SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K/A Number 3
(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, 2006
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
COMMISSION FILE NUMBER 001-16701
ABRAXAS PETROLEUM CORPORATION
(Exact name of Registrant as specified in its charter)
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Nevada 74-2584033
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(State or Other Jurisdiction of (I.R.S. Employer Identification Number)
Incorporation or Organization)
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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:
Title of each class: Name of each exchange on which registered:
Common Stock, par value $.01 per share American Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
None
Indicate by check mark if the registrant is a well-known seasoned issuer,
as defined in Rule 405 of the Securities Act. 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 [ ]
1
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, 2006, the aggregate market value of the common stock
held by non-affiliates of the registrant was $167,042,727 based on the closing
sale price as reported on the American Stock Exchange.
As of March 9, 2007, there were 42,762,466 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 2007Annual Meeting of
Shareholders to be held on May 23, 2007.
2
In connection with the filing of a Registration Statement on Form S-1 by
Abraxas Energy Partners, L.P. Our reserve estimates at December 31, 2006
included approximately 12 Bcf of reserves classified as proved undeveloped
reserves in our reserve report prepared by independent third-party engineers as
of December 31, 2006. The subject reserves, predominately located in West Texas,
are scheduled to be produced from deeper formations in wellbores that are
currently producing in commercial quantities from a shallower formation. We
scheduled the redeepenings to develop such reserves from the deeper formation
beginning at the time the shallower formation is expected to be depleted, which
according to our reserve report would not occur within the next five years.
In connection with the filing of the Registration Statement on Form S-1 of
Abraxas Energy, we concluded that we should reclassify these reserves and remove
them from the proved undeveloped category as previously reported in our 2006
Form 10-K because the future redeepenings are not scheduled to be performed for
many years in the future and require significant additional capital such as for
deepening wells are subject to greater uncertainties such as depletion from
offsetting wells, changes in management, greater geological risks, changes in
the company's strategy or focus and other factors. We believe that these greater
uncertainties suggest that these volumes should remain as unproved until they
are more reasonably certain of being developed. These reserves represented
approximately 12% of our proved reserves at December 31, 2006 but only
approximately 3% of our PV-10 at such date.
This amendment is being filed to reflect the restatement of the Company's
consolidated financial statements to reflect the impact of the changes discussed
above. See Note 14 to the consolidated financial statements and other
information related to such restated financial statements. Except for Items 1,
1A and 2 of Part I, Items 6, 7 and 8 of Part II and Item 15 of Part IV, no other
information included in the original report on Form 10-K filed on March 14,
2007, as amended by Form 10-K/A Number 1 as filed on April 30, 2007, as amended
by Form 10-K A/ Number 2 as filed on August 24, 2007, is amended by this Form
10-K/A Number 3. For convenience, we have repeated our original Form 10-K filed
on March 14, 2007 in its entirety.
This amendment does not reflect events occurring after the filing of the
Original Form 10-K, and does not modify or update the disclosures therein in any
way other than as required to reflect the matters described above. Such events
include among others, the events described in our quarterly report on Form 10-Q
for the quarter ended March 31, 2007, as amended, the quarterly report on Form
10-Q for the quarter and year-to-date period ended June 30, 2007, as amended by
Form 10-Q/A Number 1 filed on August 24, 2007, as amended, the quarterly report
on Form 10-Q for the quarter and year-to-date period ended September 30, 2007,
as amended and the events described in our current reports on Form 8-K filed
after the filing of the Original Form 10-K. -
ABRAXAS PETROLEUM CORPORATION
FORM 10-K/A Number 3
TABLE OF CONTENTS
Page
Item 1. Business..........................................................................................4
Item 1A. Risk Factors....................................................................................12
Item 1B. Unresolved Staff Comments.......................................................................20
Item 2. Properties.......................................................................................20
Item 3. Legal Proceedings................................................................................25
Item 4. Submission of Matters to a Vote of Security Holders..............................................25
Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities............................................26
3
Item 6. Selected Financial Data..........................................................................27
Item 7. Management's Discussion And Analysis Of Financial Condition And Results Of Operations............28
Item 7A. Quantitative and Qualitative Disclosures about Market Risk......................................45
Item 8. Financial Statements and Supplementary Data......................................................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...............................................................................47
Item 15. Exhibits, Financial Statement Schedules.........................................................47
4
FORWARD-LOOKING INFORMATION
We make forward-looking statements throughout this document. Whenever
you read a statement that is not simply a statement of historical fact (such as
statements including words like "believe", "expect", "anticipate", "intend",
"plan", "seek", "estimate", "could", "potentially" or similar expressions), you
must remember that these are forward-looking statements and that our
expectations may not be correct, even though we believe they are reasonable. The
forward-looking information contained in this document is generally located in
the material set forth under the heading "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 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 economic and business conditions;
o political and economic conditions in oil producing countries,
especially those in the Middle East;
o price 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 document.
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.
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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 exploration 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 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 primary properties are located in mature fields that exhibit
relatively long-lived production, with a reserve to production index of 12.8
years (5.8 years for our proved developed reserves), as of December 31, 2006. At
December 31, 2006, we owned interests in 101,815 gross acres (87,554 net acres)
applicable to our continuing operations, and operated properties accounting for
approximately 96% of our PV-10, affording us substantial control over the timing
and incurrence of operating and capital expenditures. At December 31, 2006,
estimated total proved reserves were 86.9 Bcfe with an aggregate PV-10 of $157
million. During 2006, we participated in the drilling of 5 gross (4.2 net) wells
with 4 gross (3.2 net) wells being successful. Total capital expenditures for
2006 were approximately $26 million, of which 35% was spent on 2 wells in the SW
Oates Field of West Texas which were still in progress at year-end. Overall,
during 2006 our proved reserves declined by approximately 2.1 Bcfe. Property
sales of 1.8 Bcfe and production of 7.7 Bcfe further reduced our proved
reserves.
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 51 proved undeveloped projects and
have identified over 500 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 ranging from $27.0 to $44.0 million for 2007, (the final amount of which
will depend upon our cash flow from operations which, in turn, is dependent upon
our production volumes and commodity prices) which will be used primarily for
the development of our current properties as well as to drill and complete the
wells that were in progress at the end of 2006. 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. To help mitigate the impact
of commodity price volatility, we hedge our production through the use of price
floors. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations - General - Commodity Prices and Hedging Activities" and
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Note 12 of the notes to our consolidated financial statements for more
information regarding our hedging activities.
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, 2006, two purchasers accounted for
approximately 49% 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.
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 and
condensate 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
7
facilities by their new, unregulated owners. Note, however, that FERC 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.
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
8
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.
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.
9
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.
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
10
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 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.
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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."
Employees
As of March 9, 2007 we had 50 full-time employees in the United States,
including two executive officers, three non-executive officers, one petroleum
engineer, one geologist, five managers, one landman, eleven administrative and
support personnel and 26 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
We file annual, quarterly and current reports, proxy statements and other
information with the Securities and Exchange Commission. You may read and copy
any document we file with the SEC at the SEC's public reference room at 100 F
Street, NE, Room 1580, Washington, D.C. 20549. Please call the SEC at
1-800-SEC-0330 for information on the public reference room. The SEC maintains
an internet web site that contains annual, quarterly and current reports, proxy
statements and other information that issuers (including Abraxas) file
electronically with the SEC. The SEC's web site is www.sec.gov.
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. Information on our website is not
incorporated by reference into this Form 10-K and should not be considered part
of this report or any other filing that we make with the SEC.
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 9, 2007, we had
total indebtedness, including our floating rate senior secured notes due 2009,
or notes, of approximately $127.3 million, all of which is secured indebtedness.
We also had availability of $12.7 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 affects
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;
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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 all of our capital expenditures.
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 exploration 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, including during 2006, 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.
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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 exploration activities or, through
engineering studies, identify additional behind-pipe zones or secondary recovery
reserves. We cannot assure you that our exploration and development activities
will result in increases in our proved reserves. For example, in 2006, while we
have had some success in pursuing these activities, we were not able to fully
replace the production volumes lost from natural field declines and property
sales. If our proved reserves continue to decline in the future, our production
will also decline and, consequently, 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 45% of our total estimated proved reserves
at December 31, 2006 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.
A substantial portion of our production is currently concentrated in one
well.
Approximately 29% of our production during 2006 was from a single well in
west Texas. Like all natural gas wells, the rate of production from this well
will decline over time and the reserves associated with this well will also
decrease. If production from this well decreases, and if we are unable to reduce
the percentage of our production represented by this well, it would have a
material adverse effect 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 depletion and 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
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 45% of our total
estimated proved reserves at December 31, 2006 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;
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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
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 2005, we incurred a hedging loss of $592,000,
resulting from the price floors we established. For the year ended December 31,
2004 and 2006, we recognized a gain from hedging activities of approximately
$118,000 and $646,000 respectively. 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 in the future
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 its contractual obligations.
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
15
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, 2006, we had, subject to the limitation discussed below,
$192.7 million of net operating loss carryforwards for U.S. tax purposes. These
loss carryforwards will expire through 2026 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.
Therefore, we have established a valuation allowance of $66.9 for deferred tax
assets at December 31, 2005 and 2006.
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 IndustryItem 1A.
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;
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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.
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 exploration 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, 2006.
The sales prices as of such date used for purposes of such estimates were $5.83
per Mcf of natural gas and $56.42 per Bbl of crude oil. This compares with $8.84
per Mcf of natural gas and $56.92 per Bbl of crude oil as of December 31, 2005.
These estimates also assume that we will make future capital expenditures of
approximately $73.4 million in the aggregate through 2026, with the majority
expected to be incurred from 2007 to 2012, 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.
17
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
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.
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Shares eligible for future sale may depress our stock price.
At March 9, 2007, we had 42,769,284 shares of common stock outstanding of
which 3,628,078 shares were held by affiliates and, in addition, 2,467,716
shares of common stock were subject to outstanding options granted under certain
stock option plans (of which 1,908,116 shares were vested at March 9, 2007).
All of the shares of common stock held by affiliates are restricted or
controlled 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.
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.
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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.
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, 2006
located in those two regions. We operate 93% of our wells in Texas. During 2006,
we drilled a total of 5 new wells (4.2 net) in Texas with an 80% success rate.
This drilling, although somewhat successful did not fully replace the production
volumes lost from natural field declines and property sales. During 2006, we
sold natural gas properties with reserves of 1.8 Bcfe and produced 7.7 Bcfe.
Operations in south Texas are concentrated along the Edwards trend in
DeWitt and Lavaca Counties, the Frio/Vicksburg trend in San Patricio County and
the Wilcox trend in Bee, Karnes, Goliad and DeWitt Counties. In south Texas, we
own an average 94% working interest in 41 wells with average production of 205
net Bbls of crude oil and 5,759 net Mcf of natural gas per day for the year
ended December 31, 2006. As of December 31, 2006, we had estimated net proved
reserves in south Texas of 29.9 Bcfe (89% natural gas) with a PV-10 of $59.1
million, 62% 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 which was brought onto production in August 2005 that
accounted for approximately 29% of our production in 2006.
