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<SEC-DOCUMENT>0000867665-06-000015.txt : 20060323
<SEC-HEADER>0000867665-06-000015.hdr.sgml : 20060323
<ACCEPTANCE-DATETIME>20060323134216
ACCESSION NUMBER: 0000867665-06-000015
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 9
CONFORMED PERIOD OF REPORT: 20051231
FILED AS OF DATE: 20060323
DATE AS OF CHANGE: 20060323
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: ABRAXAS PETROLEUM CORP
CENTRAL INDEX KEY: 0000867665
STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311]
IRS NUMBER: 742584033
STATE OF INCORPORATION: NV
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-16071
FILM NUMBER: 06705761
BUSINESS ADDRESS:
STREET 1: 500 N LOOP 1604 E STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
BUSINESS PHONE: 2104904788
MAIL ADDRESS:
STREET 1: 500 N LOOP 1604 EAST STE 100
CITY: SAN ANTONIO
STATE: TX
ZIP: 78232
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>abp10k2005fnl.txt
<TEXT>
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 [ ]
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
ABRAXAS PETROLEUM CORPORATION
FORM 10-K
TABLE OF CONTENTS
Page
PART I
<S> <C> <C>
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
<PAGE>
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
</TABLE>
4
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
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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."
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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.
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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
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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
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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.
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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.
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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
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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.
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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
<PAGE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
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
------------ ------------ ------------ ------------- ------------- --------- --------------
<S> <C> <C> <C> <C> <C> <C> <C>
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
============ ============ ============ ============= ============= ========= ==============
- ---------------
</TABLE>
(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:
<TABLE>
<CAPTION>
Productive Wells (1)
As of December 31, 2005
---------------------------------------------------------------------
State Crude Oil Natural Gas
------------------------------- -------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
<S> <C> <C> <C> <C>
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
=============== ============== =============== ================
- ------------
</TABLE>
(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
<PAGE>
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.
<TABLE>
<CAPTION>
Estimated Proved Reserves
------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
<S> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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:
<TABLE>
<CAPTION>
2005 2004 2003
--------------- -------------- --------------
<S> <C> <C> <C>
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
- ------------------
</TABLE>
(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
<PAGE>
<TABLE>
<CAPTION>
2005 2004 2003
-------------------------- ----------------------------- -----------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ----------- ---------- --------
Exploratory(3)
Productive(4)
<S> <C> <C> <C> <C> <C> <C>
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
============ ========== ============ ========== ========== ========
- ------------------
</TABLE>
(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
<PAGE>
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.
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------------------
2005 2004 * 2003 * 2002* 2001 *
-------------- ------------- --------------- ---------------- ---------------
(Dollars in thousands except per share data)
<S> <C> <C> <C> <C> <C>
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
<PAGE>
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.
------------------
</TABLE>
(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
<PAGE>
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.
<TABLE>
<CAPTION>
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
---------- ---------- ----------- ---------- ---------- ---------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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.
<TABLE>
<CAPTION>
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
---------- ---------- ----------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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
<PAGE>
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 $15.6 million
for 2006. This increase in cash interest expense has required us to increase our
production and cash flow from operations in order to meet our debt service
requirements, as well as to fund the development of our numerous drilling
opportunities.
28
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Outlook for 2006. As a result of final 2005 financial results and
current market conditions, we have updated our operating and financial guidance
for year 2006 as follows:
Production:
BCFE (approximately 80% gas)....................... 7.5 - 8.5
Exit Rate (Mmcfe/d)................................... 22 - 24
Price Differentials (Pre Hedge):
Gas (% Mcf)........................................ 5%
Oil ($/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.
<TABLE>
<CAPTION>
Years Ended December 31
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