2005, Grey Wolf Exploration Inc. completed an IPO resulting in
Abraxas substantially divesting itself of its investment in Grey Wolf. The
operations of Grey Wolf, previously reported as a business segment, are reported
as discontinued operations for all periods presented in the accompanying
financial statements and the operating results are reflected separately from the
results of continuing operations.
Income from discontinued operations for the period ended December 31,
2005 includes a gain on the disposal of Grey Wolf of $17.3 million, net of
non-cash income tax of $6.1 million, and a loss from operations, including debt
retirement costs, of $4.4 million. Income from discontinued operations for the
year ended December 31, 2004 represents the operating results of Grey Wolf for
the year then ended.
Comparison of Year Ended December 31, 2004 to Year Ended December 31, 2003
Operating Revenue. During the year ended December 31, 2004, operating
revenue from crude oil, natural gas and natural gas liquids sales increased by
$3.4 million from $29.7 million in 2003 to $33.1 million in 2004. The increase
in revenue was primarily due to increased commodity prices realized in 2004 as
compared to 2003. The increase in revenue due to commodity prices was partially
offset by decreased production volumes. Higher commodity prices contributed $5.2
million to natural gas and crude oil revenue while reduced production volumes
had a $1.8 million negative impact on revenue.
31
Natural gas liquids volumes declined from 9.4 MBbls in 2003 to 8.9
MBbls in 2004. Crude oil sales volumes increased slightly from 220.1 MBbls in
2003 to 220.4 MBbls during 2004. The increase is primarily due to the production
from new wells in Wyoming and west Texas brought onto production in 2004,
offsetting natural field declines in other areas. Natural gas sales volumes
decreased from 4.8 Bcf in 2003 to 4.4 Bcf in 2004. This decrease is primarily
due to natural field declines. There were no significant wells brought on line
in 2004, primarily due to significant restrictions on capital expenditures for
most of the year.
Average sales prices in 2004 net of hedging costs were:
o $40.12 per Bbl of crude oil,
o $26.32 per Bbl of natural gas liquids, and
o $ 5.45 per Mcf of natural gas.
Average sales prices in 2003 net of hedging costs were:
o $30.43 per Bbl of crude oil,
o $20.46 per Bbl of natural gas liquids, and
o $ 4.77 per Mcf of natural gas.
Lease Operating Expense. Lease operating expense, or LOE, increased
slightly from $8.3 million in 2003 to $8.6 million in 2004. The increase in LOE
was primarily due to higher production taxes associated with higher commodity
prices in 2004 as compared to 2003. Our LOE on a per Mcfe basis for the year
ended December 31, 2004 was $1.48 per Mcfe compared to $1.35 for 2003, primarily
due to the decrease in production volumes.
G&A Expense. G&A expense increased from $4.0 million in 2003 to $5.1
million in 2004. The increase in G&A expense was primarily due to performance
bonuses in 2004. Our G&A expense on a per Mcfe basis increased from $0.65 in
2003 to $0.89 in 2004. The increase in the per Mcfe cost was due to increased
expense and to lower production volumes in 2004 as compared to 2003.
Stock-based Compensation Expense. Effective July 1, 2000, the Financial
Accounting Standards Board ("FASB") issued FIN 44, "Accounting for Certain
Transactions Involving Stock Compensation", an interpretation of Accounting
Principles Board Opinion No. ("APB") 25. Under the interpretation, certain
modifications to fixed stock option awards, which were made subsequent to
December 15, 1998, and not exercised prior to July 1, 2000, require that the
awards be subject to variable accounting until they are exercised, forfeited, or
expired. In March 1999, we amended the exercise price on all options with an
existing exercise price greater than $2.06 to $2.06. In January 2003, we amended
the exercise price to $0.66 per share on certain options with an existing
exercise price greater than $0.66 per share which resulted in variable
accounting treatment on these options. Under the rules of variable accounting,
we recognized the difference in the market price of our common stock as of the
end of the period and the exercise price of $0.66. Subsequently, if the market
price of our common stock increased from the previous period, we recognized
expense; conversely, if the price decreased, we recognized a gain. Prior to the
adoption of SFAS No. 123R, as discussed below, we had charged approximately $1.3
million to stock based compensation expense in 2004 related to these repricings.
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment".
SFAS No. 123R is a revision of SFAS No. 123, "Accounting for Stock Based
Compensation", and supersedes APB 25. Among other items, SFAS 123R eliminates
the use of APB 25 and the intrinsic value method of accounting, and requires
companies to recognize the cost of employee services received in exchange for
awards of equity instruments, based on the grant date fair value of those
awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. In December 2005, we elected early adoption
of SFAS 123R.
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method or a "modified retrospective" method. Under the
"modified prospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
32
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. Under the "modified retrospective" method, the requirements
are the same as under the "modified prospective" method, but also permits
entities to restate financial statements of previous periods based on proforma
disclosures made in accordance with SFAS 123. We elected to use the "modified
retrospective" method, and have accordingly restated prior year financial
statements to reflect this method.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized a reduction of stock-based compensation of $1.2 million during
2004 as a result of the adoption of this accounting change. Restated stock-based
compensation expense was $228,000 and $112,000 for 2003 and 2004, respectively.
We currently utilize a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to Employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by us on the alternative models available to value option grants,
and in conjunction with the type and number of stock options expected to be
issued in the future, we have determined that we will continue to use the
Black-Scholes model for option valuation as of the current time.
DD&A Expense. Depreciation, depletion and amortization expense
decreased from $7.6 million in 2003 to $7.2 million in 2004. The decrease in
DD&A was primarily due to decreased production volumes in 2004. Our DD&A expense
on a per Mcfe basis for 2004 was $1.25 per Mcfe as compared to $1.24 per Mcfe in
2003.
Interest Expense. Interest expense increased from $16.3 million to
$17.9 million for 2004 compared to 2003. The increase in interest expense was
due to increased debt levels in 2004, prior to the refinancing completed in
October 2004. The increase in debt was primarily due to the payment of interest
by the issuance of additional notes pursuant to the 11 1/2% notes due 2007,
which were repaid in October 2004. Cash interest expense was $7.6 million in
2004 and $3.6 million in 2003.
Financing Costs. Financing costs in 2004 were $1.7 million compared to
$4.4 million in 2003. Financing costs represent costs related to refinancing
activities, which do not qualify for amortization over the life of the debt.
Financing costs in 2003 were related to the restructuring transaction, which
occurred in January 2003. The 2004 costs relate to the refinancing activities
during 2004.
Income from discontinued operations. Income from discontinued
operations was $3.3 million in 2004 compared to $70.0 million in 2003. This
represents income from Grey Wolf, which was sold in February 2005. Income in
2003 included a gain on the sale of foreign subsidiaries in January 2003 of
$68.9 million. Excluding this gain, income in 2003 would have been $1.1 million.
The increase in income in 2004, exclusive of the gain, was due to increased
production and higher commodity prices in 2004 as compared to 2003.
Liquidity and Capital Resources
General. The natural gas and crude oil industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in additional natural gas and crude oil
properties; and
o production and transportation facilities.
The amount of capital expenditures we are able to make has a direct
impact on our ability to increase cash flow from operations and, thereby, will
directly affect our ability to service our debt obligations and to continue to
grow the business through the development of existing properties and the
acquisition of new properties.
33
Our sources of capital going forward will primarily be cash from
operating activities, funding under our revolving credit facility, and if an
appropriate opportunity presents itself, proceeds from the sale of properties.
We may also seek equity capital although we may not be able to complete any
equity financings on terms acceptable to us, if at all. In addition, under the
terms of the notes, proceeds of optional sales of our assets that are not timely
reinvested in new natural gas and crude oil assets will be required to be used
to reduce indebtedness and proceeds of mandatory sales must be used to repay or
redeem indebtedness.
Working Capital (Deficit). The following discussion represents working
capital from continuing operations. At December 31, 2005 our current liabilities
of approximately $15.2 million exceeded our current assets of $10.3 million
resulting in a working capital deficit of $4.9 million. This compares to a
working capital deficit of $4.6 million as of December 31, 2004. Current
liabilities as of December 31, 2005 consisted of trade payables of $9.8 million,
revenues due third parties $3.5 million, accrued interest of $1.4 million and
other accrued liabilities of $ 0.5 million.
Capital Expenditures. Capital expenditures related to our continuing
operations in 2005, 2004 and 2003 were $35.4 million, $9.3 million and $9.2
million, respectively. The table below sets forth the components of these
capital expenditures for the three years ended December 31, 2005.
Year Ended December 31
------------------------------------------------------------
2005 2004 2003
------------------- -------------------- ------------------
(dollars in thousands)
Expenditure category:
Development $ 34,991 $ 9,088 $ 9,158
Facilities and other 359 181 36
------------------- -------------------- ------------------
Total $ 35,350 $ 9,269 $ 9,194
=================== ==================== ==================
During 2005, 2004 and 2003, capital expenditures were primarily for the
development of existing properties. We anticipate making capital expenditures
for 2006 of approximately $40.0 million which will be used primarily for the
development of our current properties. These anticipated expenditures are
subject to adequate cash flow from operations and availability under our
revolving credit facility. If these sources of funding do not prove to be
sufficient, we may also issue additional shares of equity securities although we
may not be able to complete equity financings on terms acceptable to us, if at
all. Our ability to make all of our budgeted capital expenditures will also be
subject to availability of drilling rigs and other field equipment and services.
Our capital expenditures could also include expenditures for acquisition of
producing properties if such opportunities arise, but we currently have no
agreements, arrangements or undertakings regarding any material acquisitions. We
have no material long-term capital commitments and are consequently able to
adjust the level of our expenditures as circumstances dictate. Additionally, the
level of capital expenditures will vary during future periods depending on
market conditions and other related economic factors. Should the prices of
natural gas and crude oil continue to decline and if our costs of operations
continue to increase as a result of the scarcity of drilling rigs or if our
production volumes decrease, our cash flows will decrease which may result in a
reduction of the capital expenditures budget. If we decrease our capital
expenditures budget, we may not be able to offset natural gas and crude oil
production volumes decreases caused by natural field declines and sales of
producing properties, if any.
Sources of Capital. The net funds provided by and/or used in each of
the operating, investing and financing activities, related to continuing
operations, are summarized in the following table and discussed in further
detail below:
Year Ended December 31,
-------------------------------------------------
2005 2004 2003
------------- ----------- ---------------
(dollars in thousands)
Net cash provided by operating activities $ 21,099 $ 27,000 $ 11,479
Net cash used in investing activities (35,350) (9,269) (9,194)
Net cash provided by (used in) financing activities
14,877 (65,684) (88,652)
------------- ----------- ---------------
Total $ 626 $ (47,953) $ (86,367)
============= =========== ===============
34
Operating activities for the year ended December 31, 2005 provided us
with $21.1 million of cash. Expenditures in 2005 of approximately $35.4 were
primarily for the development of natural gas and crude oil properties. Financing
activities provided $14.9 million during 2005, of which $11.3 million was
provided by a private placement of common stock, $28.4 million was provided from
long-term borrowing offset by $25.3 million of payments on long-term debt.
Operating activities for the year ended December 31, 2004 provided us
with $27.0 million of cash. Investing activities used $9.3 million during 2004
primarily for the development of natural gas and crude oil properties. Financing
activities used $65.7 million during 2004, primarily for payments on long-term
debt and deferred financing fees.
Operating activities for the year ended December 31, 2003 provided us
with $11.5 million of cash. Investing activities used $9.2 million during 2003.
Financing activities used $88.7 million during 2003. Most of these funds were
used to reduce our long-term debt and were generated by the sale of our Canadian
subsidiaries and an exchange offer completed in January 2003. The sale of our
Canadian subsidiaries contributed $85.8 million in 2003 reduced by $9.2 million
in exploitation and development expenditures. Expenditures in 2003 were
primarily for the development of natural gas and crude oil properties.
Future Capital Resources. We currently have three principal sources of
liquidity going forward: (i) cash from operating activities, (ii) funding under
our revolving credit facility, and (iii) if an appropriate opportunity presents
itself, the sale of producing properties. If these sources of liquidity do not
prove to be sufficient, we may also issue additional shares of equity securities
although we may not be able to complete equity financings on terms acceptable to
us, if at all. While we are no longer subject to limitations on capital
expenditures under our 11 1/2% secured notes due 2007, covenants under the
indenture for the notes and the revolving credit facility restrict our use of
cash from operating activities, cash on hand and any proceeds from asset sales.
Under the terms of the notes, proceeds of optional sales of our assets that are
not timely reinvested in new natural gas and crude oil assets will be required
to be used to reduce indebtedness and proceeds of mandatory sales must be used
to redeem indebtedness. The terms of the notes and the revolving credit facility
also substantially restrict our ability to:
o incur additional indebtedness;
o grant liens;
o pay dividends or make certain other restricted payments;
o merge or consolidate with any other person; or
o sell, assign, transfer, lease, convey or otherwise dispose of all or
substantially all of our assets.
Our cash flow from operations depends heavily on the prevailing prices
of natural gas and crude oil and our production volumes of natural gas and crude
oil. Although we have hedged a portion of our natural gas and crude oil
production and will continue this practice as required pursuant to the revolving
credit facility, future natural gas and crude oil price declines would have a
material adverse effect on our overall results, and therefore, our liquidity.
Low natural gas and crude oil prices could also negatively affect our ability to
raise capital on terms favorable to us or at all.
Our cash flow from operations will also depend upon the volume of
natural gas and crude oil that we produce. Unless we otherwise expand reserves,
our production volumes may decline as reserves are produced. Due to sales of
properties in 2002 and 2003 and the divestiture of Grey Wolf during the first
quarter of 2005, and restrictions on capital expenditures under the terms of our
11 1/2% secured notes due 2007 (which were refinanced in October 2004), we now
have significantly reduced reserves and production as compared with pre-2003
levels. In the future, if an appropriate opportunity presents itself, we may
sell additional properties, which could further reduce our production volumes.