In west Texas, we own an average 75% working interest in 169 wells with
average daily production of 298 net Bbls of crude oil and 12,090 net Mcf of
natural gas per day for the year ended December 31, 2006. As of December 31,
2006, we had estimated net proved reserves in west Texas of 56.0 Bcfe (78%
natural gas) with a PV-10 of $96.1 million, 50% of which was attributable to
proved developed reserves.
In the Abraxas Cherry Canyon Field of Ward County, Texas, we have two wells
currently being completed in the Bell and Cherry Canyon sands. In the Oates SW
Field of Pecos County, Texas, we have two wells which began drilling in 2006 and
are still in progress and one well that is currently awaiting a drilling rig to
drill the horizontal lateral in the Devonian formation.
Wyoming
We currently hold 50,409 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
20
formations. We own a 100% working interest in these wells that produced a
combined average of 46 net barrels of crude oil per day in 2006. As of December
31, 2006, we had estimated net proved producing reserves in Wyoming of 169,633
barrels of crude oil with a PV-10 of $1.6 million.
During 2006, the wells that were drilled in late 2005 were fracture
stimulated and brought onto production. In the Brooks Draw Field of Wyoming, we
are currently in the process of permitting new horizontal Mowry Shale wells
while monitoring industry activity in this new area. We plan to drill several
more wells in Wyoming during 2007.
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 as of
Developed Undeveloped Fee Mineral
Acreage (1) Acreage (2) Acreage (3)
----------------------- ---------------------------- ----------------------- ---------------
Total
Gross Acres Net Gross Acres Net Gross Net Net
(4) Acres (5) (4) Acres (5) Acres (6) Acres Acres
----------------------- ---------------------------- ------------ ---------- ---------------
South Texas 4,687 4,258 3,496 3,256 - - 7,514
West Texas 20,868 15,616 17,752 12,617 12,007 5,272 33,505
Wyoming 3,400 3,400 47,009 43,111 - - 46,511
N. Dakota - - 80 24 - - 24
----------------------- ---------------------------- ------------ ---------- ---------------
Total 28,955 23,274 68,337 59,008 12,007 5,272 87,554
======================= ============================ ============ ========== ===============
---------------
(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
expressed separately for natural gas and crude oil, as of December 31, 2006:
Productive Wells (1)
As of December 31, 2006
---------------------------------------------------------------------
State Crude Oil Natural Gas
-------------------------------- ----------------------------------
Gross(2) Net(3) Gross(2) Net(3)
--------------- -------------- --------------- ----------------
South Texas 17.0 17.0 24.0 21.2
West Texas 133.0 103.4 36.0 23.5
Wyoming 10.0 10.0 - -
--------------- -------------- --------------- ----------------
Total 160.0 130.4 60.0 44.7
=============== ============== =============== ================
------------
(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.
21
Reserves Information
The natural gas and crude oil reserves have been estimated as of December
31, 2004, December 31, 2005, and December 31, 2006, 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 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,
2004, December 31, 2005 and December 31, 2006.
Estimated Proved Reserves
---------------------------------------------------------
Proved Proved Total
Developed Undeveloped Proved
-------------- --------------- ------------------
As of December 31, 2004
Crude oil (MBbls) 1,878 1,178 3,056
Natural gas (MMcf) 36,247 35,482 71,729
As of December 31, 2005
Crude oil (MBbls) 1,942 1,093 3,035
Natural gas (MMcf) 38,797 41,474 80,271
As of December 31, 2006
Crude oil (MBbls) 1,708 1,048 2,756
Natural gas (MMcf) 37,333 33,000 70,333
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 exploration 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."
22
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.
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, 2006. The average sales prices as of such date used for
purposes of such estimates were $56.42 per Bbl of crude oil and $5.83 per Mcf of
natural gas. It is also assumed that we will make future capital expenditures of
approximately $73.4 million in the aggregate, most of which is in the years 2007
through 2012, 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,
2006:
2006 2005 2004
--------------- -------------- --------------
Crude oil production (Bbls) 200,436 194,366 220,409
Natural gas production (Mcf) 6,515,055 4,942,355 4,403,030
Natural gas liquids production (Bbls) - - 8,875
Total production (Mmcfe) (2) 7,718 6,109 5,779
Average sales price per Bbl of crude oil $ 62.10 $ 53.27 $ 40.12
Average sales price per Mcf of natural
gas (1) $ 5.78 $ 7.48 $ 5.45
Average sales price per Bbl of natural
gas liquids $ - $ - $ 26.32
Average sales price per Mcfe $ 6.49 $ 7.75 $ 5.72
Average cost of production per Mcfe
produced (2) $ 1.52 $ 1.82 $ 1.48
------------------
(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 during the three years ended December
31, 2006:
23
2006 2005 2004
------------------------ ------------------------ -------------------
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
------------ ---------- ------------ ---------- ---------- --------
Exploratory(3)
Productive(4)
Crude oil - 1.0 1.0 2.0 2.0
Natural gas 1.0 1.0 1.0 1.0 - -
Dry holes(5) 1.0 1.0 - - - -
------------ ---------- ------------ ---------- ---------- --------
Total 2.0 2.0 2.0 2.0 2.0 2.0
============ ========== ============ ========== ========== ========
Development(6)
Productive (4)
Crude oil 2.0 1.2 4.0 4.0 - -
Natural gas 1.0 1.0 5.0 5.0 1.0 1.0
Dry holes (5) - - 1.0 1.0 1.0 1.0
------------ ---------- ------------ ---------- ---------- --------
Total 3.0 2.2 10.0 10.0 2.0 2.0
============ ========== ============ ========== ========== ========
------------------
(1) A gross well is a well in which we own an interest.
(2) The number of net wells represents the total percentage of working
interests held in all wells (e.g., total working interest of 50% is
equivalent to 0.5 net well. A total working interest of 100% is
equivalent to 1.0 net well).
(3) An exploratory well is a well drilled to find and produce natural gas
or crude oil in an unproved area, to find a new reservoir in a field
previously found to be producing natural gas or crude oil in another
reservoir, or to extend a known reservoir.
(4) A productive well is an exploratory or a development well that is not a
dry hole.
(5) A dry hole is an exploratory or development well found to be incapable
of producing either natural gas or crude oil in sufficient quantities
to justify completion as a natural gas or crude oil well.
(6) A development well is a well drilled within the proved area of a
natural gas or crude oil reservoir to the depth of stratigraphic
horizon (rock layer or formation) noted to be productive for the
purpose of extracting proved natural gas or crude oil reserves.
As of March 9, 2007, we had 3 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 $21,152 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 and an office building in Scurry County,
Texas, 600 acres of land in Scurry County, Texas, 160 acres of land in Coke
County, Texas and 11,537 acres of land in Pecos County, Texas. We also own 22
vehicles which are used in the field by employees. We own two workover rigs,
which are used for servicing our wells.
24
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,
2006, Abraxas was not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on Abraxas.
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, 2006.
25
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
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 $ 7.25 $ 5.24
Second Quarter 6.50 4.00
Third Quarter 4.86 2.90
Fourth Quarter 4.35 2.90
2007 First Quarter (Through March 9, 2007) $ 3.42 $ 2.81
Holders
As of March 9, 2007, we had 42,769,284 shares of common stock outstanding
and had approximately 1,206 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.
Performance Graph
Set forth below is a performance graph comparing yearly cumulative total
stockholder return on the Abraxas common stock with (a) the monthly index of
stocks included in the Standard and Poor's 500 Index and (b) the Energy Capital
Solutions Index (the "ECS Index") of stocks of crude oil and natural gas
exploration and production companies with a market capitalization of less than
$800 million (the "Comparable Companies"). The Comparable Companies are: Adams
Resources & Energy Inc., Callon Petroleum Company, Carrizo Oil & Gas Inc.,
Clayton Williams Energy Inc., Double Eagle Petroleum Company, Edge Petroleum
Corporation, Contango Oil & Gas Company, CREDO Petroleum Corporation, Markwest
Hydrocarbon Inc., NGAS Resources Inc., Parallel Petroleum Corporation and Arena
Resources Inc.
All of these cumulative total returns are computed assuming the value of
the investment in Abraxas common stock and each index as $100.00 on December 31,
2001, and the reinvestment of dividends at the frequency with which dividends
were paid during the applicable years. The years compared are 2002, 2003, 2004,
2005 and 2006.
26
[GRAPHIC OMITTED][GRAPHIC OMITTED]
Dec-01 Dec-02 Dec-03 Dec-04 Dec-05 Dec-06
ECS Index 100.00 98.07 201.65 251.01 469.62 602.29
S&P 500 100.00 76.63 96.85 105.56 108.73 123.54
ABP 100.00 42.42 93.18 175.76 400.00 234.09
Item 6. Selected Financial Data
The following selected financial data as of and for the years ended is
derived from our Consolidated Financial Statements. The data should be read in
conjunction with our Consolidated Financial Statements and Notes thereto, and
other financial information included herein. See "Financial Statements" in Item
8.
Year Ended December 31,
--------------------------------------------------------------------------------------
2006 2005 2004 2003 2002
---- ----- ---- ---- -----
(Dollars in thousands except per share data)
Total revenue - continuing operations $ 51,723 $ 48,625 $ 33,854 $ 30,380 $ 21,541
Net income (loss) $ 700 $ 19,117 (1) $ 12,360 (2) $ 56,798(3) $ (119,197) (4)
Net income (loss) - discontinued
operations $ - $ 12,846 (1) $ 3,323 $ 70,024(3) $ (63,355)
Net income (loss) - continuing operations
$ 700 $ 6,271 $ 9,037 $ (13,226) $ (55,842)
Net income (loss) per common share -
diluted $ 0.02 $ 0.46 $ 0.32 $ 1.61 $ (3.98)
Weighted average shares outstanding -
diluted (in thousands) 43,862 41,164 38,895 35,364 (5) 29,979
Total assets $ 116,940 $ 121,866 $ 152,685 $ 126,437 $ 181,425
27
Long-term debt, excluding current
maturities $ 127,614 $ 129,527 $ 126,425 $ 184,649 $ 201,850
Total stockholders' equity (deficit) $ (22,165) $ (23,701) $ (53,464) $ (72,203) $ (142,254)
------------------
(1) Includes gain on the sale of foreign subsidiary of $17.3 million net of
non-cash tax of $6.1 million.
(2) Includes gain on debt extinguishment of $12.6
million and a deferred tax benefit of $6.1 million. (3) Includes gain on sale of
foreign subsidiaries of $ 68.9 million in 2003. (4) Includes ceiling limitation
write-down of $116.0 million ($28.2 million related to continuing operations).
(5) 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 exploration 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 development activities with
complementary exploration projects in our core areas of operation.
While we have attained positive net income from continuing operations in
three of the last five years, 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 and crude oil;
o the availability of, and our ability to raise additional
capital resources and provide liquidity to meet, cash flow
needs;
o the level of and interest rates on borrowings; and
o the level and success of exploration and development activity.
Commodity Prices and Hedging Activities. The results of our operations are
highly dependent upon the prices received for our natural gas and crude oil
production. Substantially all of our sales of natural gas and crude oil are made
in the spot market, or pursuant to contracts based on spot market prices, and
not pursuant to long-term, fixed-price contracts. Accordingly, the prices
received for our natural gas and crude oil production are dependent upon
numerous factors beyond our control. Significant declines in prices for natural
28
gas and crude oil could have a material adverse effect on our financial
condition, results of operations and quantities of reserves recoverable on an
economic basis. Recently, the prices of natural gas and crude oil have been
volatile. During the first half of 2006, prices for natural gas and crude oil
were sustained at record or near-record levels. Supply and geopolitical
uncertainties resulted in significant price volatility during the remainder of
2006 with both natural gas and crude oil prices weakening. New York Mercantile
Exchange (NYMEX) futures prices for West Texas Intermediate (WTI) crude oil
averaged $66.18 per barrel for the year, with a low price of about $56.27 per
barrel occurring in the fourth quarter of 2006. U.S. natural gas pricing
declined during 2006. NYMEX Henry Hub futures prices averaged $6.98 per million
British thermal units (MMBtu) during 2006 as compared to $9.13 per MMBtu during
2005. The natural gas market continues to be driven by high natural gas storage
inventories and mild early winter conditions for much of the country. NYMEX
natural gas prices ended the year at about $6.30 per MMBtu. The outlook for the
commodity markets in 2007 calls for continued volatility.
We seek to reduce our exposure to price volatility by hedging our
production through price floors. In 2005 we incurred a hedging loss of $592,000.
For the years ended December 31, 2004 and 2006 we recognized gains from hedging
activities of approximately $118,000 and $646,000 respectively.
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 2007 10,000 MMbtu of production per day Floor of $ 4.50
May 2007 10,000 MMbtu of production per day Floor of $ 5.00
June 2007 10,000 MMbtu of production per day Floor of $ 5.00
July 2007 10,000 MMbtu of production per day Floor of $ 4.25
August 2007 10,000 MMbtu of production per day Floor of $ 5.00
September 2007 10,000 MMbtu of production per day Floor of $ 5.50
At December 31, 2006 the aggregate fair market value of our hedges was
approximately $157,286.
Production Volumes. Because our proved reserves will decline as natural gas
and crude oil are produced, unless we acquire additional properties containing
proved reserves or conduct successful exploration 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, exploration and development projects.
We had capital expenditures for 2006 of $26.3 million and have a capital
budget for 2007 ranging from $27 to $44 million in 2007, the exact amount of
which will depend on our success rate, production levels and commodity prices.
During 2006, our production volumes increased by 26% over 2005.
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 $12.7 million of
availability under our revolving credit facility. We may also seek equity
capital in order to fund our planned drilling expenditures.
Exploration 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 94% of the properties accounting for approximately 93% of our PV-10,
giving us substantial control over the timing and incurrence of operating and
capital expenditures. In addition, we have 51 proved undeveloped projects and
have identified over 500 drilling and recompletion opportunities on our existing
acreage, the successful development of which we believe could significantly
increase our daily production and proved reserves.
29
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 exploration activities or, through
engineering studies, identify additional behind-pipe zones or secondary recovery
reserves. We cannot assure you that our exploration and development activities
will result in increases in our proved reserves. For example, in 2006, while we
have had some success in pursuing these activities, we were not able to fully
replace the production volumes lost from natural field declines and property
sales. If our proved reserves continue to decline in the future, our production
will also decline and, consequently, 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 45% of our total estimated proved reserves
at December 31, 2006 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
$127.3 million and availability of $12.7 million under the revolving credit
facility. Cash interest expense was $16.6 million during 2006 and based on
current interest rates and our outstanding indebtedness at March 9, 2007, would
be approximately $16.3 million for 2007. This increase in cash interest expense
resulted in a larger percentage of our production and cash flow from operations
being used to meet our debt service requirements. As a result, we will need to
increase our cash flow from operations in order to fund the development of our
numerous drilling opportunities which, in turn, will be dependent upon the level
of our production volumes and commodity prices.
Results of Operations
Selected Operating Data. The following table sets forth certain of our
operating data for the periods presented. All data has been restated to reflect
continuing operations.
Years Ended December 31
--------------------------------------------------------------
(dollars in thousands, except per unit data)
2006 2005 2004
------------------- ------------------- -------------------
Operating revenue(1):
Crude oil sales............................. $ 12,446 $ 10,354 $ 8,843
NGLs sales ................................. - - 234
Natural gas sales........................... 37,648 36,960 23,996
Rig and other............................... 1,629 1,311 781
------------------- ------------------- -------------------
Total operating revenues ................... $ 51,723 $ 48,625 $ 33,854
=================== =================== ===================
Operating income .......................... $ 19,029 $ 22,104 $ 12,165
Crude oil production (MBbls)................ 200.4 194.4 220.4
NGLs production (MBbls)..................... - - 8.9
Natural gas production (MMcf)............... 6,515.0 4,942.4 4,403.0
Average crude oil sales price (per Bbl) $ 62.10 $ 53.27 $ 40.12
Average NGLs sales price (per Bbl) $ - $ - $ 26.32
Average natural gas sales price (per Mcf) $ 5.78 $ 7.48 $ 5.45
-------------------
(1) Revenue and average sales prices are net of hedging activities.
Comparison of Year Ended December 31, 2006 to Year Ended December 31, 2005
Operating Revenue. During the year ended December 31, 2006, operating
revenue from natural gas and crude oil sales increased by $2.8 million from
$47.3 million in 2005 to $50.1 million in 2006. The increase in revenue was
primarily due to increased production volumes in 2006 as compared to 2005 offset
30
by lower natural gas prices realized in 2006 as compared to 2005. Higher
production volumes contributed $12.1 million to natural gas and crude oil
revenue, and increased crude oil realized prices contributed $1.8 million. Lower
natural gas prices had a negative impact of $11.1 million on natural gas and
crude oil revenue during 2006.
Crude oil sales volumes increased from 194.4 MBbls in 2005 to 200.4
MBbls during 2006. The increase in crude oil production was primarily due to
production from wells in Wyoming and south Texas that were brought onto
production during 2006. Natural gas sales volumes increased from 4.9 Bcf in 2005
to 6.5 Bcf in 2006. This increase was primarily due to production from a west
Texas well drilled and brought onto production in August 2005. This well
produced 2.2 Bcf in 2006 as compared to 0.6 Bcf in 2005. The increase in
production was partially offset by natural field declines and the sale of
properties in Live Oak County, Texas effective August 1, 2006. These properties
produced 286.8 MMcf in 2005 compared to 182.3 MMcf in 2006 through the date of
sale.
Average sales prices in 2006 net of hedging costs were:
o $62.10 per Bbl of crude oil, and
o $ 5.78 per Mcf of natural gas.
Average sales prices in 2005 net of hedging costs were:
o $53.27 per Bbl of crude oil, and
o $ 7.48 per Mcf of natural gas.
Lease Operating Expense and Production Taxes. Lease operating expense, or
LOE, increased from $11.1 million in 2005 to $11.8 million in 2006. The increase
in LOE was primarily due to a general increase in the cost of field services.
Lower production taxes, due to the lower realized price for natural gas, were
offset by increased advalorem taxes related to new wells. Our LOE on a per Mcfe
basis for the year ended December 31, 2006 was $1.52 per Mcfe compared to $1.82
per Mcfe in 2005. The decrease on a per Mcfe basis was primarily due to
increased production volumes in 2006 as compared to 2005.
G&A Expense. General and administrative, or G&A expense, excluding stock
based compensation decreased from $5.5 million in 2005 to $4.2 million in 2006.
The decrease in G&A expense in 2006 was primarily due to higher performance
bonuses in 2005 as compared to 2006. Performance bonuses amounted to $162,000 in
2006, as compared to $960,000 in 2005. Our G&A expense on a per Mcfe basis
decreased from $0.90 in 2005 to $0.54 in 2006. The decrease in the per Mcfe cost
was due to decreased G&A expense in 2006 as compared to 2005 as well as
increased production volumes in 2006 as compared to 2005.
Stock-based Compensation. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment." SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
those awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. In December 2005, we elected early adoption
of SFAS 123R .
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method or a "modified retrospective" method. We elected
to use the "modified retrospective" method. Under the "modified retrospective"
method, compensation cost is recognized in the financial statements beginning
with the effective date, based on the requirements of SFAS 123R for all
share-based payments granted after that date, and based on the requirements of
SFAS 123 for all unvested awards granted prior to the effective date of SFAS
123R. The "modified retrospective" method, also permits entities to restate
financial statements of previous periods based on proforma disclosures made in
accordance with SFAS 123, accordingly we have restated prior year financial
statements to reflect this method.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized stock-based compensation of $998,000 during 2006 as a result of
the adoption of this accounting change compared to $247,000 in 2005, as
restated. The increase in stock-based compensation in 2006 as compared to 2005
31
was due to new options granted during the latter part of 2005 and the first half
of 2006 and the increase in the calculated fair value of these grants due to
higher option prices as a result of the increase in the price of our Common
Stock over previous option grants. Also contributing to the increase was
director options grants that vest upon issuance resulting in all of the fair
value of the options being recognized as stock-based compensation in the current
period.
We currently utilize a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees. While SFAS 123R
permits entities to continue to use such a model, the standard also permits the
use of a more complex binomial, or "lattice" model. Based upon research done by
us on the alternative models available to value option grants, and in
conjunction with the type and number of stock options expected to be issued in
the future, we have determined that we will continue to use the Black-Scholes
model for option valuation.
DD&A Expense. Depreciation, depletion and amortization, or DD&A, expense
increased from $8.9 million in 2005 to $14.9 million in 2006. The increase in
DD&A was primarily due to increased production volumes in 2006 as well as a
general increase in drilling and development cost in 2006 as compared to 2005.
The increase in development cost was a result of an increase in estimated future
development cost which causes an increase in the depletion base on which
depletion is calculated. Our DD&A expense on a per Mcfe basis for 2006 was $1.94
per Mcfe as compared to $1.46 per Mcfe in 2005. The increase in the per Mcfe
basis was due to the increased depletion base as a result of higher estimated
future development cost in 2006 as compared to 2005, which was partially offset
by higher production volumes in 2006.
Interest Expense. Interest expense increased from $14.0 million to $16.8
million for 2006 compared to 2005. The increase in interest expense was
primarily due to increased interest rates during 2006.