To offset the loss in production volumes resulting from natural field declines
and sales of producing properties, we must conduct successful, exploitation,
exploration and development activities, acquire additional producing properties
or identify additional behind-pipe zones or secondary recovery reserves. We
believe our numerous drilling opportunities will allow us to increase our
production volumes; however, our drilling activities are subject to numerous
risks, including the risk that no commercially productive natural gas or crude
oil reservoirs will be found. The risk of not finding commercially productive
reservoirs will be compounded by the fact that 52% of our total estimated proved
35
reserves at December 31, 2005 were undeveloped. During 2005, we expended
approximately $35.0 million for twelve wells in south Texas, west Texas and
Wyoming. We are currently completing and/or testing multiple Woodford, Atoka and
Wolfcamp wells in west Texas and continue to recomplete various wells in South
Texas. In the latter part of the year we drilled and are currently completing
and testing four vertical wells in Wyoming. . In addition, approximately 30% of
our production at March 13, 2006 was from a single well in west Texas. If
production from this well decreases, the volume of our production would also
decrease which, in turn, would likely cause our cash flow from operations to
decrease.
Our total indebtedness and cash interest expense as a result of issuing
the notes and entering into the revolving credit facility require us to increase
our production and cash flow from operations in order to meet our debt service
requirements, as well as to fund the development of our numerous drilling
opportunities. The ability to satisfy these new obligations will depend upon our
drilling success as well as prevailing commodity prices.
Contractual Obligations. We are committed to making cash payments in
the future on the following types of agreements:
o Long-term debt
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have
not guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
December 31, 2005.
Payments due in:
------------------------------------------------------------------------
Contractual Obligations (dollars
in thousands) Total 2006 2007-2008 2009-2010 Thereafter
- ---------------------------------- --------------- ------------- ------------- -------------- -------------
Long-Term Debt (1) $ 129,527 $ - $ 4,527 $ 125,000 $ -
Interest on long-term debt (2) 60,200 15,473 30,885 13,842 -
Operating Leases (3) 780 254 505 21 -
--------------- ------------- ------------- -------------- -------------
Total $ 190,507 $ 15,727 $ 35,917 $ 138,863 $ -
=============== ============= ============= ============== =============
- -------------------
(1) These amounts represent the balances outstanding under the revolving
credit facility and the notes. These repayments assume that we will not
draw down additional funds.
(2) Interest expense assumes the balances of long-term debt at the end of the
period and current effective interest rates.
(3) Office lease obligations. The lease for office space expires in January
2009.
Contingencies.
From time to time, we are involved in litigation relating to claims
arising out of our operations in the normal course of business. At December 31,
2005 we were not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on the
Company.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploitation development and production of
crude oil and natural gas. In the past, we have funded our operations and
capital expenditures primarily through cash flow from operations, sales of
properties, sales of production payments and borrowings under our bank credit
facilities and other sources. Given our high degree of operating control, the
timing and incurrence of operating and capital expenditures is largely within
our discretion.
Long-Term Indebtedness.
The following table sets forth our long-term indebtedness as of
December 31, 2005 and 2004.
36
Long Term Indebtedness
December 31,
---------------------------------
2005 2004
----------------- ---------------
(in thousands)
Floating rate senior secured notes due 2009........................ $ 125,000 $ 125,000
Senior secured revolving credit facility........................... 4,527 1,425
----------------- ---------------
129,527 126,425
Less current maturities ........................................... - -
----------------- ---------------
$ 129,527 $ 126,425
================= ===============
Floating Rate Senior Secured Notes due 2009. In connection with the
October 2004 financial restructuring, Abraxas issued $125 million in principal
aggregate amount of Floating Rate Senior Secured Notes due 2009. The notes will
mature on December 1, 2009 and began accruing interest from the date of
issuance, October 28, 2004, at a per annum floating rate of six-month LIBOR plus
7.50%. The initial interest rate on the notes was 9.72% per annum. The interest
will be reset semi-annually on each June 1 and December 1, commencing on June 1,
2005. The current interest rate is 12.08% per annum. Interest is payable
semi-annually in arrears on June 1 and December 1 of each year, commencing on
June 1, 2005.
The notes rank equally among themselves and with all of our
unsubordinated and unsecured indebtedness, including our revolving credit
facility and senior in right of payment to our existing and future subordinated
indebtedness.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest including any additional interest on, the notes on a senior
secured basis. In addition, any other subsidiary or affiliate of ours, that in
the future guarantees any other indebtedness with us, or our restricted
subsidiaries, will also be required to guarantee the notes.
The notes and the Subsidiary Guarantors' guarantees thereof, together
with our revolving credit facility and the Subsidiary Guarantors' guarantees
thereof, are secured by shared first priority perfected security interests,
subject to certain permitted encumbrances, in all of our and each of our
restricted subsidiaries' material property and assets, including substantially
all of our and their natural gas and crude oil properties and all of the capital
stock (or in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
The notes may be redeemed, at our election, as a whole or from time to
time in part, at any time after April 28, 2007, upon not less than 30 nor more
that 60 days' notice to each holder of notes to be redeemed, subject to the
conditions and at the redemption prices (expressed as percentages of principal
amount) set forth below, together with accrued and unpaid interest and
Liquidating Damages, if any, to the applicable redemption date.
Year Percentage
------------------------------------------ -------------------------
From April 29, 2007 to April 28, 2008 104.00%
From April 29, 2008 to April 28, 2009 102.00%
After April 28, 2009 100.00%
Prior to April 28, 2007, we may redeem up to 35% of the aggregate
original principal amount of the notes using the net proceeds of one or more
equity offerings, in each case at the redemption price equal to the product of
(i) the principal amount of the notes being so redeemed and (ii) a redemption
price factor of 1.00 plus the per annum interest rate on the notes (expressed as
a decimal) on the applicable redemption date plus accrued and unpaid interest to
the applicable redemption date, provided certain conditions are also met.
If we experience specific kinds of change of control events, each
holder of notes may require us to repurchase all or any portion of such holder's
notes at a purchase price equal to 101% of the principal amount of the notes,
plus accrued and unpaid interest to the date of repurchase.
37
The indenture governing the notes contains covenants that, among other
things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including
nonpayment of principal or interest, violations of covenants, cross default and
cross acceleration to certain other indebtedness, including our new credit
facility and bridge loan, bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we
entered into an agreement for a revolving credit facility having a maximum
commitment of $15 million, which includes a $2.5 million subfacility for letters
of credit. Availability under the revolving credit facility is subject to a
borrowing base consistent with normal and customary natural gas and crude oil
lending transactions.
Outstanding amounts under the revolving credit facility bear interest
at the prime rate announced by Wells Fargo Bank, National Association plus
1.00%. Subject to earlier termination rights and events of default, the stated
maturity date under the revolving credit facility is October 28, 2008.
We are permitted to terminate the revolving credit facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders' aggregate commitment under the revolving credit facility. Such
termination and each such reduction is subject to a premium equal to the
percentage listed below multiplied by the lenders' aggregate commitment under
the revolving credit facility, or, in the case of partial reduction, the amount
of such reduction.
Year % Premium
-------------- --------------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of its restricted subsidiaries will be required to guarantee our obligations
under the revolving credit facility. Obligations under the revolving credit
facility are secured, together with the notes, by a shared first priority
perfected security interest, subject to certain permitted encumbrances, in all
of our and each of our restricted subsidiaries' material property and assets,
including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
38
Under the revolving credit facility, we are subject to customary
covenants, including certain financial covenants and reporting requirements. The
revolving credit facility requires us to maintain a minimum net cash interest
coverage and also requires us to enter into hedging agreements on not less than
25% or more than 75% of our projected natural gas and crude oil production.
In addition to the foregoing and other customary covenants, the
revolving credit facility contains a number of covenants that, among other
things, restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain types
of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
The revolving credit facility also contains customary events of
default, including nonpayment of principal or interest, violations of covenants,
cross default and cross acceleration to certain other indebtedness, bankruptcy
and material judgments and liabilities, and is subject to an Intercreditor,
Security and Collateral Agency Agreement, which specifies the rights of the
parties thereto to the proceeds from the Collateral.
Intercreditor Agreement. The holders of the notes, together with the
lenders under our revolving credit facility, are subject to an Intercreditor,
Security and Collateral Agency Agreement, which specifies the rights of the
parties thereto to the proceeds from the Collateral. The Intercreditor
Agreement, among other things, (i) creates security interests in the Collateral
in favor of a collateral agent for the benefit of the holders of the notes and
the credit facility lenders and (ii) governs the priority of payments among such
parties upon notice of an event of default under the indenture or the revolving
credit facility.
So long as no such event of default exists, the collateral agent will
not collect payments under the credit facility documents or the indenture
governing the notes and other note documents (collectively, the "Secured
Documents"), and all payments will be made directly to the respective creditor
under the applicable Secured Document. Upon notice of an event of default and
for so long as an event of default exists, payments to each credit facility
lender and holder of the notes from us and our current subsidiaries and proceeds
from any disposition of any collateral, will, subject to limited exceptions, be
collected by the collateral agent for deposit into a collateral account and then
distributed as provided in the following paragraph.
Upon notice of any such event of default and so long as an event of
default exists, funds in the collateral account will be distributed by the
collateral agent generally in the following order of priority:
39
first, to reimburse the collateral agent for expenses incurred
in protecting and realizing upon the value of the Collateral;
second, to reimburse the credit facility administrative agent
and the trustee, on a pro rata basis, for expenses incurred in
protecting and realizing upon the value of the Collateral while any of
these parties was acting on behalf of the Control Party (as defined
below);
third, to reimburse the credit facility administrative agent
and the trustee, on a pro rata basis, for expenses incurred in
protecting and realizing upon the value of the Collateral while any of
these parties was not acting on behalf of the Control Party;
fourth, to pay all accrued and unpaid interest (and then any
unpaid commitment fees) under the credit facility;
fifth, if the collateral coverage value of three times the
outstanding obligations under the credit facility would be met after
giving effect to any payment under this clause "fifth," to pay all
accrued and unpaid interest on the notes;
sixth, to pay all outstanding principal of (and then any other
unpaid amounts, including, without limitation, any fees, expenses,
premiums and reimbursement obligations) the credit facility;
seventh, to pay all accrued and unpaid interest on the notes
(if not paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any
other unpaid amounts, including, without limitation, any premium with
respect to) the notes; and
ninth, to pay each credit facility lender, holder of the
notes, and other secured parties, on a pro rata basis, all other
amounts outstanding under the credit facility and the notes.
To the extent there exists any excess monies or property in the
collateral account after all of our and our subsidiaries' obligations under the
credit facility, the indenture and the notes are paid in full, the collateral
agent will be required to return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party" which for purposes of the
Intercreditor Agreement is the holders of the notes and the credit facility
lenders, acting as a single class, by vote of the holders of a majority of the
aggregate principal amount of outstanding obligations under the notes and the
credit facility.
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the credit facility administrative agent certifying that the proposed
sale or other disposition of assets is either permitted or required by, and is
in accordance with the provisions of, the applicable Secured Documents and (iii)
the collateral agent has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
40
Hedging Activities
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. Under our revolving credit facility, we are required to maintain
hedge positions on not less than 25% or more than 75% of our projected oil and
gas production for a six month rolling period. See "--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
Net Operating Loss Carryforwards
At December 31, 2005, we had, subject to the limitation discussed
below, $190.0 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire through 2025 if not utilized.
Uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, we have established a valuation allowance of $73.0 million and $67.0
million for deferred tax assets at December 31, 2004 and 2005, respectively.
Related Party Transactions
Abraxas has adopted a policy that transactions between Abraxas and its
officers, directors, principal stockholders, or affiliates of any of them, will
be on terms no less favorable to Abraxas than can be obtained on an arm's length
basis in transactions with third parties and must be approved by the vote of at
least a majority of the disinterested directors.
Critical Accounting Policies
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for natural gas and crude oil
activities. SEC Regulation S-X defines the financial accounting and reporting
standards for companies engaged in natural gas and crude oil activities. Two
methods are prescribed: the successful efforts method and the full cost method.
We have chosen to follow the full cost method under which all costs associated
with property acquisition, exploitation and development are capitalized. We also
capitalize internal costs that can be directly identified with our acquisition,
exploitation and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Under the
successful efforts method, geological and geophysical costs and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred. Costs of drilling exploratory wells that do not result in proved
reserves are charged to expense. Depreciation, depletion, amortization and
impairment of natural gas and crude oil properties are generally calculated on a
well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of natural gas
and crude oil properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization rate on our
natural gas and crude oil properties.
At the time it was adopted, management believed that the full cost
method would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. We have experienced this
situation several times over the years, most recently in 2002. Our natural gas
and crude oil reserves have a relatively long life. However, temporary drops in
commodity prices can have a material impact on our business including impact
from the full cost method of accounting.
Under full cost accounting rules, the net capitalized cost of natural
gas and crude oil properties may not exceed a "ceiling limit" which is based
upon the present value of estimated future net cash flows from proved reserves
41
on a pool by pool basis, discounted at 10%, plus the lower of cost or fair
market value of unproved properties and the cost of properties not being
amortized, less income taxes. If net capitalized costs of natural gas and crude
oil properties exceed the ceiling limit, we must charge the amount of the excess
to earnings. This is called a "ceiling limitation write-down." This charge does
not impact cash flow from operating activities, but does reduce our
stockholders' equity and reported earnings. The risk that we will be required to
write down the carrying value of natural gas and crude oil properties increases
when natural gas and crude oil prices are depressed or volatile. In addition,
write-downs may occur if we experience substantial downward adjustments to our
estimated proved reserves or if purchasers cancel long-term contracts for our
natural gas production. An expense recorded in one period may not be reversed in
a subsequent period even though higher natural gas and crude oil prices may have
increased the ceiling applicable to the subsequent period.
For the year ended December 31, 2002, we recorded a ceiling limitation
write-down due to low commodity prices. We cannot assure you that we will not
experience additional write-downs in the future.
Estimates of Proved Natural Gas and Crude Oil Reserves. Estimates of
our proved reserves included in this report are prepared in accordance with GAAP
and SEC guidelines. The accuracy of a reserve estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was based on
evaluations prepared by independent petroleum engineers. Estimates prepared by
other third parties may be higher or lower than those included herein. Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
You should not assume that the present value of future net cash flows
is the current market value of our estimated proved reserves. In accordance with
SEC requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A expense
will increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher cost
fields.
Asset Retirement Obligations. The estimated costs of restoration and
removal of facilities are accrued. The fair value of a liability for an asset's
retirement obligation is recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense.