Income from discontinued operations. Income from discontinued operations
was $12.8 million in 2005. There was no income from discontinued operations in
2006. On February 28, 2005, Grey Wolf Exploration Inc. completed an IPO
resulting in Abraxas substantially divesting itself of its investment in Grey
Wolf. The operations of Grey Wolf, previously reported as a business segment,
are reported as discontinued operations for all periods presented in the
accompanying financial statements and the operating results are reflected
separately from the results of continuing operations.
Income from discontinued operations for the period ended December 31, 2005
included a gain on the disposal of Grey Wolf of $17.3 million, net of non-cash
income tax of $6.1 million, and a loss from operations, including debt
retirement costs, of $4.4 million.
Comparison of Year Ended December 31, 2005 to Year Ended December 31, 2004
Operating Revenue. During the year ended December 31, 2005, operating
revenue from natural gas and crude oil sales increased by $14.2 million from
$33.1 million in 2004 to $47.3 million in 2005. The increase in revenue was
primarily due to increased commodity prices realized in 2005 as compared to
2004, as well as an increase in natural gas production volumes. Higher commodity
prices contributed $12.6 million to natural gas and crude oil revenue while
increased production volumes contributed $1.6 million to revenue.
Prior to 2005, we were being paid on certain wells for the natural gas
liquid content of the gas as a separate component as well as the value of the
residue gas after processing. In 2005 we elected to be paid for this natural gas
at the wellhead. Accordingly, we did not recognize any natural gas liquids
revenue in 2005. Crude oil sales volumes decreased slightly from 220.4 MBbls in
2004 to 194.4 MBbls during 2005. The decrease was primarily due to natural field
declines. Natural gas sales volumes increased from 4.4 Bcf in 2004 to 4.9 Bcf in
2005. This increase was primarily due to new production during 2005 offset by
natural field declines. New production brought on line at various times during
2005 contributed 1.1 Bcf to natural gas production and was partially offset by
natural field decline.
Average sales prices in 2005 net of hedging costs were:
o $53.27 per Bbl of crude oil,
o $ 7.48 per Mcf of natural gas.
32
Average sales prices in 2004 net of hedging costs were:
o $40.12 per Bbl of crude oil,
o $26.32 per Bbl of natural gas liquids,and
o $ 5.45 per Mcf of natural gas.
Lease Operating Expense and Production Taxes. Lease operating expense, or
LOE, increased from $8.6 million in 2004 to $11.1 million in 2005. The increase
in LOE was primarily due to higher production taxes associated with higher
commodity prices in 2005 as compared to 2004 as well as a general increase in
the cost of field services and the amount of services required by us as we
increased our drilling activity during 2005 as compared to 2004. Our LOE on a
per Mcfe basis for the year ended December 31, 2005 was $1.82 per Mcfe compared
to $1.48 per Mcfe in 2004. The increase on a per Mcfe basis was due to increased
cost in 2005 as compared to 2004.
G&A Expense. G&A expense, excluding stock-based compensation, increased
from $5.1 million in 2004 to $5.5 million in 2005. The increase in G&A expense
in 2005 was primarily due to higher performance bonuses in 2005 as compared to
2004. Our G&A expense on a per Mcfe basis increased from $0.89 in 2004 to $0.90
in 2005. The increase in the per Mcfe cost was due to increased expense in 2005
as compared to 2004.
Stock-based Compensation. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment." SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
those awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. In December 2005, we elected early adoption
of SFAS 123R .
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method or a "modified retrospective" method. Under the
"modified prospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. Under the "modified retrospective" method, the requirements
are the same as under the "modified prospective" method, but also permits
entities to restate financial statements of previous periods based on proforma
disclosures made in accordance with SFAS 123. We elected to use the "modified
retrospective" method, and have accordingly restated prior year financial
statements to reflect this method.
As a result of the retrospective adoption of SFAS 123R, the expenses
previously recognized under the rules of variable accounting were reversed and a
compensation expense measured according to SFAS 123R was recorded. As a result,
we recognized stock-based compensation of $247,000 during 2005 as a result of
the adoption of this accounting change compared to $112,000 in 2004, as
restated.
We currently utilize a standard option pricing model (i.e., Black-Scholes)
to measure the fair value of stock options granted to employees. While SFAS 123R
permits entities to continue to use such a model, the standard also permits the
use of a more complex binomial, or "lattice" model. Based upon research done by
us on the alternative models available to value option grants, and in
conjunction with the type and number of stock options expected to be issued in
the future, we have determined that we will continue to use the Black-Scholes
model for option valuation.
DD&A Expense. DD&A expense increased from $7.2 million in 2004 to $8.9
million in 2005. The increase in DD&A was primarily due to increased production
volumes in 2005 and increased capital expenditures in 2005 as compared to 2004.
Our DD&A expense on a per Mcfe basis for 2005 was $1.46 per Mcfe as compared to
$1.25 per Mcfe in 2004.
Interest Expense. Interest expense decreased from $17.9 million to $14.0
million for 2005 compared to 2004. The decrease in interest expense was due to
decreased debt levels during 2005. While the outstanding debt at December 31,
33
2005 was slightly higher than the balance as December 31, 2004, the level of
debt during the course of 2004, prior to the financial restructuring that
occurred in October 2004, was significantly higher. In addition, during most of
2004, interest on our then outstanding secured notes was payable by the issuance
of additional notes, which caused our cash interest expense in 2004 to be $7.6
million. With the issuance of the notes in October 2004, interest became payable
in cash, which led to all of the interest paid in 2005 being paid in cash.
Financing Costs. Financing costs in 2004 were $1.7 million compared to zero
in 2005. Financing costs represent costs related to refinancing activities,
which do not qualify for amortization over the life of the debt. The 2004 costs
relate to the refinancing activities during 2004. We did not undertake any
activities in 2005 which would have given rise to financing costs.
Income from discontinued operations. Income from discontinued operations
was $12.8 million in 2005 compared to $3.3 million in 2004. On February 28,
2005, Grey Wolf Exploration Inc. completed an IPO resulting in Abraxas
substantially divesting itself of its investment in Grey Wolf. The operations of
Grey Wolf, previously reported as a business segment, are reported as
discontinued operations for all periods presented in the accompanying financial
statements and the operating results are reflected separately from the results
of continuing operations.
Income from discontinued operations for the period ended December 31, 2005
includes a gain on the disposal of Grey Wolf of $17.3 million, net of non-cash
income tax of $6.1 million, and a loss from operations, including debt
retirement costs, of $4.4 million. Income from discontinued operations for the
year ended December 31, 2004 represents the operating results of Grey Wolf for
the year then ended.
Liquidity and Capital Resources
General. The natural gas and crude oil industry is a highly capital
intensive and cyclical business. Our capital requirements are driven principally
by our obligations to service debt and to fund the following costs:
o the development of existing properties, including drilling and
completion costs of wells;
o acquisition of interests in additional natural gas and crude
oil properties; and
o production and transportation facilities.
The amount of capital expenditures we are able to make has a direct impact
on our ability to increase cash flow from operations and, thereby, will directly
affect our ability to service our debt obligations and to continue to grow the
business through the development of existing properties and the acquisition of
new properties.
Our sources of capital going forward will primarily be cash from operating
activities, funding under our revolving credit facility, and if an appropriate
opportunity presents itself, proceeds from the sale of properties. We may also
seek equity capital although we may not be able to complete any equity
financings on terms acceptable to us, if at all. In addition, under the terms of
the notes, proceeds of optional sales of our assets that are not timely
reinvested in new natural gas and crude oil assets will be required to be used
to reduce indebtedness and proceeds of mandatory sales must be used to repay or
redeem indebtedness.
Working Capital (Deficit). At December 31, 2006 our current liabilities of
approximately $10.5 million exceeded our current assets of $6.8 million
resulting in a working capital deficit of $3.7 million. This compares to a
working capital deficit of $4.9 million as of December 31, 2005. Current
liabilities as of December 31, 2006 consisted of trade payables of $5.3 million,
revenues due third parties $2.6 million, accrued interest of $1.4 million and
other accrued liabilities of $ 1.2 million.
Capital Expenditures. Capital expenditures related to our continuing
operations in 2006, 2005 and 2004 were $26.3 million, $35.4 million and $9.3
million, respectively. The table below sets forth the components of these
capital expenditures for the three years ended December 31, 2006.
34
Year Ended December 31
------------------------------------------------------------
2006 2005 2004
------------------- -------------------- ------------------
(dollars in thousands)
Expenditure category:
Exploration/Development $ 26,117 $ 34,991 $ 9,088
Facilities and other 229 359 181
------------------- -------------------- ------------------
Total $ 26,346 $ 35,350 $ 9,269
=================== ==================== ==================
During 2006, 2005 and 2004, capital expenditures were primarily for the
development of existing properties. We anticipate making capital expenditures
for 2007 ranging from $27 to $44 million which will be used primarily for the
development of our current properties. These anticipated expenditures are
subject to adequate cash flow from operations and availability under our
revolving credit facility. If these sources of funding do not prove to be
sufficient, we may also issue additional shares of equity securities although we
may not be able to complete equity financings on terms acceptable to us, if at
all. Our ability to make all of our budgeted capital expenditures will also be
subject to availability of drilling rigs and other field equipment and services.
Our capital expenditures could also include expenditures for acquisition of
producing properties if such opportunities arise, but we currently have no
agreements, arrangements or undertakings regarding any material acquisitions. We
have no material long-term capital commitments and are consequently able to
adjust the level of our expenditures as circumstances dictate. Additionally, the
level of capital expenditures will vary during future periods depending on
market conditions and other related economic factors. Should the prices of
natural gas and crude oil continue to decline and if our costs of operations
continue to increase as a result of the scarcity of drilling rigs or if our
production volumes decrease, our cash flows will decrease which may result in a
reduction of the capital expenditures budget. If we decrease our capital
expenditures budget, we may not be able to offset natural gas and crude oil
production volumes decreases caused by natural field declines and sales of
producing properties, if any.
Sources of Capital. The net funds provided by and/or used in each of the
operating, investing and financing activities, related to continuing operations,
are summarized in the following table and discussed in further detail below:
Year Ended December 31,
-----------------------------------------------
2006 2005 2004
---- ---- ----
(dollars in thousands)
Net cash provided by operating activities $ 15,561 $ 21,099 $ 27,000
Net cash used in investing activities (14,102) (35,350) (9,269)
Net cash (used in) provided by financing activities (1,458) 14,877 (65,684)
------------- ----------- -------------
Total $ 1 $ 626 $ (47,953)
============= =========== =============
Operating activities for the year ended December 31, 2006 provided us with
$15.5 million of cash. Expenditures in 2006 of approximately $26.3 were
primarily for the development of natural gas and crude oil properties offset by
proceeds from the sale of oil and gas properties of $12.2 million. Financing
activities used $1.4 million during 2006, of which $20.4 million was provided
from long-term borrowing offset by $22.4 million of payments on long-term debt.
Operating activities for the year ended December 31, 2005 provided us with
$21.1 million of cash. Expenditures in 2005 of approximately $35.4 were
primarily for the development of natural gas and crude oil properties. Financing
activities provided $14.9 million during 2005, of which $11.3 million was
provided by a private placement of common stock, $28.4 million was provided from
long-term borrowing offset by $25.3 million of payments on long-term debt.
Operating activities for the year ended December 31, 2004 provided us with
$27.0 million of cash. Investing activities used $9.3 million during 2004
primarily for the development of natural gas and crude oil properties. Financing
activities used $65.7 million during 2004, primarily for payments on long-term
debt and deferred financing fees
35
Future Capital Resources. We currently have three principal sources of
liquidity going forward: (i) cash from operating activities, (ii) funding under
our revolving credit facility, and (iii) if an appropriate opportunity presents
itself, the sale of producing properties. If these sources of liquidity do not
prove to be sufficient, we may also issue additional shares of equity securities
although we may not be able to complete equity financings on terms acceptable to
us, if at all. Covenants under the indenture for the notes and the revolving
credit facility restrict our use of cash from operating activities, cash on hand
and any proceeds from asset sales. Under the terms of the notes, proceeds of
optional sales of our assets that are not timely reinvested in new natural gas
and crude oil assets will be required to be used to reduce indebtedness and
proceeds of mandatory sales must be used to redeem indebtedness. The terms of
the notes and the revolving credit facility also substantially restrict our
ability to:
o incur additional indebtedness;
o grant liens;
o pay dividends or make certain other restricted payments;
o merge or consolidate with any other entity; or
o sell, assign, transfer, lease, convey or otherwise dispose of all
or substantially all of our assets.
Our cash flow from operations depends heavily on the prevailing prices
of natural gas and crude oil and our production volumes of natural gas and crude
oil. Although we have hedged a portion of our natural gas and crude oil
production and will continue this practice as required pursuant to the revolving
credit facility, future natural gas and crude oil price declines would have a
material adverse effect on our overall results, and therefore, our liquidity.
Falling natural gas and crude oil prices could also negatively affect our
ability to raise capital on terms favorable to us or at all.
Our cash flow from operations will also depend upon the volume of natural
gas and crude oil that we produce. Unless we otherwise expand reserves, our
production volumes may decline as reserves are produced. Due to sales of
properties in 2002 and 2003, the divestiture of Grey Wolf during the first
quarter of 2005, property sales in 2006 and restrictions on capital expenditures
under the terms of our 11 1/2% secured notes due 2007 (which were refinanced in
October 2004), we now have significantly reduced reserves and production as
compared with pre-2003 levels. In the future, if an appropriate opportunity
presents itself, we may sell additional properties, which could further reduce
our production volumes. To offset the loss in production volumes resulting from
natural field declines and sales of producing properties, we must conduct
successful, exploration and development activities, acquire additional producing
properties or identify additional behind-pipe zones or secondary recovery
reserves. We believe our numerous drilling opportunities will allow us to
increase our production volumes; however, our drilling activities are subject to
numerous risks, including the risk that no commercially productive natural gas
or crude oil reservoirs will be found. . While we have had some success in
pursuing these activities, we have not been able to fully replace the production
volumes lost from natural field declines and property sales. For example, during
2006, our proved reserves declined by 2.1 Bcfe. Property sales of 1.8 Bcfe and
7.7 Bcfe of production further reduced our proved reserves. If our proved
reserves continue to decline in the future, our production will also decline
and, consequently our cash flow from operations and the amount that we are able
to borrow under our revolving credit facility will also decline. The risk of not
finding commercially productive reservoirs will be compounded by the fact that
45% of our total estimated proved reserves at December 31, 2006 were
undeveloped. During 2006, we expended approximately $26.1 million for wells in
south Texas, west Texas and Wyoming. These activities did not result in
significant new production or reserves. In west Texas we are currently
completing two wells in the Bell and Cherry Canyon Sands. In the Oates SW Field
of Pecos County, Texas, we have a well that is currently awaiting a drilling rig
to drill the horizontal lateral in the Devonian formation. We continue to
perform general well maintenance and work-overs utilizing our own work-over
rigs. In addition, approximately 29% of our production for the year ended
December 31, 2006 was from a single well in west Texas. If production from this
well decreases, the volume of our production would also decrease which, in turn,
would likely cash flow from operations to decrease.
Contractual Obligations. We are committed to making cash payments in
the future on the following types of agreements:
o Long-term debt
36
o Operating leases for office facilities
We have no off-balance sheet debt or unrecorded obligations and we have not
guaranteed the debt of any other party. Below is a schedule of the future
payments that we are obligated to make based on agreements in place as of
December 31, 2006.
Payments due in:
------------------------------------------------------------------------
Contractual Obligations (dollars
in thousands) Total 2007 2008-2009 2010-2011 Thereafter
-----------------------------------------------------------------------------------------------------------
Long-Term Debt (1) $ 127,614 $ - $ 127,614 $ - $ -
Interest on long-term debt (2) 47,292 16,304 30,988 - -
Operating Leases (3) 534 259 275 - -
--------------- ------------- ------------- -------------- -------------
Total $ 175,440 $ 16,563 $ 158,877 $ - $ -
=============== ============= ============= ============== =============
-----------------
(1) These amounts represent the balances outstanding under the revolving
credit facility and the notes. These repayments assume that we will not
draw down additional funds.
(2) Interest expense assumes the balances of long-term debt at the end of
the period and current effective interest rates.
(3) Office lease obligations. The lease for office space expires in January
2009.
We maintain a reserve for cost associated with the retirement of tangible
long-lived assets. At December 31, 2006 our reserve for these obligations
totaled $1.0 million for which no contractual commitment exist. For additional
information relating to this obligation, see Note 1 of Notes to Consolidated
Financial Statements.
Off-Balance Sheet Arrangements. At December 31, 2006, we had no existing
off-balance sheet arrangements, as defined under SEC regulations, that have or
are reasonably likely to have a current or future effect on our financial
condition, revenues or expenses, results of operations, liquidity, capital
expenditures or capital resources that is material to investors.
Contingencies. From time to time, we are involved in litigation relating to
claims arising out of our operations in the normal course of business. At
December 31, 2006 we were not engaged in any legal proceedings that are
expected, individually or in the aggregate, to have a material adverse effect on
the Company.
Other obligations. We make and will continue to make substantial capital
expenditures for the acquisition, exploration, development and production of
crude oil and natural gas. In the past, we have funded our operations and
capital expenditures primarily through cash flow from operations, sales of
properties, sales of production payments and borrowings under our bank credit
facilities and other sources. Given our high degree of operating control, the
timing and incurrence of operating and capital expenditures is largely within
our discretion.
Long-Term Indebtdness
The following table sets forth our long-term indebtedness as of December
31, 2006 and 2005.
Long Term Indebtedness
December 31
---------------------------------
2006 2005
----------------- ---------------
(in thousands)
Floating rate senior secured notes due 2009.. $ 125,000 $ 125,000
Senior secured revolving credit facility..... 2,614 4,527
----------------- ---------------
127,614 129,527
Less current maturities ..................... - -
----------------- ---------------
$ 127,614 $ 129,527
================= ===============
37
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in aggregate principal
amount of Floating Rate Senior Secured Notes due 2009. The notes will mature on
December 1, 2009 and began accruing interest from the date of issuance, October
28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The current
interest rate is 12.85% per annum. The interest rate is reset semi-annually on
each June 1 and December 1. Interest is payable semi-annually in arrears on June
1 and December 1 of each year.
The notes rank equally among themselves and with all of our unsubordinated
and secured indebtedness, including our credit facility and senior in right of
payment to our existing and future subordinated indebtedness.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest on the notes on a senior secured basis. In addition, any
other subsidiary or affiliate of ours, that in the future guarantees any other
indebtedness with us, or our restricted subsidiaries, will also be required to
guarantee the notes.
The notes and the Subsidiary Guarantors' guarantees thereof, together with
our revolving credit facility and the Subsidiary Guarantors' guarantees thereof,
are secured by shared first priority perfected security interests, subject to
certain permitted encumbrances, in all of our and each of our restricted
subsidiaries' material property and assets, including substantially all of our
and their natural gas and crude oil properties and all of the capital stock (or
in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
The notes may be redeemed, at our election, as a whole or from time to time
in part, at any time after April 28, 2007, upon not less than 30 nor more than
60 days notice to each holder of notes to be redeemed, subject to the conditions
and at the redemption prices (expressed as percentages of principal amount) set
forth below, together with accrued and unpaid interest and Liquidating Damages(
as defined in the indenture) if any, to the applicable redemption date.
Year Percentage
-------------------------------------------------------------------
From April 29, 2007 to April 28, 2008 104.00%
From April 29, 2008 to April 28, 2009 102.00%
After April 28, 2009 100.00%
Prior to April 28, 2007, we may redeem up to 35% of the aggregate original
principal amount of the notes using the net proceeds of one or more equity
offerings, in each case at the redemption price equal to the product of (i) the
principal amount of the notes being so redeemed and (ii) a redemption price
factor of 1.00 plus the per annum interest rate on the notes (expressed as a
decimal) on the applicable redemption date plus accrued and unpaid interest to
the applicable redemption date, provided certain conditions are also met.
If we experience specific kinds of change of control events, each holder of
notes may require us to repurchase all or any portion of such holder's notes at
a purchase price equal to 101% of the principal amount of the notes, plus
accrued and unpaid interest to the date of repurchase.
The indenture governing the notes contains covenants that, among other
things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain
types of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
38
o pay dividends or make other distributions on capital stock or
make other restricted payments, including repurchasing,
redeeming or retiring capital stock or subordinated debt or
making certain investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its capital
stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including nonpayment of
principal or interest, violations of covenants, cross default and cross
acceleration to certain other indebtedness, including our revolving credit
facility, bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we entered
into an agreement for a revolving credit facility having a maximum commitment of
$15 million, which includes a $2.5 million subfacility for letters of credit.
Availability under the revolving credit facility is subject to a borrowing base
consistent with normal and customary natural gas and crude oil lending
transactions.
Outstanding amounts under the revolving credit facility bear interest at
the prime rate announced by Wells Fargo Bank, National Association plus 1.00%.
The current interest rate is 9.25% per annum. Subject to earlier
termination rights and events of default, the stated maturity date under the
revolving credit facility is October 28, 2008.
We are permitted to terminate the revolving credit facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders' aggregate commitment under the revolving credit facility. Such
termination and each such reduction is subject to a premium equal to the
percentage listed below multiplied by the lenders' aggregate commitment under
the revolving credit facility, or, in the case of partial reduction, the amount
of such reduction.