Hedge Accounting. From time to time, we use commodity price hedges to
limit our exposure to fluctuations in natural gas and crude oil prices. Results
of those hedging transactions are reflected in natural gas and crude oil sales.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities", was effective
for us on January 1, 2001. SFAS 133, as amended and interpreted, establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging activities.
In 2003 we elected out of hedge accounting as prescribed by SFAS 133.
42
Accordingly all derivatives, whether designated in hedging relationships or not,
are required to be recorded at fair value on our balance sheet. Changes in fair
value of contracts are recognized in earnings in the current period.
Due to the volatility of natural gas and crude oil prices and, to a
lesser extent, interest rates, our financial condition and results of operations
can be significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2005 and 2004 the net market value of our
derivatives was an asset of $75,817 and $528,165 respectively.
Share-Based Payments. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment". SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
those awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. The Company has elected early adoption of
SFAS 123R .
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method, or a "modified retrospective" method. Under the
"modified prospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. Under the "modified retrospective" method, the requirements
are the same as under the "modified prospective" method, but also permit
entities to restate financial statements of previous periods based on proforma
disclosures made in accordance with SFAS 123. The Company has elected to use the
"modified retrospective" method. This standard requires the cost of all
share-based payments, including stock options, to be measured at fair value on
the grant date and recognized in the statement of operations. In accordance with
this standard, all periods prior to January 1, 2005 were restated to reflect the
impact of the standard as if it had been adopted on January 1, 1995, the
original effective date of SFAS No. 123, "Accounting for Stock-Based
Compensation". Also in accordance with the standard, the amounts that are
reported in the statement of operations for the restated periods are the pro
forma amounts previously disclosed under SFAS No. 123.
The Company currently utilizes a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by the Company on the alternative models available to value option
grants, and in conjunction with the type and number of stock options expected to
be issued in the future, the Company has determined that it will continue to use
the Black-Scholes model for option valuation as of the current time.
SFAS 123R includes several modifications to the way that income taxes
are recorded in the financial statements. The expense for certain types of
option grants is only deductible for tax purposes at the time that the taxable
event takes place, which could cause variability in the Company's effective tax
rates recorded throughout the year. SFAS 123R does not allow companies to
"predict" when these taxable events will take place. Furthermore, it requires
that the benefits associated with the tax deductions in excess of recognized
compensation cost be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement will
reduce net operating cash flows and increase net financing cash flows in periods
after the effective date. These future amounts cannot be estimated, because they
depend on, among other things, when employees exercise stock options.
New Accounting Pronouncements
In March 2005 the FASB issued Interpretation No. 47 "Accounting for
Conditional Asset Retirement Obligations--an interpretation of FASB Statement
No. 143". This Interpretation clarifies that the term conditional asset
retirement obligation as used in FASB Statement No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Thus, the timing and (or) method of settlement may be conditional on a future
event. Accordingly, an entity is required to recognize a liability for the fair
43
value of a conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when
incurred--generally upon acquisition, construction, or development and (or)
through the normal operation of the asset. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists. Statement 143 acknowledges that in some cases, sufficient information
may not be available to reasonably estimate the fair value of an asset
retirement obligation. This Interpretation also clarifies when an entity would
have sufficient information to reasonably estimate the fair value of an asset
retirement obligation.
This Interpretation is effective no later than the end of fiscal years
ending after December 15, 2005 (December 31, 2005, for calendar-year
enterprises). Retrospective application for interim financial information is
permitted but is not required. Early adoption of this Interpretation is
encouraged. This statement did not effect the Company's financial statements for
the period ended December 31, 2005.
In May 2005, the FASB issued "Summary of Statement No. 154 Accounting
Changes and Error Corrections" - a replacement of APB Opinion No. 20 and FASB
Statement No. 3. This Statement replaces APB Opinion No. 20, Accounting Changes,
and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial
Statements, and changes the requirements for the accounting for and reporting of
a change in accounting principle. This Statement applies to all voluntary
changes in accounting principle. It also applies to changes required by an
accounting pronouncement in the unusual instance that the pronouncement does not
include specific transition provisions. When a pronouncement includes specific
transition provisions, those provisions should be followed.
Opinion 20 previously required that most voluntary changes in
accounting principle be recognized by including in net income of the period of
the change the cumulative effect of changing to the new accounting principle.
This Statement requires retrospective application to prior periods' financial
statements of changes in accounting principle, unless it is impracticable to
determine either the period-specific effects or the cumulative effect of the
change. When it is impracticable to determine the period-specific effects of an
accounting change on one or more individual prior periods presented, this
Statement requires that the new accounting principle be applied to the balances
of assets and liabilities as of the beginning of the earliest period for which
retrospective application is practicable and that a corresponding adjustment be
made to the opening balance of retained earnings (or other appropriate
components of equity or net assets in the statement of financial position) for
that period rather than being reported in an income statement. When it is
impracticable to determine the cumulative effect of applying a change in
accounting principle to all prior periods, this Statement requires that the new
accounting principle be applied as if it were adopted prospectively from the
earliest date practicable.
This Statement defines retrospective application as the application of
a different accounting principle to prior accounting periods as if that
principle had always been used or as the adjustment of previously issued
financial statements to reflect a change in the reporting entity. This Statement
also redefines restatement as the revising of previously issued financial
statements to reflect the correction of an error.
This Statement requires that retrospective application of a change in
accounting principle be limited to the direct effects of the change. Indirect
effects of a change in accounting principle, such as a change in
non-discretionary profit-sharing payments resulting from an accounting change,
should be recognized in the period of the accounting change.
This Statement also requires that a change in depreciation,
amortization, or depletion method for long-lived, non-financial assets be
accounted for as a change in accounting estimate effected by a change in
accounting principle.
This Statement carries forward without change the guidance contained in
Opinion 20 for reporting the correction of an error in previously issued
financial statements and a change in accounting estimate.
This Statement also carries forward the guidance in Opinion 20
requiring justification of a change in accounting principle on the basis of
preferability.
44
This statement is effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005. This statement
did not effect the Company's financial statements for the period ended December
31, 2005.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent natural gas and crude oil producer, our revenue, cash
flow from operations, other income and equity earnings and profitability,
reserve values, access to capital and future rate of growth are substantially
dependent upon the prevailing prices of crude oil, natural gas and natural gas
liquids. Declines in commodity prices will adversely affect our financial
condition, liquidity, ability to obtain financing and operating results. Lower
commodity prices may reduce the amount of natural gas and crude oil that we can
produce economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for natural gas and crude oil
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. Assuming the production levels we
attained during the year ended December 31, 2005, a 10% decline in natural gas
and crude oil, prices would have reduced our operating revenue and cash flow by
approximately $4.7 million for the year.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS
138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. In 2003 we elected not to designate derivative instruments
as hedges. Accordingly the instruments are recorded on the balance sheet at fair
value with changes in the market value of the derivatives being recorded in
current oil and gas revenue.
Under the terms of our revolving credit facility, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our natural gas and crude oil production for a rolling six month period.
All hedge transactions are subject to our risk management policy, which
has been approved by the Board of Directors.
We currently have the following hedges in place:
Time Period Notional Quantities Price
- ----------------------- --------------------------------------- --------------
April 2006 10,000 MMbtu of production per day Floor of $7.00
May 2006 10,000 MMbtu of production per day Floor of $8.00
June 2006 10,000 MMbtu of production per day Floor of $8.00
July 2006 10,000 MMbtu of production per day Floor of $7.00
August 2006 10,000 MMbtu of production per day Floor of $6.00
September 2006 10,000 Mmbtu of production per day Floor of $5.00
At December 31, 2005 the aggregate fair market value of our hedges was
approximately $76,000.
Interest rate risk
At December 31, 2005, as a result of the financial restructuring that
occurred in October 2004, we had $125.0 million in outstanding indebtedness
under the floating rate senior secured notes due 2009. The notes bear interest
at a per annum rate of six-month LIBOR plus 7.5%. The rate is redetermined on
June 1 and December 1 of each year, beginning June 1, 2005. The current rate on
the notes is 12.08%. For every percentage point that the LIBOR rate rises, our
interest expense would increase by approximately $1.3 million on an annual
45
basis. At December 31, 2005, we had $4.5 million of outstanding indebtedness
under our revolving credit facility. Interest on this facility accrues at the
prime rate announced by Wells Fargo Bank plus 1.00%. For every percentage point
increase in the announced prime rate, our interest expense would increase by
approximately $45,000 on an annual basis.
Item 8. Financial Statements
For the financial statements and supplementary data required by this
Item 8, see the Index to Consolidated Financial Statements.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. As of the end of the period covered
by this report, we carried out an evaluation, under the supervision and with the
participation of management, including our Chief Executive Officer and Chief
Financial Officer, of the effectiveness of our disclosure controls and
procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934,
or the Exchange Act). Based on that evaluation, our Chief Executive Officer and
our Chief Financial Officer concluded that our disclosure controls and
procedures are effective to ensure that the information required to be disclosed
by us in the reports that we file or submit under the Exchange Act is recorded,
processed, summarized and reported within the time periods specified in SEC
rules and forms.
Management's Annual Report on Internal Control over Financial Reporting
and Attestation Report of Registered Public Accounting Firm. Pursuant to Section
404 of the Sarbanes-Oxley Act of 2002, we have included a report of management's
assessment of the design and effectiveness of our internal controls as part of
this Annual Report on Form 10-K for the fiscal year ended December 31, 2005. BDO
Seidman, LLP, our registered public accountants, also attested to, and reported
on, management's assessment of the effectiveness of internal control over
financial reporting. Management's report and the independent public accounting
firms attestation report are included in our 2005 Financial Statements in Item
15 under the captions "Management's Report on Internal Control over Financial
Reporting" and "Report of Independent Registered Public Accounting Firm" and are
incorporated herein by reference.
Changes in Internal Control over Financial Reporting. As of the end of
the period covered by this report, we carried out an evaluation, under the
supervision and with the participation of our Chief Executive Officer and Chief
Financial Officer, of our internal control over financial reporting to determine
whether any changes occurred during the fourth quarter of 2005 that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting. Based on that evaluation, there were no
changes in our internal control over financial reporting or in other factors
that have materially affected or are reasonably likely to materially affect our
internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
There is incorporated in this Item 10 by reference that portion of our
definitive proxy statement for the 2006 Annual Meeting of Stockholders which
appears therein under the captions "Election of Directors". See also the
information in Item 4a of Part I of this Report.
46
Audit Committee and Audit Committee Financial Expert
The Audit Committee of our board of directors consists of C. Scott
Bartlett, Jr., Frank M. Burke, Paul Powell and Joseph A. Wagda. The board of
directors has determined that each of the members of the Audit Committee is
independent as determined in accordance with the listing standards of the
American Stock Exchange and Item 7(d) (3) (iv) of Schedule 14A of the Exchange
Act. In addition, the board of directors has determined that C. Scott Bartlett,
Jr., as defined by SEC rules, is an audit committee financial expert.
Section 16(a) Compliance
Section 16(a) of the Exchange Act requires Abraxas directors and
executive officers and persons who own more than 10% of a registered class of
Abraxas equity securities to file with the Securities and Exchange Commission
and the AMEX initial reports of ownership and reports of changes in ownership of
Abraxas common stock. Officers, directors and greater than 10% stockholders are
required by SEC regulations to furnish us with copies of all such forms they
file. Based solely on a review of the copies of such reports furnished to us and
written representations that no other reports were required. We believe that all
our directors and executive officers complied on a timely basis with all
applicable filing requirements under Section 16(a) of the Exchange Act during
2005.
Item 11. Executive Compensation
There is incorporated in this Item 11 by reference that portion of our
definitive proxy statement for the 2006 Annual Meeting of Stockholders which
appears therein under the caption "Executive Compensation", except for those
parts under the captions "Compensation Committee Report on Executive
Compensation", "Performance Graph", "Audit Committee Report" and "Report on
Repricing of Options."
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
There is incorporated in this Item 12 by reference that portion of our
definitive proxy statement for the 2006 Annual Meeting of Stockholders which
appears therein under the caption "Securities Holdings of Principal
Stockholders, Directors and Officers".
Item 13. Certain Relationships and Related Transactions
There is incorporated in this Item 13 by reference that portion of our
definitive proxy statement for the 2006 Annual Meeting of Stockholders which
appears therein under the caption "Certain Transactions".
Item 14. Principal Accounting Fees and Services
There is incorporated in this Item 14 by reference that portion of our
definitive proxy statement for the 2006 Annual Meeting of Stockholders which
appears therein under the caption "Principal Auditor Fees and Services".
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)1. Consolidated Financial Statements
Page
Management's Report on Internal Control over Financial Reporting...........................F-2
Report of Independent Registered Public Accounting Firm....................................F-3
Report of Independent Registered Public Accounting Firm on Internal Control
Over Financial Reporting...............................................................F-4
47
Consolidated Balance Sheets at December 31, 2004 and 2005..................................F-5
Consolidated Statements of Operations for the years ended December 31, 2003
2004 and 2005............................................................................F-7
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2003, 2004 and 2005.........................................................F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2003,
2004 and 2005............................................................................F-9
Consolidated Statements of Other Comprehensive Income (loss) for the years ended
December 31, 2003, 2004 and 2005.........................................................F-11
Notes to Consolidated Financial Statements ................................................F-12
(a) 2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
(a) 3. Exhibits
The following Exhibits have previously been filed by the Registrant or
are included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to our
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration
Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration
Statement).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated
June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on
Form S-3, No. 333-00398 (the "S-3 Registration Statement")).
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated
as of August 12, 2000 (Filed as Exhibit 3.5 to our Annual Report of
Form 10-K filed April 2, 2001).
3.6 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.6 to
Abraxas' Annual Report on Form 10-K filed April 5, 2002).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to
the S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2
to our Annual Report on Form 10-K filed on March 31, 1995).
4.3 Indenture dated October 28, 2004, by and among Abraxas, as Issuer; the
Subsidiary Guarantors party thereto and U.S. Bank National Association,
as Trustee, relating to Abraxas' Floating Rate Senior Secured Notes Due
2009. (Filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K
filed on November 3, 2004).
48
4.4 Form of Rule 144A Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-1 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.5 Form of Regulation S Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-2 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.6 Form of Accredited Investor Certificated Note for Floating Rate Senior
Secured Notes due 2009. (Filed as Exhibit A-3 to Exhibit 4.1 to
Abraxas' Current Report on Form 8-K filed on November 3, 2004).