Year % Premium
-------------- --------------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of our restricted subsidiaries will be required to guarantee our obligations
under the revolving credit facility. Obligations under the revolving credit
facility are secured, together with the notes, by a shared first priority
perfected security interest, subject to certain permitted encumbrances, in all
of our and each of our restricted subsidiaries' material property and assets,
including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
Under the revolving credit facility, we are subject to customary covenants,
including certain financial covenants and reporting requirements. The revolving
credit facility requires us to maintain a minimum net cash interest coverage
ratio and also requires us to enter into hedging agreements on not less than 25%
or more than 75% of our projected natural gas and crude oil production.
39
In addition to the foregoing and other customary covenants, the revolving
credit facility contains a number of covenants that, among other things,
restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain types of
preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital stock; and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
The revolving credit facility also contains customary events of default,
including nonpayment of principal or interest, violations of covenants, cross
default and cross acceleration to certain other indebtedness, bankruptcy and
material judgments and liabilities, and is subject to an Intercreditor, Security
and Collateral Agency Agreement, which specifies the rights of the parties
thereto to the proceeds from the Collateral.
Intercreditor Agreement. The holders of the notes, together with the
lenders under our credit facility, are subject to an Intercreditor, Security and
Collateral Agency Agreement, which specifies the rights of the parties thereto
to the proceeds from the Collateral. The Intercreditor Agreement, among other
things, (i) creates security interests in the Collateral in favor of a
collateral agent for the benefit of the holders of the notes and the credit
facility lenders and (ii) governs the priority of payments among such parties
upon notice of an event of default under the Indenture or the credit facility.
So long as no such event of default exists, the collateral agent will not
collect payments under the new credit facility documents or the indenture
governing the notes and other note documents (collectively, the "Secured
Documents"), and all payments will be made directly to the respective creditor
under the applicable Secured Document. Upon notice of an event of default and
for so long as an event of default exists, payments to each credit facility
lender and holder of the notes from us and our current subsidiaries and proceeds
from any disposition of any collateral, will, subject to limited exceptions, be
collected by the collateral agent for deposit into a collateral account and then
distributed as provided in the following paragraph.
Upon notice of any such event of default and so long as an event of default
exists, funds in the collateral account will be distributed by the collateral
agent generally in the following order of priority:
first, to reimburse the collateral agent for expenses incurred in
protecting and realizing upon the value of the Collateral;
second, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was acting on behalf
of the Control Party (as defined below);
40
third, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was not acting on
behalf of the Control Party;
fourth, to pay all accrued and unpaid interest (and then any unpaid
commitment fees) under the credit facility;
fifth, if, the collateral coverage value of three times the outstanding
obligations under the credit facility would be met after giving effect to any
payment under this clause "fifth," to pay all accrued and unpaid interest on the
notes;
sixth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any fees, expenses, premiums and
reimbursement obligations) the credit facility;
seventh, to pay all accrued and unpaid interest on the notes (if not
paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any premium with respect to) the notes;
and
ninth, to pay each credit facility lender, holder of the notes, and
other secured party, on a pro rata basis, all other amounts outstanding under
the credit facility and the notes.
To the extent there exists any excess monies or property in the collateral
account after all of ours and our subsidiaries' obligations under the credit
facility, the indenture and the notes are paid in full, the collateral agent
will be required to return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party" which for purposes of the
Intercreditor Agreement is the holders of the notes and the credit facility
lenders, acting as a single class, by vote of the holders of a majority of the
aggregate principal amount of outstanding obligations under the notes and the
credit facility.
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the credit facility administrative agent certifying that the proposed
sale or other disposition of assets is either permitted or required by, and is
in accordance with the provisions of, the applicable Secured Documents and (iii)
the collateral agent has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
Hedging Activities
Our results of operations are significantly affected by fluctuations in
commodity prices and we seek to reduce our exposure to price volatility by
hedging our production through swaps, options and other commodity derivative
instruments. Under our revolving credit facility, we are required to maintain
hedge positions on not less than 25% or more than 75% of our projected oil and
gas production for a six month rolling period. See "--Quantitative and
Qualitative Disclosures about Market Risk--Hedging Sensitivity" for further
information.
Net Operating Loss Carryforwards
At December 31, 2006, we had, subject to the limitation discussed below,
$192.7 million of net operating loss carryforwards for U.S. tax purposes. These
loss carryforwards will expire through 2026 if not utilized.
41
Uncertainties exist as to the future utilization of the operating loss
carryforwards under the criteria set forth under FASB Statement No. 109.
Therefore, we have established a valuation allowance of $66.9 million for
deferred tax assets at December 31, 2006 and 2005.
Related Party Transactions
Abraxas has adopted a policy that transactions between Abraxas and its
officers, directors, principal stockholders, or affiliates of any of them, will
be on terms no less favorable to Abraxas than can be obtained on an arm's length
basis in transactions with third parties and must be approved by the vote of at
least a majority of the disinterested directors.
Critical Accounting Policies
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for natural gas and crude oil activities.
SEC Regulation S-X defines the financial accounting and reporting standards for
companies engaged in natural gas and crude oil activities. Two methods are
prescribed: the successful efforts method and the full cost method. We have
chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. We also
capitalize internal costs that can be directly identified with our acquisition,
exploration and development activities and do not include any costs related to
production, general corporate overhead or similar activities. Under the
successful efforts method, geological and geophysical costs and costs of
carrying and retaining undeveloped properties are charged to expense as
incurred. Costs of drilling exploratory wells that do not result in proved
reserves are charged to expense. Depreciation, depletion, amortization and
impairment of natural gas and crude oil properties are generally calculated on a
well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of natural gas
and crude oil properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher depreciation, depletion and amortization rate on our
natural gas and crude oil properties.
At the time it was adopted, management believed that the full cost method
would be preferable, as earnings tend to be less volatile than under the
successful efforts method. However, the full cost method makes us susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. We have experienced this
situation several times over the years, most recently in 2002. Our natural gas
and crude oil reserves have a relatively long life. However, temporary drops in
commodity prices can have a material impact on our business including impact
from the full cost method of accounting.
Under full cost accounting rules, the net capitalized cost of natural gas
and crude oil properties may not exceed a "ceiling limit" which is based upon
the present value of estimated future net cash flows from proved reserves on a
pool by pool basis, discounted at 10%, plus the lower of cost or fair market
value of unproved properties and the cost of properties not being amortized,
less income taxes. If net capitalized costs of natural gas and crude oil
properties exceed the ceiling limit, we must charge the amount of the excess to
earnings. This is called a "ceiling limitation write-down." This charge does not
impact cash flow from operating activities, but does reduce our stockholders'
equity and reported earnings. The risk that we will be required to write down
the carrying value of natural gas and crude oil properties increases when
natural gas and crude oil prices are depressed or volatile. In addition,
write-downs may occur if we experience substantial downward adjustments to our
estimated proved reserves or if purchasers cancel long-term contracts for our
natural gas production. An expense recorded in one period may not be reversed in
a subsequent period even though higher natural gas and crude oil prices may have
increased the ceiling applicable to the subsequent period. We apply the full
cost ceiling test on a quarterly basis on the date of the latest balance sheet
presented.
42
Estimates of Proved Natural Gas and Crude Oil Reserves. Estimates of
our proved reserves included in this report are prepared in accordance with GAAP
and SEC guidelines. The accuracy of a reserve estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
Our proved reserve information included in this report was based on
evaluations prepared by independent petroleum engineers. Estimates prepared by
other third parties may be higher or lower than those included herein. Because
these estimates depend on many assumptions, all of which may substantially
differ from future actual results, reserve estimates will be different from the
quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify
material revisions to the estimate.
You should not assume that the present value of future net cash flows is
the current market value of our estimated proved reserves. In accordance with
SEC requirements, we based the estimated discounted future net cash flows from
proved reserves on prices and costs on the date of the estimate. Actual future
prices and costs may be materially higher or lower than the prices and costs as
of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A expense
will increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher cost
fields.
Asset Retirement Obligations. The estimated costs of restoration and
removal of facilities are accrued. The fair value of a liability for an asset's
retirement obligation is recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense.
Hedge Accounting. From time to time, we use commodity price hedges to limit
our exposure to fluctuations in natural gas and crude oil prices. Results of
those hedging transactions are reflected in natural gas and crude oil sales.
Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting
for Derivative Instruments and Hedging Activities", was effective for us on
January 1, 2001. SFAS 133, as amended and interpreted, establishes accounting
and reporting standards for derivative instruments, including certain derivative
instruments embedded in other contracts, and for hedging activities. In 2003 we
elected out of hedge accounting as prescribed by SFAS 133. Accordingly all
derivatives, whether designated in hedging relationships or not, are required to
be recorded at fair value on our balance sheet. Changes in fair value of
contracts are recognized in earnings in the current period.
Due to the volatility of natural gas and crude oil prices and, to a lesser
extent, interest rates, our financial condition and results of operations can be
significantly impacted by changes in the market value of our derivative
instruments. As of December 31, 2006 and 2005 the net market value of our
derivatives was an asset of $157,286 and $75,817 respectively.
Share-Based Payments. In December 2004, the FASB issued SFAS No. 123R,
"Share-Based Payment." SFAS No. 123R is a revision of SFAS No. 123, "Accounting
for Stock Based Compensation", and supersedes APB 25. Among other items, SFAS
123R eliminates the use of APB 25 and the intrinsic value method of accounting,
and requires companies to recognize the cost of employee services received in
exchange for awards of equity instruments, based on the grant date fair value of
43
those awards, in the financial statements. Pro forma disclosure is no longer an
alternative under the new standard. The Company has elected early adoption of
SFAS 123R .
SFAS 123R permits companies to adopt its requirements using either a
"modified prospective" method, or a "modified retrospective" method. The Company
has elected to use the "modified retrospective" method. Under the "modified
retrospective" method, compensation cost is recognized in the financial
statements beginning with the effective date, based on the requirements of SFAS
123R for all share-based payments granted after that date, and based on the
requirements of SFAS 123 for all unvested awards granted prior to the effective
date of SFAS 123R. The "modified retrospective " method also permit entities to
restate financial statements of previous periods based on proforma disclosures
made in accordance with SFAS 123. This standard requires the cost of all
share-based payments, including stock options, to be measured at fair value on
the grant date and recognized in the statement of operations. In accordance with
this standard, all periods prior to January 1, 2005 were restated to reflect the
impact of the standard as if it had been adopted on January 1, 1995, the
original effective date of SFAS No. 123, "Accounting for Stock-Based
Compensation." Also in accordance with the standard, the amounts that are
reported in the statement of operations for the restated periods are the pro
forma amounts previously disclosed under SFAS No. 123.