*10.1 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to Abraxas' Registration Statement on Form S-4, No.
333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.2 Abraxas Petroleum Corporation Director Stock Option Plan. (Filed as
Exhibit 10.5 to the 1996 Exchange Offer Registration Statement).
*10.3 Abraxas Petroleum Corporation Restricted Share Plan for Directors.
(Filed as Exhibit 10.20 to Abraxas' Annual Report on Form 10-K filed on
April 12, 1994).
*10.4 Abraxas Petroleum Corporation Amended and Restated 1994 Long Term
Incentive Plan. (Filed as Exhibit 10.4 to Abraxas' Registration
Statement on Form S-4 filed on January 12, 2005).
*10.5 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed
as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
10.6 Form of Indemnity Agreement between Abraxas and each of its directors
and officers. (Filed as Exhibit 10.30 to the 1993 S-1).
10.7 Loan Agreement dated as of October 28, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors party thereto, Wells
Fargo Foothill, Inc., as Arranger and Administrative Agent and the
Lenders signatory thereto. (Filed as Exhibit 10.2 to Abraxas' Current
Report on Form 8-K filed November 3, 2004).
10.8 Loan Agreement dated as of October 28, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors party thereto,
Guggenheim Corporate Funding, LLC, as Arranger and Administrative Agent
and the Lenders signatory thereto. (Filed as Exhibit 10.3 to Abraxas'
Current Report on Form 8-K filed November 3, 2004).
*10.9 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.19 to the 2000 S-1 Registration Statement).
*10.10 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.20 to the 2000 S-1 Registration Statement).
*10.11 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).
*10.12 Employment Agreement between Abraxas and William H. Wallace. (Filed as
Exhibit 10.27 to the S-3 Registration Statement).
*10.13 Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as
Exhibit 10.28 to the S-3 Registration Statement).
49
10.14 Intercreditor, Security and Collateral Agency Agreement dated as of
October 28, 2004 by and among Abraxas Petroleum Corporation, the
Subsidiary Guarantors party thereto, Wells Fargo Foothill, Inc.,
Guggenheim Corporate Funding, LLC and U.S. Bank National Association.
(Filed as Exhibit 10.5 to Abraxas' Current Report on Form 8-K filed
November 3, 2004).
*10.15 Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term
Equity Incentive Plan. (Filed as Exhibit 10.1 to Abraxas' Current
Report on Form 8-K filed June 6, 2005).
*10.16 Form of Stock Option Agreement under the Abraxas Petroleum Corporation
2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as
Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed June 6,
2005).
*10.17 Abraxas Peteroleum Corporation Senior Management Incentive Bonus Plan
2006 (Filed herewith).
10.18 Common Stock Purchase Agreement made and entered into as of the 20th
day of July, 2005, by and between Abraxas Petroleum Corporation and the
Purchasers signatory thereto. (Filed as Exhibit 10.1 to Abraxas'
Current Report on Form 8-K filed July 22, 2005).
14.1 Abraxas Petroleum Corporation Code of Business Conduct and Ethics
(filed herewith)
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas, Grey Wolf
Exploration Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation and
Eastside Coal Company, Inc.'s Registration Statement on Form S-1, No.
333-103027).
23.1 Consent of BDO Seidman, LLP (filed herewith)
23.2 Consent of DeGolyer and MacNaughton. (filed herewith).
31.1 Certification - Chief Executive Officer (filed herewith)
31.2 Certification - Chief Financial Officer (filed herewith)
32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
* Management Compensatory Plan or Agreement.
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.
ABRAXAS PETROLEUM CORPORATION
By:/s/ Robert L.G. Watson By: /s/ Chris E. Williford
--------------------------------- ---------------------------------
Robert L.G. Watson Chris E. Williford
President and Principal Exec. Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED: March 22, 2006
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Signature Name and Title Date
--------- -------------- ----
/s/ Robert L.G. Watson Chairman of the Board,
- ---------------------------- President (Principal Executive
Robert L.G. Watson Officer)and Director March 22, 2006
/s/ Chris E. Williford Exec. Vice President and
- ---------------------------- Treasurer (Principal Financial
Chris E. Williford and Accounting Officer) March 22, 2006
/s/ Craig S. Bartlett, Jr. Director March 22, 2006
- ----------------------------
Craig S. Bartlett, Jr.
/s/ Franklin A. Burke Director March 22, 2006
- ----------------------------
Franklin A. Burke
/s/ Harold D. Carter Director March 22, 2006
- ----------------------------
Harold D. Carter
/s/ Ralph F. Cox Director March 22, 2006
- ----------------------------
Ralph F. Cox
/s/ Barry J. Galt Director March 22, 2006
- ----------------------------
Barry J. Galt
/s/ Dennis E. Logue Director March 22, 2006
- ----------------------------
Dennis E Logue
/s/ Paul Powell Director March 22, 2006
- ----------------------------
Paul Powell
/s/ Joseph A. Wagda Director March 22, 2006
- ----------------------------
Joseph A. Wagda
51
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Management's Report on Internal Control over Financial Reporting....................................F-2
Report of Independent Registered Public Accounting Firm.............................................F-3
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting.................................................................................F-4
Consolidated Balance Sheets at December 31, 2004 and 2005...........................................F-5
Consolidated Statements of Operations for the years ended December 31, 2003
2004 and 2005....................................................................................F-7
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2003, 2004 and 2005.................................................................F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2003,
2004 and 2005....................................................................................F-9
Consolidated Statements of Other Comprehensive Income for the years ended
December 31, 2003, 2004 and 2005.................................................................F-11
Notes to Consolidated Financial Statements .........................................................F-12
All schedules are omitted because they are not required, are not applicable or
the information required is included in the Consolidated Financial Statements or
the notes thereto.
F-1
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
Abraxas Petroleum Corporation:
Management is responsible for establishing and maintaining adequate
internal control over financial reporting (as defined in Rules 13a-15(f) under
the Securities Exchange Act of 1934). Our internal control over financial
reporting is designed to provide reasonable assurance to management and board of
directors regarding the preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Management assessed the
effectiveness of our internal control over financial reporting as of December
31, 2005. In making this assessment, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in
Internal Control - Integrated Framework. Based on our assessment, we believe
that, as of December 31, 2005, our internal control over financial reporting is
effective based on those criteria.
Management's assessment of the effectiveness of internal control over
financial reporting as of December 31, 2005, has been audited BDO Seidman, LLP,
an independent registered public accounting firm which also audited our
consolidated financial statements. BDO Seidman's attestation report on
management's assessment of our internal control over financial reporting is
included under the heading "Report of Independent Registered Public Accounting
Firm on Internal Control Over Financial Reporting."
By: /s/ Robert L.G. Watson By: /s/ Chris E. Williford
---------------------- -----------------------
Robert L.G. Watson Chris E. Williford
President and Chief Executive Officer Executive Vice President and
Chief Financial Officer
San Antonio, Texas
March 8, 2006
F-2
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Abraxas Petroleum Corporation
San Antonio, Texas
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and subsidiaries as of December 31, 2005 and 2004 and the
related consolidated statements of operations, stockholders' deficit, cash flows
and other comprehensive income (loss) for each of the three years in the period
ended December 31, 2005. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, 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 consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Abraxas Petroleum
Corporation at December 31, 2005 and 2004, and the results of its operations and
its cash flows for each of the three years in the period ended December 31,
2005, in conformity with accounting principles generally accepted in the United
States of America.
As discussed in Note 2 to the consolidated financial statements, the Company
changed its method of accounting for stock-based compensation during 2005.
We also have audited, in accordance with the standards of the Public Company
Accounting Oversight Board (United States), the effectiveness of Abraxas
Petroleum Corporation's internal control over financial reporting as of December
31, 2005, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) and our report dated March 8, 2006 expressed an unqualified
opinion thereon.
/s/ BDO Seidman, LLP
Dallas, Texas
March 8, 2006
F-3
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting
The Board of Directors and Stockholders
Abraxas Petroleum Corporation
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting and Scope of
Management's Report, that Abraxas Petroleum Corporation maintained effective
internal control over financial reporting as of December 31, 2005, based on
criteria established in Internal Control--Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (the COSO
criteria). Abraxas Petroleum Corporation's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management's assessment and an
opinion on the effectiveness of the company's internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.
A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that Abraxas Petroleum Corporation
maintained effective internal control over financial reporting as of December
31, 2005, is fairly stated, in all material respects, based on the COSO
criteria. Also, in our opinion, Abraxas Petroleum Corporation maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2005, 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 as of December 31, 2005 and 2004 and the related consolidated statements
of operations, stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 2005 of Abraxas Petroleum Corporation and our
report dated March 8, 2006 expressed an unqualified opinion thereon.
/s/ BDO Seidman, LLP
Dallas, Texas
March 8, 2006
F-4
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------------------
2005 2004 (1)
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ 42 $ 1,284
Accounts receivable:
Joint owners ....................................... 540 471
Oil and gas production sales ....................... 7,957 4,724
Other .............................................. 100 66
------------------ -------------------
8,597 5,261
Other current assets ................................... 1,638 752
------------------ -------------------
10,277 7,297
Assets held for sale.................................... - 52,600
------------------ -------------------
Total current assets................................ 10,277 59,897
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 333,373 298,382
Other property and equipment ......................... 3,289 2,930
------------------ -------------------
Total .......................................... 336,662 301,312
Less accumulated depreciation, depletion, and
amortization ....................................... 231,414 222,500
------------------ -------------------
Total property and equipment - net ................. 105,248 78,812
Deferred financing fees net ............................... 6,037 7,618
Deferred tax asset......................................... - 6,060
Other assets .............................................. 304 298
------------------ -------------------
Total assets ........................................... $ 121,866 $ 152,685
================== ===================
(1) Reflects retrospective adoption of SFAS 123R, see Note 2.
See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' DEFICIT
December 31
--------------------------------------
2005 2004 (1)
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 9,814 $ 5,622
Joint interest oil and gas production payable ............. 3,481 2,443
Accrued interest .......................................... 1,368 2,170
Other accrued expenses .................................... 494 1,654
------------------ -------------------
15,157 11,889
Liabilities related to assets held for sale................ - 66,947
------------------ -------------------
Total current liabilities................................ 15,157 78,836
Long-term debt ............................................... 129,527 126,425
Future site restoration ..................................... 883 888
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized
200,000,000 shares; issued 42,063,167 and 36,597,045 .... 421 366
Additional paid-in capital ................................ 162,795 150,961
Accumulated deficit ...................................... (188,193) (207,310)
Treasury stock, at cost, 56,477 and 105,989 shares......... (408) (549)
Accumulated other comprehensive income..................... 1,684 3,068
------------------ -------------------
Total stockholders' deficit................................... (23,701) (53,464)
------------------ -------------------
Total liabilities and stockholders' deficit................ $ 121,866 $ 152,685
================== ===================
(1) Reflects retrospective adoption of SFAS 123R, see Note 2.
See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------------------------------
2005 2004 (1) 2003 (1)
-------------------- ------------------- -----------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 47,314 $ 33,073 $ 29,710
Rig revenues ............................................ 1,295 771 663
Other .................................................. 16 10 7
-------------------- ------------------- -----------------
48,625 33,854 30,380
Operating costs and expenses:
Lease operating and production taxes .................... 11,094 8,567 8,342
Depreciation, depletion, and amortization ............... 8,914 7,213 7,608
Rig operations .......................................... 756 671 609
General and administrative (including stock-based
compensation of $247; $112; and $228)................. 5,757 5,238 4,223
-------------------- ------------------- -----------------
26,521 21,689 20,782
-------------------- ------------------- -----------------
Operating income ........................................... 22,104 12,165 9,598
Other (income) expense:
Interest income ......................................... (19) (10) (30)
Amortization of deferred financing fees ................. 1,589 1,848 1,630
Interest expense ........................................ 13,989 17,867 16,323
Financing costs.......................................... - 1,657 4,406
Gain on debt redemption.................................. - (12,561) -
Other ................................................... 274 387 100
-------------------- ------------------- -----------------
15,833 9,188 22,429
-------------------- ------------------- -----------------
Income (loss) from continuing operations before cumulative
effect of accounting change ............................. 6,271 2,977 (12,831)
Cumulative effect of accounting change...................... - - 395
-------------------- ------------------- -----------------
Net income (loss) from continuing operations before
income tax............................................ 6,271 2,977 (13,226)
-------------------- ------------------- -----------------
Deferred income tax benefit.............................. - (6,060) -
-------------------- ------------------- -----------------
Income (loss) from continuing operations................. 6,271 9,037 (13,226)
Net income from discontinued operations................. 12,846 3,323 70,024
-------------------- ------------------- -----------------
Net income $ 19,117 $ 12,360 $ 56,798
==================== =================== =================
Basic earnings (loss)per common share:
Net earnings (loss) from continuing operations........ $ 0.16 $ 0.25 $ (0.36)
Discontinued operations .............................. 0.33 0.09 1.98
Cumulative effect of accounting change................ - - (0.01)
-------------------- ------------------- -----------------
Net income per common share - basic .................... $ 0.49 $ 0.34 $ 1.61
==================== =================== =================
Diluted earnings (loss) per common share:
Net earnings (loss) from continuing operations........ $ 0.15 $ 0.23 $ (0.36)
Discontinued operations .............................. 0.31 0.09 1.98
Cumulative effect of accounting change................ - - (0.01)
-------------------- ------------------- -----------------
Net income per common share - diluted.................. $ 0.46 $ 0.32 $ 1.61
==================== =================== =================
(1)Reflects retrospective adoption of SFAS 123R, see Note 2.