The Company currently utilizes a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by the Company on the alternative models available to value option
grants, and in conjunction with the type and number of stock options expected to
be issued in the future, the Company has determined that it will continue to use
the Black-Scholes model for option valuation as of the current time. SFAS 123R
includes several modifications to the way that income taxes are recorded in the
financial statements. The expense for certain types of option grants is only
deductible for tax purposes at the time that the taxable event takes place,
which could cause variability in the Company's effective tax rates recorded
throughout the year. SFAS 123R does not allow companies to "predict" when these
taxable events will take place. Furthermore, it requires that the benefits
associated with the tax deductions in excess of recognized compensation cost be
reported as a financing cash flow, rather than as an operating cash flow as
required under current literature. This requirement will reduce net operating
cash flows and increase net financing cash flows in periods after the effective
date. These future amounts cannot be estimated, because they depend on, among
other things, when employees exercise stock options.
New Accounting Pronouncements
In June 2006, the Financial Accounting Standards Board (FASB) issued FIN
48, "Accounting for Uncertainty in Income Taxes, an interpretation of FASB
Statement No. 109." FIN 48 requires an entity to evaluate its tax positions
following a two-step process. The first step requires an entity to determine
whether it is more-likely-than-not that a tax position will be sustained based
on the technical merits of the position. The second step requires an entity to
recognize in the financial statements each tax position that meets the
more-likely-than-not criterion. Each recognized tax position should be measured
at the largest amount of benefit that has a greater than 50 percent likelihood
of being realized. FIN 48 also provides guidance on derecognition,
classification, interest and penalties, accounting in interim periods,
disclosure and transition.
FIN 48 is effective for fiscal years beginning after December 15, 2006. The
impact of initially applying FIN 48 is required to be recognized as a cumulative
effect adjustment to the opening balance of retained earnings for that fiscal
year. The Company is currently evaluating the impact of applying this guidance
if any.
In September 2006, the FASB issued Statement of Financial Accounting
Standards No. 157, "Fair Value Measurements" ("SFAS No. 157"). This standard
clarifies the principle that fair value should be based on the assumptions that
market participants would use when pricing an asset or liability. Additionally,
it establishes a fair value hierarchy that prioritizes the information used to
develop those assumptions. We have not yet determined the impact that the
implementation of SFAS No. 157 will have on our results of operations or
financial condition if any. SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108,
Considering the Effects of Prior Year Misstatements when quantifying
44
Misstatements in Current Year Financial Statements ("SAB 108"). SAB 108 requires
companies to evaluate the materiality of identified unadjusted errors on each
financial statement and related financial statement disclosure using both the
rollover approach and the iron curtain approach, as those terms are defined in
SAB 108. The rollover approach quantifies misstatements based on the amount of
the error in the current year financial statement, whereas the iron curtain
approach quantifies misstatements based on the effects of correcting the
misstatement existing in the balance sheet at the end of the current year,
irrespective of the misstatement's year(s) of origin. Financial statements would
require adjustment when either approach results in quantifying a misstatement
that is material. Correcting prior year financial statements for immaterial
errors would not require previously filed reports to be amended. If a Company
determines that an adjustment to prior year financial statements is required
upon adoption of SAB 108 and does not elect to restate its previous financial
statements, then it must recognize the cumulative effect of applying SAB 108 in
fiscal 2006 beginning balances of the affected assets and liabilities with a
corresponding adjustment to the fiscal 2006 opening balance in retained
earnings. SAB 108 is effective for interim periods of the first fiscal year
ending after November 15, 2006 and was adopted by the company effective October
1, 2006. The adoption of SAB 108 did not have a material impact on the Company's
consolidated financial statements.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price Risk
As an independent natural gas and crude oil producer, our revenue, cash
flow from operations, other income and equity earnings and profitability,
reserve values, access to capital and future rate of growth are substantially
dependent upon the prevailing prices of crude oil, natural gas and natural gas
liquids. Declines in commodity prices will adversely affect our financial
condition, liquidity, ability to obtain financing and operating results. Lower
commodity prices may reduce the amount of natural gas and crude oil that we can
produce economically. Prevailing prices for such commodities are subject to wide
fluctuation in response to relatively minor changes in supply and demand and a
variety of additional factors beyond our control, such as global political and
economic conditions. Historically, prices received for natural gas and crude oil
production have been volatile and unpredictable, and such volatility is expected
to continue. Most of our production is sold at market prices. Generally, if the
commodity indexes fall, the price that we receive for our production will also
decline. Therefore, the amount of revenue that we realize is partially
determined by factors beyond our control. Assuming the production levels we
attained during the year ended December 31, 2006, a 10% decline in natural gas
and crude oil, prices would have reduced our operating revenue and cash flow by
approximately $5.1 million for the year.
Hedging Sensitivity
On January 1, 2001, we adopted SFAS 133 as amended by SFAS 137 and SFAS
138. Under SFAS 133, all derivative instruments are recorded on the balance
sheet at fair value. In 2003 we elected not to designate derivative instruments
as hedges. Accordingly the instruments are recorded on the balance sheet at fair
value with changes in the market value of the derivatives being recorded in
current oil and gas revenue.
Under the terms of our revolving credit facility, we are required to
maintain hedging positions with respect to not less than 25% nor more than 75%
of our natural gas and crude oil production for a rolling six month period.
All hedge transactions are subject to our risk management policy, which has
been approved by the Board of Directors.
We currently have the following hedges in place:
Time Period Notional Quantities Price
---------------------------------- -------------------------------------------- ----------------------
April 2007 10,000 MMbtu of production per day Floor of $ 4.50
May 2007 10,000 MMbtu of production per day Floor of $ 5.00
June 2007 10,000 MMbtu of production per day Floor of $ 5.00
July 2007 10,000 MMbtu of production per day Floor of $ 4.25
45
August 2007 10,000 MMbtu of production per day Floor of $ 5.00
September 2007 10,000 MMbtu of production per day Floor of $ 5.50
At December 31, 2006 the aggregate fair market value of our hedges was
approximately $157,286.
Interest rate risk
At December 31, 2006 we had $125.0 million in outstanding indebtedness
under the floating rate senior secured notes due 2009. The notes bear interest
at a per annum rate of six-month LIBOR plus 7.5%. The rate is redetermined on
June 1 and December 1 of each year, beginning June 1, 2005. The current rate on
the notes is 12.85%. For every percentage point that the LIBOR rate rises, our
interest expense would increase by approximately $1.3 million on an annual
basis. At December 31, 2006, we had $2.6 million outstanding indebtedness under
our revolving credit facility. Interest on this facility accrues at the prime
rate announced by Wells Fargo Bank plus 1.00%. For every percentage point
increase in the announced prime rate, our interest expense would increase by
approximately $26,000 on an annual basis.
Item 8. Financial Statements and Supplementary Data
For the financial statements and supplementary data required by this Item
8, see the Index to Consolidated Financial Statements.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures. We maintain disclosure controls and
procedures designed to ensure that information required to be disclosed in
reports filed or submitted by it under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods specified
in the Securities and Exchange Commission rules and forms. As of December 31,
2006, we carried out an evaluation, under the supervision and with the
participation of management, including our Chief Executive Officer and Chief
Financial Officer of the effectiveness of the design and operation of our
disclosure controls and procedures pursuant to Securities Exchange Act Rule
13a-15(b). Based upon that evaluation, our Chief Executive Officer and Chief
Financial Officer concluded that our disclosure controls and procedures are
effective as of December 31, 2006, to ensure that information required to be
disclosed by us in reports that we file under the Securities Exchange Act of
1934 is accumulated and communicated to management, including our Chief
Executive Officer and Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure.
Management's Annual Report on Internal Control over Financial Reporting and
Attestation Report of Registered Public Accounting Firm. Pursuant to Section 404
of the Sarbanes-Oxley Act of 2002, we have included a report of management's
assessment of the design and effectiveness of our internal controls as part of
this Annual Report on Form 10-K for the fiscal year ended December 31, 2006. BDO
Seidman, LLP, our registered public accountants, also attested to, and reported
on, management's assessment of the effectiveness of internal control over
financial reporting. Management's report and the independent public accounting
firm's attestation report are included in our 2006 Financial Statements in Item
15 under the captions "Management's Report on Internal Control over Financial
Reporting" and "Report of Independent Registered Public Accounting Firm" and are
incorporated herein by reference.
Changes in Internal Control over Financial Reporting. As of the end of the
period covered by this report, we carried out an evaluation, under the
supervision and with the participation of our Chief Executive Officer and Chief
Financial Officer, of our internal control over financial reporting to determine
whether any changes occurred during the fourth quarter of 2006 that have
materially affected, or are reasonably likely to materially affect, our internal
control over financial reporting. Based on that evaluation, there were no
changes in our internal control over financial reporting or in other factors
that have materially affected or are reasonably likely to materially affect our
internal control over financial reporting
46
Item 9B. Other Information
None.
PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)1. Consolidated Financial Statements Page
Management's Report on Internal Control over Financial Reporting...........................F-2
Report of Independent Registered Public Accounting Firm....................................F-3
Report of Independent Registered Public Accounting Firm on Internal Control
Over Financial Reporting...............................................................F-4
Consolidated Balance Sheets at December 31, 2006 and 2005..................................F-5
Consolidated Statements of Operations for the years ended December 31, 2006
2005 and 2004............................................................................F-7
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2006, 2005 and 2004.........................................................F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2006,
2005 and 2004............................................................................F-9
Consolidated Statements of Other Comprehensive Income (loss) for the years ended
December 31, 2006, 2005 and 2004.........................................................F-11
Notes to Consolidated Financial Statements ................................................F-12
(a) 2. Financial Statement Schedules
All schedules have been omitted because they are not applicable, not
required under the instructions or the information requested is set forth in the
consolidated financial statements or related notes thereto.
(a)3.Exhibits
The following Exhibits have previously been filed by the Registrant or are
included following the Index to Exhibits.
Exhibit Number. Description
3.1 Articles of Incorporation of Abraxas. (Filed as Exhibit 3.1 to our
Registration Statement on Form S-4, No. 33-36565 (the "S-4 Registration
Statement")).
3.2 Articles of Amendment to the Articles of Incorporation of Abraxas dated
October 22, 1990. (Filed as Exhibit 3.3 to the S-4 Registration
Statement).
3.3 Articles of Amendment to the Articles of Incorporation of Abraxas dated
December 18, 1990. (Filed as Exhibit 3.4 to the S-4 Registration
Statement).
3.4 Articles of Amendment to the Articles of Incorporation of Abraxas dated
June 8, 1995. (Filed as Exhibit 3.4 to our Registration Statement on
Form S-3, No. 333-00398 (the "S-3 Registration Statement")).
47
3.5 Articles of Amendment to the Articles of Incorporation of Abraxas dated
as of August 12, 2000 (Filed as Exhibit 3.5 to our Annual Report of
Form 10-K filed April 2, 2001).
3.6 Amended and Restated Bylaws of Abraxas. (Filed as Exhibit 3.6 to
Abraxas' Annual Report on Form 10-K filed April 5, 2002).