See accompanying notes to consolidated financial statements
F-7
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands except number of shares)
Accumulated
Common Stock Treasury Stock Additional Other Receivable
------------------ ------------------- Paid-In Accumulated Comprehensive From
Shares Amount Shares Amount Capital Deficit Income (loss) Stock Sale Total
------------------ ------------------- ---------- -------------- -------------- --------- ----------
Balance December 31, 2002
as originally reported... 30,145,280 $ 301 165,883 $ (964) $136,830 $ (269,621) $ (8,703) $ (97) $(142,254)
Cumulative effect of change
in accounting for
stock-based compensation. - - - - 6,847 (6,847) - - -
----------- ------ -------- ---------- ------------ ------------- -------------- --------- ----------
Balance at December 31, 2002
as adjusted for SFAS 123R. 30,145,280 $ 301 165,883 $ (964) $143,677 $ (276,468) $ (8,703) $ (97) $(142,254)
Net income.............. - - - - - 56,798 - - 56,798
Foreign currency
translation
adjustment ........ - - - - - - 9,067 - 9,067
Stock-based compensation
expense................ - - - - 228 - - - 228
Stock options exercised . 129,352 1 - - 84 - - - 85
Stock issued for
acquisition of Wind 106,977 1 - - 91 - - - 92
River Resources........
Stock issued in
connection with 5,642,699 57 - - 3,724 - - - 3,781
exchange offer.........
----------- ------ -------- ---------- ------------ ------------- -------------- --------- ----------
Balance at December 31, 2003 36,024,308 $ 360 165,883 $ (964) $147,804 $ (219,670) $ 364 $ (97) $(72,203)
Net income.............. - - - - - 12,360 - - 12,360
Foreign currency
translation
adjustment ........ - - - - - - 2,704 - 2,704
Proceeds from receivable - - - - - - - 97 97
Stock issued for
compensation........... 58,808 1 (59,894) 415 (87) - - - 329
Stock-based compensation
expense................ - - - - 112 - - - 112
Stock options and
warrants exercised .... 513,929 5 - - 3,132 - - - 3,137
----------- ------ -------- ---------- ------------ ------------- -------------- --------- ----------
Balance December 31, 2004 36,597,045 $ 366 105,989 $ (549) $150,961 $ (207,310) $ 3,068 $ - $(53,464)
Net Income............... - - - - - 19,117 - - 19,117
Foreign currency
translation
adjustment ........ - - - - - - (3,068) - (3,068)
Increase in carrying
value of
investments........ - - - - - - 1,684 - 1,684
Stock-based compensation. - - - - 247 - - - 247
Shares issued for
compensation............. - - (49,512) 141 (39) - - - 102
Stock options exercised.. 461,408 5 - - 423 - - - 428
Stock warrants exercised. 996,479 10 - - (10) - - - -
Stock issued in private
placement.............. 4,000,000 40 - 11,213 - - - 11,253
Other.................... 8,235 - - - - - - - -
----------- ------ -------- ---------- ------------ ------------- -------------- --------- ----------
Balance at December 31, 2005 42,063,167 $ 421 56,477 $ (408) $162,795 $ (188,193) $ 1,684 $ - $(23,701)
=========== ====== ======== ========== ============ ============= ============== ========= ==========
See accompanying notes to consolidated financial statements.
F-8
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31
--------------------------------------------------------------------------
2005 2004 (1) 2003 (1)
------------------ ----------------------- -------------------------
(In thousands)
Operating Activities
Net income ........................................ $ 19,117 $ 12,360 $ 56,798
Income from discontinued operations................ 12,846 3,323 70,024
------------------ ----------------------- -------------------------
Income (loss) from continuing operations............ 6,271 9,037 (13,226)
Adjustments to reconcile net income (loss) to net
cash provided by (used in) operating activities:
Depreciation, depletion, and
amortization ............................... 8,914 7,213 7,608
Non-cash interest and financing cost........... - 5,967 16,422
Accretion of future site restoration........... 19 108 379
Deferred tax benefit........................... - (6,060) -
Amortization of deferred financing fees........ 1,589 1,848 1,630
Stock-based compensation ...................... 247 112 228
Changes in operating assets and liabilities:
Accounts receivable ........................ (2,312) 7,816 (7,850)
Other ..................................... 3,127 (291) 373
Accounts payable ........................... 5,230 990 2,161
Accrued expenses ........................... (1,986) 260 3,754
------------------ ----------------------- -------------------------
Net cash provided by continuing operations......... 21,099 27,000 11,479
Net cash provided by (used in) discontinued
operations.................................. (4,132) 3,265 16,125
------------------ ----------------------- -------------------------
Net cash provided by operations.................... 16,967 30,265 27,604
------------------ ----------------------- -------------------------
Investing Activities
Capital expenditures, including purchases
and development of properties ................... (35,350) (9,269) (9,194)
------------------ ----------------------- -------------------------
Net cash used in continuing operations.............. (35,350) (9,269) (9,194)
Net cash provided by (used in) discontinued
operations....................................... 25,671 (12,069) 76,655
------------------ ----------------------- -------------------------
Net cash (used in) provided by investing activities. (9,679) (21,338) 67,461
Financing Activities
Proceeds from issuance of common stock............ 11,783 3,465 -
Proceeds from long-term borrowings ............... 28,374 147,955 43,051
Payments on long-term borrowings ................. (25,272) (212,146) (131,283)
Deferred financing fees .......................... (8) (5,056) (597)
Other............................................. - 98 177
------------------ ----------------------- -------------------------
Net cash provided by (used in) continuing
operations.................................... 14,877 (65,684) (88,652)
Net cash provided by (used in) discontinued
operations..................................... (23,407) 58,041 (6,970)
------------------ ----------------------- -------------------------
Net cash (used in) provided by financing
activities..................................... (8,530) (7,643) (95,622)
------------------ ----------------------- -------------------------
Increase (decrease) in cash ...................... (1,242) 1,284 (557)
Cash at beginning of year ........................ 1,284 - 557
------------------ ----------------------- -------------------------
Cash at end of year............................... $ 42 $ 1,284 $ -
================== ======================= =========================
(1) Reflects retrospective adoption of SFAS 123R, see Note 2.
F-9
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOW (CONTINUED)
Years Ended December 31
-------------------------------------------------------------
2005 2004 2003
------------------ ---------------- -----------------
(In thousands)
Supplemental disclosures of cash flow information:
Interest paid .......................... $ 12,583 $ 7,608 $ 3,637
================== ================ =================
See accompanying notes to consolidated financial statements.
F-10
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
Years Ended December 31,
----------------------------------------------------------------
2005 2004 2003
-------------------- --------------------- ---------------
(In thousands)
Net income .............................................. $ 19,117 $ 12,360 $ 56,798
Other Comprehensive income:
Foreign currency translation adjustment
Reclassification of foreign currency translation
adjustment relating to the sale of foreign subsidaries.. (2,190) - 4,632
Effect of change in exchange rate....................... (878) 2,704 4,435
Change in carrying value of investment.................... 1,684 - -
-------------------- --------------------- ---------------
Other comprehensive income .................................. (1,384) 2,704 9,067
-------------------- --------------------- ---------------
Comprehensive income ........................................ $ 17,733 $ 15,064 $ 65,865
==================== ===================== ===============
See accompanying notes to consolidated financial statements.
F-11
GE>
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company" or "Abraxas") is an
independent energy company primarily engaged in the exploitation of and the
acquisition, development, and production of crude oil and natural gas primarily
along the Texas Gulf Coast, in the Permian Basin of western Texas and in
Wyoming. The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All intercompany accounts and
transactions have been eliminated in consolidation.
The consolidated financial statements include the accounts of the
Company and its wholly-owned foreign subsidiary, Grey Wolf Exploration Inc.
("Grey Wolf"). On February 28, 2005 Grey Wolf closed an initial public offering,
resulting in the substantial divestiture of our capital stock and operations in
Grey Wolf. As a result of the disposal of Grey Wolf, the results of operations
of Grey Wolf through February 28, 2005 are reflected in our financial statements
as discontinued operations.
Use of Estimates
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Management believes that it is
reasonably possible that estimates of proved crude oil and natural gas revenues
could significantly change in the future.
Concentration of Credit Risk
Financial instruments, which potentially expose the Company to credit
risk consist principally of trade receivables and crude oil and natural gas
price hedges. Accounts receivable are generally from companies with significant
oil and gas marketing activities. The Company performs ongoing credit
evaluations and, generally, requires no collateral from its customers.
The Company maintains its cash and cash equivalents in excess of
Federally insured limits in prominent financial institutions considered by the
Company to be of high credit quality.
Cash and Equivalents
Cash and cash equivalents includes cash on hand, demand deposits and
short-term investments with original maturities of three months or less.
Accounts Receivable
Accounts receivable are reported net of an allowance for doubtful
accounts of approximately $11,000 and $10,000 at December 31, 2004 and 2005,
respectively. The allowance for doubtful accounts is determined based on the
Company's historical losses, as well as a review of certain accounts. Accounts
are charged off when collection efforts have failed and the account is deemed
uncollectible.
F-12
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil
and natural gas properties. Under this method, all direct costs and certain
indirect costs associated with acquisition of properties and successful as well
as unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization of capitalized crude oil and natural
gas properties and estimated future development costs, excluding unproved
properties, are based on the unit-of-production method based on proved reserves.
Net capitalized costs of crude oil and natural gas properties, as adjusted for
asset retirement obligations, less related deferred taxes, are limited to the
lower of unamortized cost or the cost ceiling, defined as the sum of the present
value of estimated future net revenues from proved reserves based on unescalated
prices discounted at 10 percent, plus the cost of properties not being
amortized, if any, plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any, less related income
taxes. Excess costs are charged to proved property impairment expense. No gain
or loss is recognized upon sale or disposition of crude oil and natural gas
properties, except in unusual circumstances.
Unproved properties represent costs associated with properties on which
the Company is performing exploration activities or intends to commence such
activities. These costs are reviewed periodically for possible impairments or
reduction in value based on geological and geophysical data. If a reduction in
value has occurred, costs being amortized are increased. The Company believes
that the unproved properties will be substantially evaluated in six to
thirty-six months and it will begin to amortize these costs at such time.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of other property and equipment is provided over the estimated
useful lives using the straight-line method. Major renewals and betterments are
recorded as additions to the property and equipment accounts. Repairs that do
not improve or extend the useful lives of assets are expensed.
Hedging
The Company periodically enters into agreements to hedge the risk of
future crude oil and natural gas price fluctuations. Such agreements are
primarily in the form of price floors, which limit the impact of price
reductions with respect to the Company's sale of crude oil and natural gas. The
Company does not enter into speculative hedges.
Statement of Financial Accounting Standards, ("SFAS") No. 133,
"Accounting for Derivative Instruments and Hedging Activities," was effective
for the Company on January 1, 2001. SFAS 133, as amended and interpreted,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. In 2003, the Company elected out of hedge accounting as
prescribed by SFAS 133. Accordingly all derivatives will be recorded on the
balance sheet at fair value with changes in fair value being recognized in
earnings.
Foreign Currency Translation
The functional currency for Grey Wolf is the Canadian dollar ($CDN).
The Company translates the functional currency into U.S. dollars ($US) based on
the current exchange rate at the end of the period for the balance sheet and a
weighted average rate for the period on the statement of operations. Translation
adjustments are reflected as accumulated other comprehensive income (loss) in
the consolidated financial statement of stockholders' deficit. The amount
reflected in the accompanying financial statements relates to discontinued
operations. In 2005 the Company disposed of substantially all operations of Grey
Wolf.
Fair Value of Financial Instruments
The Company includes fair value information in the notes to
consolidated financial statements when the fair value of its financial
instruments is materially different from the book value. The Company assumes the
book value of those financial instruments that are classified as current
approximates fair value because of the short maturity of these instruments. For
F-13
noncurrent financial instruments, the Company uses quoted market prices or, to
the extent that there are no available quoted market prices, market prices for
similar instruments.
Restoration, Removal and Environmental Liabilities
The Company is subject to extensive Federal, state and local
environmental laws and regulations. These laws regulate the discharge of
materials into the environment and may require the Company to remove or mitigate
the environmental effects of the disposal or release of petroleum substances at
various sites. Environmental expenditures are expensed or capitalized depending
on their future economic benefit. Expenditures that relate to an existing
condition caused by past operations and that have no future economic benefit are
expensed.
Liabilities for expenditures of a noncapital nature are recorded when
environmental assessments and/or remediation is probable, and the costs can be
reasonably estimated. Such liabilities are generally undiscounted unless the
timing of cash payments for the liability or component are fixed or reliably
determinable.
In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). SFAS 143 addresses accounting and reporting
for obligations associated with the retirement of tangible long-lived assets and
the associated asset retirement costs. SFAS 143 is effective for us January 1,
2003. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense in the accompanying
consolidated financial statements.
The following table summarizes the Company's asset retirement
obligation transactions related to continuing operations during the following
years:
2005 2004 2003
---------------- ------------------ -------------
Beginning asset retirement obligation......... $ 888 $ 776 $ -
New wells placed on production and other ..... 115 132 973
Deletions related to property disposals....... (139) (128) (576)
Accretion expense............................. 19 108 379
---------------- ------------------ -------------
Ending asset retirement obligation............ $ 883 $ 888 $ 776
================ ================== =============
Revenue Recognition and Major Customers
The Company recognizes crude oil and natural gas revenue from its
interest in producing wells as crude oil and natural gas is sold from those
wells, net of royalties. Revenue from the processing of natural gas is
recognized in the period the service is performed. The Company utilizes the
sales method to account for gas production volume imbalances. Under this method,
income is recorded based on the Company's net revenue interest in production
taken for delivery. The Company had no material gas imbalances at December 31,
2005 and 2004.
During 2003, 2004 and 2005 sales to two customers accounted for
approximately 80%, 64% and 61% of crude oil and natural gas revenues.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over
the term of the related debt arrangements.
F-14
Assets and Liabilities Held for Sale
The Company holds assets and liabilities related to discontinued
operations as held for sale, in accordance with Statement of Financial Standards
No. 144 "Accounting for Impairment of Disposal of Long-Lived Assets" (SFAS 144).
The Company records its assets at the lower of its carrying amount or fair
market value less cost to sell and does not depreciate or amortize the assets
while classified as held for sale.
Income Taxes
The Company records deferred income taxes using the liability method.
Under this method, deferred tax assets and liabilities are determined based on
differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws that will be in effect
when the differences are expected to reverse. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts expected
to be realized.
Other Comprehensive Income
FASB Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" (SFAS 130) requires disclosure of comprehensive income,
which includes reported net income as adjusted for other comprehensive income.
Other Comprehensive income is defined as the change in equity of a business
enterprise during a period from transactions and other events and circumstances
from non-owner sources. The components of other comprehensive income for the
Company are foreign currency translation adjustments and change in the market
value of marketable securities.
New Accounting Pronouncements
In March 2005 the FASB issued Interpretation No. 47 "Accounting for
Conditional Asset Retirement Obligations--an interpretation of FASB Statement
No. 143". This Interpretation clarifies that the term conditional asset
retirement obligation as used in FASB Statement No. 143, Accounting for Asset
Retirement Obligations, refers to a legal obligation to perform an asset
retirement activity in which the timing and (or) method of settlement are
conditional on a future event that may or may not be within the control of the
entity. The obligation to perform the asset retirement activity is unconditional
even though uncertainty exists about the timing and (or) method of settlement.
Thus, the timing and (or) method of settlement may be conditional on a future
event. Accordingly, an entity is required to recognize a liability for the fair
value of a conditional asset retirement obligation if the fair value of the
liability can be reasonably estimated. The fair value of a liability for the
conditional asset retirement obligation should be recognized when
incurred--generally upon acquisition, construction, or development and (or)
through the normal operation of the asset. Uncertainty about the timing and (or)
method of settlement of a conditional asset retirement obligation should be
factored into the measurement of the liability when sufficient information
exists. Statement 143 acknowledges that in some cases, sufficient information
may not be available to reasonably estimate the fair value of an asset
retirement obligation. This Interpretation also clarifies when an entity would
have sufficient information to reasonably estimate the fair value of an asset
retirement obligation.
This Interpretation is effective no later than the end of fiscal years
ending after December 15, 2005 (December 31, 2005, for calendar-year
enterprises). Retrospective application for interim financial information is
permitted but is not required. Early adoption of this Interpretation is
encouraged. This statement did not effect the Company's financial statements for
the period ended December 31, 2005.
In May 2005, the FASB issued "Summary of Statement No. 154 Accounting
Changes and Error Corrections" - a replacement of APB Opinion No. 20 and FASB
Statement No. 3. This Statement replaces APB Opinion No. 20, Accounting Changes,
and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial
Statements, and changes the requirements for the accounting for and reporting of
a change in accounting principle. This Statement applies to all voluntary
changes in accounting principle. It also applies to changes required by an
accounting pronouncement in the unusual instance that the pronouncement does not
include specific transition provisions. When a pronouncement includes specific
transition provisions, those provisions should be followed.
Opinion 20 previously required that most voluntary changes in
accounting principle be recognized by including in net income of the period of
the change the cumulative effect of changing to the new accounting principle.
This Statement requires retrospective application to prior periods' financial
statements of changes in accounting principle, unless it is impracticable to
determine either the period-specific effects or the cumulative effect of the
F-15
change. When it is impracticable to determine the period-specific effects of an
accounting change on one or more individual prior periods presented, this
Statement requires that the new accounting principle be applied to the balances
of assets and liabilities as of the beginning of the earliest period for which
retrospective application is practicable and that a corresponding adjustment be
made to the opening balance of retained earnings (or other appropriate
components of equity or net assets in the statement of financial position) for
that period rather than being reported in an income statement. When it is
impracticable to determine the cumulative effect of applying a change in
accounting principle to all prior periods, this Statement requires that the new
accounting principle be applied as if it were adopted prospectively from the
earliest date practicable.
This Statement defines retrospective application as the application of
a different accounting principle to prior accounting periods as if that
principle had always been used or as the adjustment of previously issued
financial statements to reflect a change in the reporting entity. This Statement
also redefines restatement as the revising of previously issued financial
statements to reflect the correction of an error.
This Statement requires that retrospective application of a change in
accounting principle be limited to the direct effects of the change. Indirect
effects of a change in accounting principle, such as a change in
non-discretionary profit-sharing payments resulting from an accounting change,
should be recognized in the period of the accounting change.
This Statement also requires that a change in depreciation,
amortization, or depletion method for long-lived, non-financial assets be
accounted for as a change in accounting estimate effected by a change in
accounting principle.
This Statement carries forward without change the guidance contained in
Opinion 20 for reporting the correction of an error in previously issued
financial statements and a change in accounting estimate. This Statement also
carries forward the guidance in Opinion 20 requiring justification of a change
in accounting principle on the basis of preferability.
This statement is effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005. This statement
did not effect the Company's financial statements for the period ended December
31, 2005.
2. Accounting Change
Stock-based Compensation
Effective July 1, 2000, the Financial Accounting Standards Board
("FASB") issued FIN 44, "Accounting for Certain Transactions Involving Stock
Compensation", an interpretation of Accounting Principles Board Opinion No.
("APB") 25. Under the interpretation, certain modifications to fixed stock
option awards, which were made subsequent to December 15, 1998, and not
exercised prior to July 1, 2000, require that the awards be subject to variable
accounting until they are exercised, forfeited, or expired. In March 1999, we
amended the exercise price to $2.06 on all options with an existing exercise
price greater than $2.06. In January 2003, we amended the exercise price to
$0.66 per share on certain options with an existing exercise price greater than
$0.66 per share which resulted in variable accounting. Under the rules of
variable accounting, we recognized the difference in the market price of our
common stock as of the end of the period and the exercise price of $0.66. If the
market price of our common stock increased from the previous period we
recognized expense, conversely, if the price decreased we recognized a benefit.
In December 2004, the FASB issued SFAS No. 123R, "Share-Based Payment".
SFAS No. 123R is a revision of SFAS No. 123, "Accounting for Stock Based
Compensation", and supersedes APB 25. Among other items, SFAS 123R eliminates
the use of APB 25 and the intrinsic value method of accounting, and requires
companies to recognize the cost of employee services received in exchange for
awards of equity instruments, based on the grant date fair value of those
awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. The Company has elected early adoption of
SFAS 123R .
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method, or a "modified retrospective" method. Under the
"modified prospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. Under the "modified retrospective" method, the requirements
F-16
are the same as under the "modified prospective" method, but also permit
entities to restate financial statements of previous periods based on proforma
disclosures made in accordance with SFAS 123. The Company has elected to use the
"modified retrospective" method. This standard requires the cost of all
share-based payments, including stock options, to be measured at fair value on
the grant date and recognized in the statement of operations. In accordance with
this standard, all periods prior to January 1, 2005 were restated to reflect the
impact of the standard as if it had been adopted on January 1, 1995, the
original effective date of SFAS No. 123, "Accounting for Stock-Based
Compensation". Also in accordance with the standard, the amounts that are
reported in the statement of operations for the restated periods are the pro
forma amounts previously disclosed under SFAS No. 123.
The Company currently utilizes a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to Employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by the Company on the alternative models available to value option
grants, and in conjunction with the type and number of stock options expected to
be issued in the future, the Company has determined that it will continue to use
the Black-Scholes model for option valuation as of the current time. The fair
value for these options was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted-average assumptions for 2003,
2004 and 2005, risk-free interest rates of 1.5% in 2003 and 2004 and 4.14% in
2005.; dividend yields of -0-%; volatility factors of the expected market price
of the Company's common stock of .35 in 2003 and 2004 and .89 in 2005 determined
by daily historical prices, and a weighted-average expected life of the option
of ten years in 2003 and 2004 and 8.3 years in 2005.
SFAS 123R includes several modifications to the way that income taxes
are recorded in the financial statements. The expense for certain types of
option grants is only deductible for tax purposes at the time that the taxable
event takes place, which could cause variability in the Company's effective tax
rates recorded throughout the year. SFAS 123R does not allow companies to
"predict" when these taxable events will take place. Furthermore, it requires
that the benefits associated with the tax deductions in excess of recognized
compensation cost be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement will
reduce net operating cash flows and increase net financing cash flows in periods
after the effective date. These future amounts cannot be estimated, because they
depend on, among other things, when employees exercise stock options.
As a result of the adoption of this standard, the Company has
recognized a reduction of stock based compensation expense of approximately
$878,000 and $1.2 million for the years ended December 31, 2003 and 2004. This
resulted in an increase in net income from continuing operations, net income
before tax, net income and cash flow from operations of $878,000 and $1.2
million for 2003 and 2004 and an increase of $0.02 and 0.03 earnings per share
for the respective periods. The Company recognized $247,000; $112,000; and
$228,000 in stock-based compensation expense for 2005, 2004 and 2003
respectively as a result of the adoption of this standard. This reduced net
income from continuing operations, net income before tax and net income in 2005
by $247,000 and reduced earnings per share by $0.01 in 2005.
3. Discontinued Operations
As part of the restructuring operations in 2004 the Company approved a
plan to dispose of its operations and interest in Grey Wolf. On February 28,
2005, Abraxas substantially divested its investment in Grey Wolf. Pursuant to an
Underwriting Agreement, the underwriters purchased 17,800,000 common shares of
Grey Wolf capital stock from Grey Wolf (the "Treasury Shares"), and 9,100,000
shares of Grey Wolf common stock owned by Abraxas (the "Secondary Shares") from
Abraxas at a purchase price of CDN $2.80 per share.
Abraxas also granted to the underwriters an over-allotment option to
purchase from Abraxas, at the underwriters' election, up to an additional
3,902,360 shares of Grey Wolf common stock held by Abraxas (the "Option
Shares"). The over-allotment option may be exercised in whole or in part at any
one time prior to thirty calendar days after the closing date for the IPO. Grey
Wolf utilized the proceeds from the sale of the Treasury Shares to re-pay and
terminate its $35 million term loan and re-pay $1 million in inter-company debt
to Abraxas. Abraxas utilized the $1 million received from Grey Wolf and the
proceeds received from the sale of the Secondary Shares to re-pay outstanding
debt under its $25 million bridge loan. After consummation of the offering,
Abraxas' remaining debt under the bridge loan was $5.4 million - see Note 3. On
March 24, 2005, the Company was advised of the underwriter's intent to exercise
3.5 million of the over allotment shares. Closing for this exercise occurred
March 31 and provided approximately $7.5 million that Abraxas utilized to payoff
F-17
the remaining balance of its Bridge Loan. The remaining proceeds of
approximately $2 million were used to pay down the Company's revolving credit
facility to, effectively, zero.
The operations of Grey Wolf, previously reported as a business segment,
are reported as discontinued operations for all periods presented in the
accompanying financial statements and the operating results are reflected
separately from the results of continuing operations. Interest attributable to
discontinued operations represents interest on debt attributable to the Canadian
subsidiary. Summarized discontinued operations operating results and net gain
(loss) for the years ended December 31, 2003, 2004 and 2005 were:
Years ended December 31
---------------------------------------------------------
2005 2004 2003
--------------- ---------------- ----------------
(in thousands)
Total revenue........................................ $ 3,129 $ 15,082 $ 8,639
Income from operations before income tax (1)......... 18,906 (1) 3,323 70,401 (2)
Income tax expense (benefit)......................... 6,060 - 377
---------------- ---------------- ----------------
Income from discontinued operations (1).............. $ 12,846 $ 3,323 $ 70,024
================ ================ ================
(1) Includes gain on sale of foreign subsidiary of $17.3 million in 2005.
(2) In 2003, as part of a series of transactions related to a financial
restructuring including an exchange offer, redemption of certain notes
payable and a credit agreement, the Company sold its wholly owned
Canadian subsidiaries. The 2003 statement of operations includes a gain
on the sale of the Canadian subsidiaries in January 2003 of $68.9
million.
Assets and liabilities of discontinued operations were as follows:
December 31, 2004
--------------------
(in thousands)
Assets:
Cash.......................................... $ 693
Accounts receivable........................... 2,556
Net property.................................. 45,426
Deferred financing fees....................... 3,577
Other......................................... 348
--------------------
$ 52,600
====================
Liabilities:
Accounts payable and accrued expenses......... $ 5,262
Long-term debt (1)............................ 60,000
Other......................................... 1,685
--------------------
$ 66,947
====================
(1) Includes Abraxas Bridge Loan of $25 million and $35 million related to Grey
Wolf term loan.
4. Long-Term Debt
The following is a description of the Company's debt as of December 31, 2005 and
2004, respectively:
December 31
----------------------
2005 2004
----------- -----------
(in thousands)
Floating rate senior secured notes due 2009....... $ 125,000 $ 125,000
Senior secured revolving credit facility.......... 4,527 1,425
----------- ------------
129,527 126,425
Less current maturities .......................... - -
----------- ------------
$ 129,527 $ 126,425
=========== ============
F-18
Floating Rate Senior Secured Notes due 2009. In connection with our
October 2004 refinancing, Abraxas issued $125 million in principal aggregate
amount of Floating Rate Senior Secured Notes due 2009. The notes will mature on
December 1, 2009 and began accruing interest from the date of issuance, October
28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The initial
interest rate on the notes was 9.72% per annum. The interest will be reset
semi-annually on each June 1 and December 1, commencing on June 1, 2005. The
current interest rate, effective December 1, 2005, is 12.08% per annum. Interest
is payable semi-annually in arrears on June 1 and December 1 of each year,
commencing on June 1, 2005.
The notes rank equally among themselves and with all of our
unsubordinated and unsecured indebtedness, including our credit facility, and
senior in right of payment to our existing and future subordinated indebtedness.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest on the notes on a senior secured basis. In addition, any
other subsidiary or affiliate of ours, that in the future guarantees any other
indebtedness with us, or our restricted subsidiaries, will also be required to
guarantee the notes.
The notes and the Subsidiary Guarantors' guarantees thereof, together
with our credit facility and the Subsidiary Guarantors' guarantees thereof, are
secured by shared first priority perfected security interests, subject to
certain permitted encumbrances, in all of our and each of our restricted
subsidiaries' material property and assets, including substantially all of our
and their natural gas and crude oil properties and all of the capital stock (or
in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
The notes may be redeemed, at the election of the Company, as a whole
or from time to time in part, at any time after April 28, 2007, upon not less
than 30 nor more that 60 days' notice to each holder of notes to be redeemed,
subject to the conditions and at the redemption prices (expressed as percentages
of principal amount) set forth below, together with accrued and unpaid interest
and Liquidating Damages, if any, to the applicable redemption date.
Year Percentage
------------------------------------------ -------------
From April 29, 2007 to April 28, 2008 104.00%
From April 29, 2008 to April 28, 2009 102.00%
After April 28, 2009 100.00%
Prior to April 28, 2007, we may redeem up to 35% of the aggregate
original principal amount of the notes using the net proceeds of one or more
equity offerings, in each case at the redemption price equal to the product of
(i) the principal amount of the notes being so redeemed and (ii) a redemption
price factor of 1.00 plus the per annum interest rate on the notes (expressed as
a decimal) on the applicable redemption date plus accrued and unpaid interest to
the applicable redemption date, provided certain conditions are also met.
If we experience specific kinds of change of control events, each
holder of notes may require us to repurchase all or any portion of such holder's
notes at a purchase price equal to 101% of the principal amount of the notes,
plus accrued and unpaid interest to the date of repurchase.
The indenture governing the notes contains covenants that, among other
things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
F-19
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including
nonpayment of principal or interest, violations of covenants, cross default and
cross acceleration to certain other indebtedness, including our credit facility,
bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we
entered into an agreement for a new revolving credit facility having a maximum
commitment of $15 million, which includes a $2.5 million subfacility for letters
of credit. Availability under the revolving credit facility is subject to a
borrowing base consistent with normal and customary natural gas and crude oil
lending transactions.
Outstanding amounts under the revolving credit facility bear interest
at the prime rate announced by Wells Fargo Bank, National Association plus
1.00%. Subject to earlier termination rights and events of default, the stated
maturity date under the revolving credit facility is October 28, 2008.
We are permitted to terminate the revolving credit facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders' aggregate commitment under the revolving credit facility. Such
termination and each such reduction is subject to a premium equal to the
percentage listed below multiplied by the lenders' aggregate commitment under
the revolving credit facility, or, in the case of partial reduction, the amount
of such reduction.
Year % Premium
---------- ----------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of our restricted subsidiaries will be required to guarantee our obligations
under the revolving credit facility. Obligations under the revolving credit
facility are secured, together with the notes, by a shared first priority
perfected security interest, subject to certain permitted encumbrances, in all
of our and each of our restricted subsidiaries' material property and assets,
including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
Under the revolving credit facility, we are subject to customary
covenants, including certain financial covenants and reporting requirements. The
revolving credit facility requires us to maintain a minimum net cash interest
coverage and also requires us to enter into hedging agreements on not less than
25% or more than 75% of our projected natural gas and crude oil production for a
rolling six month period.
In addition to the foregoing and other customary covenants, the
revolving credit facility contains a number of covenants that, among other
things, restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
F-20
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
The revolving credit facility also contains customary events of
default, including nonpayment of principal or interest, violations of covenants,
cross default and cross acceleration to certain other indebtedness, bankruptcy
and material judgments and liabilities, and is subject to an Intercreditor,
Security and Collateral Agency Agreement, which specifies the rights of the
parties thereto to the proceeds from the Collateral.
Intercreditor Agreement. The holders of the notes, together with the
lenders under our credit facility, are subject to an Intercreditor, Security and
Collateral Agency Agreement, which specifies the rights of the parties thereto
to the proceeds from the Collateral. The Intercreditor Agreement, among other
things, (i) creates security interests in the Collateral in favor of a
collateral agent for the benefit of the holders of the notes and the credit
facility lenders and (ii) governs the priority of payments among such parties
upon notice of an event of default under the Indenture or the credit facility.
So long as no such event of default exists, the collateral agent will
not collect payments under the credit facility documents or the indenture
governing the notes and other note documents (collectively, the "Secured
Documents"), and all payments will be made directly to the respective creditor
under the applicable Secured Document. Upon notice of an event of default and
for so long as an event of default exists, payments to each credit facility
lender and holder of the notes from us and our current subsidiaries and proceeds
from any disposition of any collateral, will, subject to limited exceptions, be
collected by the collateral agent for deposit into a collateral account and then
distributed as provided in the following paragraph.
Upon notice of any such event of default and so long as an event of
default exists, funds in the collateral account will be distributed by the
collateral agent generally in the following order of priority:
first, to reimburse the collateral agent for expenses incurred
in protecting and realizing upon the value of the Collateral;
second, to reimburse the credit facility administrative agent
and the trustee, on a pro rata basis, for expenses incurred in
protecting and realizing upon the value of the Collateral while any of
these parties was acting on behalf of the Control Party (as defined
below);
third, to reimburse the credit facility administrative agent
and the trustee, on a pro rata basis, for expenses incurred in
protecting and realizing upon the value of the Collateral while any of
these parties was not acting on behalf of the Control Party;
F-21
fourth, to pay all accrued and unpaid interest (and then any
unpaid commitment fees) under the credit facility;
fifth, if the collateral coverage value of three times the
outstanding obligations under the credit facility would be met after
giving effect to any payment under this clause "fifth," to pay all
accrued and unpaid interest on the notes;
sixth, to pay all outstanding principal of (and then any other
unpaid amounts, including, without limitation, any fees, expenses,
premiums and reimbursement obligations) the credit facility;
seventh, to pay all accrued and unpaid interest on the notes
(if not paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any
other unpaid amounts, including, without limitation, any premium with
respect to) the notes; and
ninth, to pay each credit facility lender, holder of the
notes, and other secured party, on a pro rata basis, all other amounts
outstanding under the credit facility and the notes.
To the extent there exists any excess monies or property in the
collateral account after all of our and our subsidiaries' obligations under the
credit facility, the indenture and the notes are paid in full, the collateral
agent will be required to return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party" which for purposes of the
Intercreditor is the holders of the notes and the credit facility lenders,
acting as a single class, by vote of the holders of a majority of the aggregate
principal amount of outstanding obligations under the notes and the credit
facility.
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the credit facility administrative agent certifying that the proposed
sale or other disposition of assets is either permitted or required by, and is
in accordance with the provisions of, the applicable Secured Documents and (iii)
the collateral agent has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
5. Property and Equipment
The major components of property and equipment, at cost, are as
follows:
Estimated December 31
----------------------------------
Useful Life 2005 2004
----------------- ---------------- -----------------
Years (In thousands)
Crude oil and natural gas properties ........... - $ 333,373 $ 298,382
Equipment and other ............................ 3-39 3,289 2,930
---------------- -----------------
$ 336,662 $ 301,312
================ =================
6. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and other
employees under various stock option and incentive plans.
The Company's 1994 Long-Term Incentive Plan has authorized the grant of
options to management, employees and directors for up to approximately 6.1
million shares of the Company's common stock. All options granted have ten year
terms and vest and become fully exercisable over three to four years of
continued service at 25% to 33% on each anniversary date. At December 31, 2005
approximately 2.6 million options remain available for grant.
F-22
The Company's 2005 Employee Long-Term Equity Incentive Plan has
authorized the grant of 1.2 million options to management and employees. Options
have a term not to exceed 10 years. Options issued under this plan vest
according to a vesting schedule as determined by the compensation committee.
Vesting may occur upon (1) the attainment of one or more performance goals or
targets established by the committee (2) the optionee's continued employment or
service for a specified period of time, (3) the occurrence of any event or the
satisfaction of any other condition specified by the committee; or (4) a
combination of any of the foregoing. This plan is subject to stockholder
approval at the Company's 2006 annual stockholders meeting.
A summary of the Company's stock option activity for the three years
ended December 31, follows:
2005 2004 2003
---------------------------- ----------------------------- -----------------------------
Weighted-Average Weighted-Average Weighted-Average
Options Exercise Price Options Exercise Price Options Exercise Price
(000s) (000s) (000s)
---------- ----------------- ---------- ------------------ --------- ------------------
Outstanding-beginning of
year ................... 2,893 $ 0.93 3,364 $ 0.90 3,305 $ 1.85
Granted ................... 716 4.33 - - 360 0.68
Exercised ................. (461) 0.93 (414) 0.69 (129) 0.66
Forfeited/Expired ......... (132) 0.67 (57) 0.77 (172) 1.61
---------- ---------- ---------
Outstanding-end of year ... 3,016 $ 0.88 2,893 $ 0.93 3,364 $ 0.90
========== ========== =========
Exercisable at end of year 2,225 $ 1.04 2,327 $ 0.97 2,331 $ 0.95
========== ========== =========
A summary of the Company's stock option related information for the
three years ended December 31, follows:
2005 2004 2003
-------------- ------------- -------------
Weighted-average fair
value of options
granted during the year $ 2,436,320 $ - $ 136,610
Intrinsic value of options
exercised............... $ 245,346 $ 153,155 $ 40,067
Intrinsic value of options
forfeited............... $ 41,092 $ 20,053 $ 163,069
Intrinsic value of
non-vested options at
beginning of year....... $ 207,970 $ 669,521 $ 1,149,178
Intrinsic value of
non-vested options at $ 2,427,269 $ 207,970 $ 669,521
end of year.............
Intrinsic value of vested
options at beginning of
year.................... $ 1,481,543 $ 1,502,654 $ 3,356,552
Intrinsic value of vested
options at end of year.. $ 1,409,468 $ 1,481,543 $ 1,502,654
The intrinsic fair value of options exercisable and options outstanding
as of December 31, 2005 is $1.5 million and $3.9 million, respectively. As of
December 31, 2005 the total compensation cost related to nonvested awards not
yet recognized is approximately $2.3 million, which will be recognized in 2006
through 2009.
The following table represents the range of option prices and the
weighted average remaining life of outstanding options as of December 31, 2005:
Options outstanding Exercisable
----------------------------------------------- --------------------------------------------
Weighted Weighted Weighted
average average average
Number remaining exercise Number remaining Weighted average
Exercise price outstanding life price exercisable life exercise price
--------------------- ------------------ --------------- ------------ --------------- ----------- ----------------
$ 0.50 - 0.97 1,783,265 4.0 $ 0.70 1,648,140 4.0 $ 0.70
$ 1.01 - 1.41 240,000 5.9 1.20 200,000 5.9 1.24
$ 2.06 - 2.75 346,857 3.1 2.24 346,857 3.1 2.24
$ 4.59 - 4.83 646,001 9.5 4.60 30,001 9.5 4.83
In January 2003, in connection with the financial restructuring,
approximately 1.9 million options with a strike price greater that $0.66 were
re-priced to $0.66.
F-23
Stock Awards
In addition to stock options granted under the plan described above,
the 1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. There
were no awards in 2003 or 2005. In 2004, 37,719 shares were awarded related to
incentive bonus plans.
The Company also has adopted the Restricted Share Plan for Directors
which provides for awards of common stock to non-employee directors of the
Company who did not, within the year immediately preceding the determination of
the director's eligibility, receive any award under any other plan of the
Company. There were no direct awards of common stock in 2003, 2004 or 2005.
On June 1, 2005, the stockholders approved the 2005 Non-Employee
Directors Long-Term Equity Incentive Plan (the "2005 Directors Plan"). The
following is a summary of the 2005 Directors Plan.
Purpose. The purpose of the 2005 Directors Plan is to attract and
retain members of the Board of Directors and to promote the growth and success
of Abraxas by aligning the long-term interests of the Board of Directors with
those of Abraxas' stockholders by providing an opportunity to acquire an
interest in Abraxas and by providing both rewards for exceptional performance
and long term incentives for future contributions to the success of Abraxas.
Administration and Eligibility. The 2005 Directors Plan will be
administered by the Compensation Committee (the "Committee") of the Board of
Directors and authorizes the Board to grant non-qualified stock options or issue
restricted stock to those persons who are non-employee directors of Abraxas,
including advisory directors of Abraxas, which currently amounts to a total of
nine people.
Shares Reserved and Awards. The 2005 Directors Plan reserves 900,000
shares of Abraxas common stock, subject to adjustment following certain events,
as discussed below. The 2005 Directors Plan provides that each year, at the
first regular meeting of the Board of Directors immediately following Abraxas'
annual stockholder's meeting, each non-employee director shall be granted or
issued awards of 10,000 shares of Abraxas common stock, for participation in
Board and Committee meetings during the previous calendar year. The maximum
annual award for any one person is 10,000 shares of Abraxas common stock or
options for common stock. If options, as opposed to shares, are awarded, the
exercise share price shall be no less than 100% of the fair market value on the
date of the award while the option terms and vesting schedules are at the
discretion of the Committee.
Stock Warrants
In October 2004, the Company issued 1.1 million warrants in conjunction
with the refinancing. Each is exercisable for one share of common stock at an
exercise price of $0.01 per share. These warrants had a ten year term and were
exercised in March 2005.
At December 31, 2005, the Company has approximately 4.0 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company's directors, employees and consultants.
7. Income Taxes
Deferred income taxes reflect the net tax effects of temporary
differences between the carrying amounts of assets and liabilities for financial
reporting purposes and the amounts used for income tax purposes. Significant
components of the Company's deferred tax liabilities and assets are as follows:
December 31
---------------------------
2005 2004
------------- -------------
(In thousands)
Deferred tax liabilities:
Marketable securities....................... $ 509 $ -
U.S. full cost pool ........................ 11,621 7,310
------------- -------------
Total deferred tax liabilities ............... 12,130 7,310
Deferred tax assets:
Capital loss carryforward................... 5,325 11,913
Depletion .................................. 3,542 3,232
Net operating losses ("NOL")............... 66,596 64,408
F-24
Investment in foreign subsidiaries.......... - 2,426
Canadian loss (Grey Wolf)................... 572 -
Other ...................................... 3,023 4,387
------------- -------------
Total deferred tax assets .................... 79,058 86,366
Valuation allowance for deferred tax assets... (66,928) (72,996)
------------- -------------
Net deferred tax assets ...................... 12,130 13,370
------------- -------------
Net deferred tax assets ...................... $ - $ (6,060)
============= =============
Significant components of the provision (benefit) for income taxes are
as follows:
2005 2004 2003
----------- -------------- --------------
(in thousands)
Current:
Federal...................................... $ - $ - $ -
Foreign ..................................... - - -
----------- -------------- --------------
$ - $ - $ -
=========== ============== ==============
Deferred:
Federal ..................................... $ (6,060) $ 6,060 $ -
Foreign ..................................... - - 377
----------- -------------- --------------
(6,060) 6,060 377
Attributable to discontinued operations...... (6,060) - (377)
----------- -------------- --------------
Attributable to continuing operations........ $ - $ 6,060 $ -
=========== ============== ==============
At December 31, 2005 the Company had, subject to the limitation
discussed below, $190.0 million of net operating loss carryforwards for U.S. tax
purposes. These loss carryforwards will expire from 2006 through 2025 if not
utilized.
In addition to the Section 382 limitations, uncertainties exist as to
the future utilization of the operating loss carryforwards under the criteria
set forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $73.0 million and $67.0 million for deferred tax assets
at December 31, 2004 and 2005, respectively.
The reconciliation of income tax computed at the U.S. federal statutory
tax rates to income tax expense is:
December 31
---------------------------------------------------------------------
2005 2004 2003
--------------------- ----------------------- ------------------------
(in thousands)
Tax (expense) benefit at U.S. statutory
rates (35%) ............................ $ (6,691) $ (1,875) $ (19,842)
Decrease in deferred tax asset valuation
allowance .............................. 6,068 8,123 22,993
Higher effective rate of foreign - (140) (2,835)
operations............................
Deferred tax expense - Disc. Ops. ..... (6,060) - -
Other .................................. 623 (48) (693)
--------------------- ----------------------- ------------------------
$ (6,060) $ 6,060 $ (377)
Attributable to discontinued operations (6,060) - 377
--------------------- ----------------------- ------------------------
Attributable to continuing operations.. $ - $ 6,060 $ -
===================== ======================= ========================
8. Commitments and Contingencies
Operating Leases
During the years ended December 31, 2003, 2004 and 2005 the Company
incurred rent expense related to leasing office facilities of approximately
$246,650, $256,355 and $248,684 respectively. Future minimum rental payments are
as follows at December 31, 2005.
F-25
2006...................................................... $ 254,435
2007...................................................... 254,538
2008...................................................... 250,148
2009...................................................... 20,773
Thereafter................................................ -
------------------
$ 779,894
==================
Litigation and Contingencies
From time to time, the Company is involved in litigation relating to
claims arising out of its operations in the normal course of business. At
December 31, 2005 the Company was not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
the Company.
9. Earnings per Share
Basic earnings (loss) per share excludes any dilutive effects of
options, warrants and convertible securities and is computed by dividing income
(loss) available to common stockholders by the weighted average number of common
shares outstanding for the period. Diluted earnings (loss) per share are
computed similar to basic, however diluted earnings per share reflects the
assumed conversion of all potentially dilutive securities.
The following table sets forth the computation of basic and diluted earnings
per share:
2005 2004 2003
----------------- ----------------- --------------------
Numerator:
Net income (loss) before effect of discontinued
operations and accounting change .............. $ 6,271,000 $ 9,037,000 $ (12,831,000)
Discontinued operations........................... 12,846,000 3,323,000 70,024,000
Cumulative effect of accounting change........... - - (395,000)
----------------- ----------------- --------------------
19,117,000 12,360,000 56,798,000
Denominator:
Denominator for basic earnings per share -
weighted-average shares ........................ 39,366,561 36,221,887 35,364,363
Effect of dilutive securities:
Stock options and warrants..................... 1,796,942 2,672,778 -
----------------- ----------------- --------------------
Dilutive potential common shares Denominator for
diluted earnings per share - adjusted
weighted-average shares and assumed
exercise of options and warrants................ 41,163,503 38,894,665 35,364,363
================= ================= ====================
Basic earnings (loss) per share:
Net income (loss) before effect of discontinued
operations and accounting change.................. $ 0.16 $ 0.25 $ (0.36)
Discontinued operations 0.33 0.09 1.98
Cumulative effect of accounting change.......... - - (0.01)
----------------- ----------------- --------------------
Net income per common share....................... $ 0.49 $ 0.34 $ 1.61
================= ================= ====================
Diluted earnings (loss) per share:
Net income (loss) before effect of discontinued
operations and accounting change.................e $ 0.15 $ 0.23 $ (0.36)
Discontinued operations........................... 0.31 0.09 1.98
Cumulative effect of accounting change.......... - - (0.01)
----------------- ----------------- --------------------
Net income per common share - diluted........ $ 0.46 $ 0.32 $ 1.61
================= ================= ====================
F-26
For the year ended December 31, 2003, 711,000 shares were excluded from
the calculation of diluted earnings per share since their inclusion would have
been anti-dilutive.
10. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during
the years ended December 31, 2004 and 2005 are as follows:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ---------------- --------------- ----------------
(In thousands, except per share data)
Year Ended December 31, 2004
Net revenue........................... $ 7,960 $ 8,504 $ 8,237 $ 9,153
Operating income - as previously
reported ........................... $ 576 $ 4,847 $ 1,837 $ 3,712
SFAS 123R adjustment.................. 2,026 (2,351) 1,345 173
---------------- ---------------- --------------- ----------------
Operating income (loss) - adjusted
for 123R............................ $ 2,602 $ 2,496 $ 3,182 $ 3,885
Net income (loss) - as previously
reported............................ $ (5,557) $ 372 $ (1,643) $ 17,995
SFAS 123R adjustment.................. 2,026 (2,351) 1,345 173
---------------- ---------------- --------------- ----------------
Net income (loss)- adjusted for 123R.. $ (3,531) $ (1,979) $ (298) $ 18,168
Net income (loss) per common share -
basic as previously reported........ $ (0.15) $ 0.01 $ (0.05) $ 0.50
Net income (loss) per common share -
basic - adjusted for 123R........... $ (0.10) $ (0.05) $ (0.01) $ 0.50
Net income (loss) per common share -
diluted - as previously reported.... $ (0.15) $ 0.01 $ (0.05) $ 0.47
Net income (loss ) per common share -
diluted - adjusted for 123R......... $ (0.09) $ (0.05) $ (0.01) $ 0.47
Year Ended December 31, 2005
Net revenue $ 7,822 $ 9,627 $ 14,164 $ 17,012
Operating income- as previously
reported............................ $ 2,079 $ 4,350 $ 868 $ n/a
SFAS 123R adjustment.................. 578 (342) 7,037 n/a
---------------- ---------------- --------------- ----------------
Operating income - adjusted for 123R.. $ 2,657 $ 4,008 $ 7,905 $ 7,534
Net income (loss) - as previously
reported............................ $ 9,217 $ 278 $ (3,254) $ n/a
SFAS 123R adjustment.................. 578 (342) 7,037 n/a
---------------- ---------------- --------------- ----------------
Net income - adjusted for 123R........ 9,795 (64) 3,783 n/a
Correct gain on sale of subsisiary.... 2,190 - - -
---------------- ---------------- --------------- ----------------
Net income (loss) - restated.......... $ 11,985 $ (64) $ 3,783 $ 3,413
Net income (loss) per common share -
basic - as previously reported...... $ 0.25 $ 0.01 $ (0.08) $ n/a
Net income (loss) per common share -
basic - as restated................. $ 0.33 $ 0.00 $ 0.09 $ 0.08
Net income (loss) per common share -
diluted - as previously reported.... $ 0.25 $ 0.01 $ (0.08) $ n/a
Net income (loss) per common share -
diluted - as restated............... $ 0.33 $ 0.00 $ 0.09 $ 0.08
(1) An error occurred in calculating the gain on the sale of Grey Wolf in
February 2005. The error related to Grey Wolf's other comprehensive
income relating to foreign currency translation at the time of the
disposition. The correctio of the error resulted in an increase in
income from discontinued operations and net income of $2.2 million.
F-27
11. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all
eligible employees of the Company. The Company matched employee contributions in
2004 and matched 50% of employee contributions in 2005. The Company did not
contribute to the plan in 2003. The employee contribution limitations are
determined by formulas, which limit the upper one-third of the plan members from
contributing amounts that would cause the plan to be top-heavy. The employee
contribution is limited to the lesser of 20% of the employee's annual
compensation or $13,000 in 2004 and $14,000 in 2005. The contribution limit for
2004 and 2005 was $16,000 and $18,000 for employees 50 years of age or older,
respectively.
12. Hedging Program and Derivatives
On January 1, 2001, the Company adopted SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities" SFAS 133 as amended by SFAS 137
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB 133" and SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities. In 2003 the Company elected out of
hedge accounting as prescribed by SFAS 133. Accordingly, instruments are
recorded on the balance sheet at their fair value with adjustments to the
carrying value of the instruments bring recognized in oil and gas income in the
current period.
Under the terms of the Company's revolving credit facility, the Company
is required to maintain hedging agreements with respect to not less than 25% nor
more than 75% of it crude oil and natural gas production for a rolling six month
period. As of December 31, 2005 the Company's hedging positions were as follows:
Time Period Notional Quantities Price
- ---------------------------------- -------------------------------------------- ----------------------
April 2006 10,000 MMbtu of production per day Floor of $7.00
May 2006 10,000 MMbtu of production per day Floor of $8.00
June 2006 10,000 MMbtu of production per day Floor of $8.00
July 2006 10,000 MMbtu of production per day Floor of $7.00
August 2006 10,000 MMbtu of production per day Floor of $6.00
September 2006 10,000 Mmbtu of production per day Floor of $5.00
All hedge transactions are subject to the Company's risk management
policy, approved by the Board of Directors. The Company formally documents all
relationships between hedging instruments and hedged items, as well as its risk
management objectives and strategy for undertaking the hedge. This process
includes specific identification of the hedging instrument and the hedged
transaction, the nature of the risk being hedged and how the hedging
instrument's effectiveness will be assessed. Both at the inception of the hedge
and on an ongoing basis, the Company assesses whether the derivatives that are
used in hedging transactions are effective in offsetting changes in cash flows
of hedged items.
13. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's
crude oil and natural gas producing activities from continuing operations as
required by Statement of Financial Accounting Standards No. 69, "Disclosures
about Oil and Gas Producing Activities." Capitalized costs relating to oil and
gas producing activities from continuing operations are as follows:
Years Ended December 31
-----------------------------------
2005 2004
---------------- ---------------
(In thousands)
Proved crude oil and
natural gas properties .... $ 333,373 $ 298,382
Unproved properties ......... - -
---------------- ---------------
Total...................... 333,373 298,382
Accumulated depreciation,
depletion, and
amortization, and
impairment ............... (228,544) (219,726)
---------------- ---------------
Net capitalized costs .. $ 104,829 $ 78,656
================ ===============
F-28
Cost incurred in oil and gas property acquisitions and development
activities related to continuing operations are as follows:
Years Ended December 31
--------------------------------------------
2005 2004 2003
-------------- -------------- --------------
(In Thousands)
--------------------------------------------
Property acquisition costs:
Proved ...................... $ - $ - $ -
Unproved .................... - - -
-------------- -------------- --------------
$ - $ - $ -
============== ============== ==============
Property development and
exploration costs ........... $ 34,991 $ 9,088 $ 9,158
============== ============== ==============
The results of operations for oil and gas producing activities from
continuing operations for the three years ending December 31, 2005, 2004 and
2003, respectively are as follows:
Years Ended December 31
---------------------------------------------
2005 2004 2003
-------------- -------------- ---------------
(In thousands)
Revenues ................... $ 47,314 $ 33,073 $ 29,710
Production costs ........... (11,094) (8,567) (8,342)
Depreciation, depletion,
and amortization ......... (8,818) (7,117) (7,428)
General and administrative . (1,378) (1,281) (998)
-------------- -------------- ---------------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ 26,024 $ 16,108 $ 12,942
============== ============== ===============
Depletion rate per barrel
of oil equivalent ........ $ 8.77 $ 7.39 $ 7.24
============== ============== ===============
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved
crude oil and natural gas reserves as of December 31, 2005, 2004, and 2003
related to continuing operations. The Company's management emphasizes that
reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of producing oil and gas properties. Accordingly,
the estimates are expected to change as future information becomes available.
The estimates have been prepared by independent petroleum reserve engineers.
Liquid Natural
Hydrocarbons Gas
----------------- --------------
(Barrels) (Mcf)
(In thousands)
Proved developed and undeveloped reserves:
Balance at December 31, 2002 ..................... 3,236 78,196
Revisions of previous estimates ................ 268 6,759
Extensions and discoveries ..................... 44 28
Production ..................................... (229) (4,781)
----------------- --------------
Balance at December 31, 2003...................... 3,319 80,202
Revisions of previous estimates ................ (59) (754)
Extensions and discoveries ..................... 70 73
F-29
Production ..................................... (229) (4,403)
----------------- --------------
Balance at December 31, 2004...................... 3,101 75,118
Revisions of previous estimates ................ 9 (232)
Extensions and discoveries ..................... 168 16,259
Production ..................................... (194) (4,942)
----------------- --------------
Balance at December 31, 2005 3,084 86,203
================= ==============
Liquid Natural
Hydrocarbons Gas
----------------- --------------
(Barrels) (Mcf)
Proved developed reserves:
December 31, 2003................................. 1,886 39,371
================= ==============
December 31, 2004................................. 1,878 36,241
================= ==============
December 31, 2005................................. 1,942 38,794
================= ==============
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas are presented in accordance
with SFAS No. 69. The standardized measure does not purport to represent the
fair market value of the Company's proved crude oil and natural gas reserves. An
estimate of fair market value would also take into account, among other factors,
the recovery of reserves not classified as proved, anticipated future changes in
prices and costs, and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2005 adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
Set forth below is the Standardized Measure relating to proved oil and
gas reserves relating to continuing operations for the three years ending
December 31, 2005, 2004 and 2003.
Years Ended December 31
------------------------------------------------------
2005 2004 2003
------------------------------------------------------
(in Thousands)
Future cash inflows ... $ 937,638 $ 498,165 $ 512,797
Future production and
development costs ... (295,323) (194,187) (179,036)
Future income tax
expense ............. - - -
------------------------------------------------------
Future net cash flows . 642,315 303,978 333,761
Discount .............. (330,407) (154,943) (172,177)
------------------------------------------------------
Standardized Measure
of discounted future
net cash relating to
proved reserves ..... $ 311,908 $ 149,035 $ 161,584
======================================================
F-30
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure
related to continuing operations:
Year Ended December 31
----------------------------------------------------------
2005 2004 2003
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 149,035 $ 161,584 $ 110,316
Sales and transfers of oil and gas
produced, net of production costs ....... (36,220) (24,506) (21,368)
Net changes in prices and development
and production costs from prior year .... 142,116 (2,814) 42,398
Extensions, discoveries, and improved
recovery, less related costs ............ 51,438 810 471
Purchase of minerals in place.............. - - 313
Revision of previous quantity estimates ... 51 (1,818) 9,351
Other ..................................... (9,415) (380) 9,071
Accretion of discount ..................... 14,903 16,159 11,032
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 311,908 $ 149,035 $ 161,584
=================== =================== ==================
F-31