4.1 Specimen Common Stock Certificate of Abraxas. (Filed as Exhibit 4.1 to
the S-4 Registration Statement).
4.2 Specimen Preferred Stock Certificate of Abraxas. (Filed as Exhibit 4.2
to our Annual Report on Form 10-K filed on March 31, 1995).
4.3 Indenture dated October 28, 2004, by and among Abraxas, as Issuer; the
Subsidiary Guarantors party thereto and U.S. Bank National Association,
as Trustee, relating to Abraxas' Floating Rate Senior Secured Notes Due
2009. (Filed as Exhibit 4.1 to Abraxas' Current Report on Form 8-K
filed on November 3, 2004).
4.4 Form of Rule 144A Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-1 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.5 Form of Regulation S Global Note for Floating Rate Senior Secured Notes
due 2009. (Filed as Exhibit A-2 to Exhibit 4.1 to Abraxas' Current
Report on Form 8-K filed on November 3, 2004).
4.6 Form of Accredited Investor Certificated Note for Floating Rate Senior
Secured Notes due 2009. (Filed as Exhibit A-3 to Exhibit 4.1 to
Abraxas' Current Report on Form 8-K filed on November 3, 2004).
*10.1 Abraxas Petroleum Corporation 401(k) Profit Sharing Plan. (Filed as
Exhibit 10.4 to Abraxas' Registration Statement on Form S-4, No.
333-18673, (the "1996 Exchange Offer Registration Statement")).
*10.2 Abraxas Petroleum Corporation Amended and Restated 1994 Long Term
Incentive Plan. (Filed as Exhibit 10.4 to Abraxas' Registration
Statement on Form S-4 filed on January 12, 2005).
*10.3 Abraxas Petroleum Corporation Incentive Performance Bonus Plan. (Filed
as Exhibit 10.24 to Abraxas' Annual Report on Form 10-K filed on April
12, 1994).
10.4 Form of Indemnity Agreement between Abraxas and each of its directors
and officers. (Filed herewith).
10.5 Loan Agreement dated as of October 28, 2004 by and among Abraxas
Petroleum Corporation, the Subsidiary Guarantors party thereto, Wells
Fargo Foothill, Inc., as Arranger and Administrative Agent and the
Lenders signatory thereto. (Filed as Exhibit 10.2 to Abraxas' Current
Report on Form 8-K filed November 3, 2004).
10.6 Employment Agreement between Abraxas and Robert L. G. Watson. (Filed as
Exhibit 10.19 to the 2000 S-1 Registration Statement).
*10.7 Employment Agreement between Abraxas and Chris E. Williford. (Filed as
Exhibit 10.20 to the 2000 S-1 Registration Statement).
*10.8 Employment Agreement between Abraxas and Stephen T. Wendel. (Filed as
Exhibit 10.26 to the S-3 Registration Statement).
*10.9 Employment Agreement between Abraxas and William H. Wallace. (Filed as
Exhibit 10.27 to the S-3 Registration Statement).
48
*10.10 Employment Agreement between Abraxas and Lee T. Billingsley. (Filed as
Exhibit 10.28 to the S-3 Registration Statement).
10.11 Intercreditor, Security and Collateral Agency Agreement dated as of
October 28, 2004 by and among Abraxas Petroleum Corporation, the
Subsidiary Guarantors party thereto, Wells Fargo Foothill, Inc.,
Guggenheim Corporate Funding, LLC and U.S. Bank National Association.
(Filed as Exhibit 10.5 to Abraxas' Current Report on Form 8-K filed
November 3, 2004).
*10.12 Abraxas Petroleum Corporation 2005 Non-Employee Directors Long-Term
Equity Incentive Plan. (Filed as Exhibit 10.1 to Abraxas' Current
Report on Form 8-K filed June 6, 2005).
*10.13 Form of Stock Option Agreement under the Abraxas Petroleum Corporation
2005 Non-Employee Directors Long-Term Equity Incentive Plan. (Filed as
Exhibit 10.2 to Abraxas' Current Report on Form 8-K filed June 6,
2005).
*10.14 Abraxas Petroleum Corporation Senior Management Incentive Bonus Plan
2006 (Filed as exhibit 10 to 2005 Form 10-K filed March 22, 2006).
10.15 Common Stock Purchase Agreement made and entered into as of the 20th
day of July, 2005, by and between Abraxas Petroleum Corporation and the
Purchasers signatory thereto. (Filed as Exhibit 10.1 to Abraxas'
Current Report on Form 8-K filed July 22, 2005).
10.16 Abraxas Petroleum Corporation 2005 Employee Long-Term Equity Incentive
Plan (Filed as Exhibit 10.2 to Abraxas' Current Report on Form 8-K
filed on May 26, 2006).
14.1 Abraxas Petroleum Corporation Code of Business Conduct and Ethics
((Filed as Exhibit 14.1 to Abraxas Annual Report on Form 10-K filed
March 22, 2006).
21.1 Subsidiaries of Abraxas. (Filed as Exhibit 21.1 to Abraxas, Grey Wolf
Exploration Inc., Sandia Oil & Gas Corporation, Sandia Operating Corp.,
Wamsutter Holdings, Inc., Western Associated Energy Corporation and
Eastside Coal Company, Inc.'s Registration Statement on Form S-1, No.
333-103027).
23.1 Consent of BDO Seidman, LLP (filed herewith)
23.2 Consent of DeGolyer and MacNaughton. (filed herewith).
31.1 Certification - Chief Executive Officer (filed herewith)
31.2 Certification - Chief Financial Officer (filed herewith)
32.1 Certification by Chief Executive Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
32.2 Certification by Chief Financial Officer pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of
2002 (filed herewith).
* Management Compensatory Plan or Agreement.
49
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
ABRAXAS PETROLEUM CORPORATION
By: /s/ Robert L.G. Watson By: /s/ Chris E. Williford
---------------------- --------------------------
President and Principal Exec. Vice President and
Executive Officer Principal Financial and
Accounting Officer
DATED: November 14, 2007
Pursuant to the requirements of the Securities and Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the date indicated.
Signature Name and Title Date
--------- -------------- ----
/s/ Robert L.G. Watson Chairman of the Board,
------------------------ President (Principal Executive
Robert L.G. Watson Officer) and Director November 14, 2007
/s/ Chris E. Williford Exec. Vice President and
---------------------- Treasurer (Principal Financial
Chris E. Williford and Accounting Officer) November 14, 2007
/s/ Craig S. Bartlett, Jr. Director November 14, 2007
--------------------------
Craig S. Bartlett, Jr.
/s/ Franklin A. Burke Director November 14, 2007
----------------------
Franklin A. Burke
/s/ Harold D. Carter Director November 14, 2007
----------------------
Harold D. Carter
/s/ Ralph F. Cox Director November 14, 2007
----------------------
Ralph F. Cox
/s/ Barry J. Galt Director November 14, 2007
------------------
Barry J. Galt
/s/ Dennis E. Logue Director November 14, 2007
----------------------
Dennis E Logue
/s/ Paul Powell Director November 14, 2007
----------------------
Paul Powell
50
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Abraxas Petroleum Corporation and Subsidiaries
Management's Report on Internal Control over Financial Reporting....................................F-2
Report of Independent Registered Public Accounting Firm.............................................F-3
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting.................................................................................F-4
Consolidated Balance Sheets at December 31, 2006 and 2005...........................................F-5
Consolidated Statements of Operations for the years ended December 31, 2006
2005 and 2004....................................................................................F-7
Consolidated Statements of Stockholders' Deficit for the years ended
December 31, 2006, 2005 and 2004.................................................................F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2006,
2005 and 2004....................................................................................F-9
Consolidated Statements of Other Comprehensive Income for the years ended
December 31, 2006, 2005 and 2004.................................................................F-11
Notes to Consolidated Financial Statements .........................................................F-12
All schedules are omitted because they are not required, are not applicable or
the information required is included in the Consolidated Financial Statements or
the notes thereto.
F-1
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The Board of Directors and Stockholders of
Abraxas Petroleum Corporation:
Management is responsible for establishing and maintaining adequate
internal control over financial reporting (as defined in Rules 13a-15(f) under
the Securities Exchange Act of 1934). Our internal control over financial
reporting is designed to provide reasonable assurance to management and board of
directors regarding the preparation and fair presentation of published financial
statements. Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Therefore, even those systems
determined to be effective can provide only reasonable assurance with respect to
financial statement preparation and presentation. Management assessed the
effectiveness of our internal control over financial reporting as of December
31, 2006. In making this assessment, management used the criteria set forth by
the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in
Internal Control - Integrated Framework. Based on our assessment, we believe
that, as of December 31, 2006, our internal control over financial reporting is
effective based on those criteria.
Management's assessment of the effectiveness of internal control over
financial reporting as of December 31, 2006 and 2005, has been audited by BDO
Seidman, LLP, an independent registered public accounting firm which also
audited our consolidated financial statements. BDO Seidman's attestation report
on management's assessment of our internal control over financial reporting is
included under the heading "Report of Independent Registered Public Accounting
Firm on Internal Control Over Financial Reporting."
By: /s/ Robert L.G. Watson By: /s/ Chris E. Williford
---------------------- ----------------------
Robert L.G. Watson Chris E. Williford
President and Chief Executive Officer Executive Vice President and
Chief Financial Officer
San Antonio, Texas
March 9, 2007
F-2
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Abraxas Petroleum Corporation
San Antonio, Texas
We have audited the accompanying consolidated balance sheets of Abraxas
Petroleum Corporation and subsidiaries as of December 31, 2006 and 2005 and the
related consolidated statements of operations, stockholders' deficit, cash flows
and other comprehensive income (loss) for each of the three years in the period
ended December 31, 2006. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements, assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Abraxas
Petroleum Corporation at December 31, 2006 and 2005, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2006, in conformity with accounting principles generally accepted
in the United States of America.
We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of Abraxas
Petroleum Corporation's internal control over financial reporting as of December
31, 2006, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO) and our report dated March 9, 2007 expressed an unqualified
opinion thereon.
As discussed in Note 14 to the financial statements, the accompanying 2006
financial statements have been restated.
/s/ BDO Seidman, LLP
Dallas, Texas
March 9, 2007 (November 14, 2007 as to Note 14)
F-3
Report of Independent Registered Public Accounting Firm on Internal Control Over
Financial Reporting
The Board of Directors and Stockholders
Abraxas Petroleum Corporation
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting and Scope of
Management's Report, that Abraxas Petroleum Corporation maintained effective
internal control over financial reporting as of December 31, 2006, based on
criteria established in Internal Control--Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission (the COSO
criteria). Abraxas Petroleum Corporation's management is responsible for
maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting.
Our responsibility is to express an opinion on management's assessment and an
opinion on the effectiveness of the company's internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our
opinion.
A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.
In our opinion, management's assessment that Abraxas Petroleum Corporation
maintained effective internal control over financial reporting as of December
31, 2006, is fairly stated, in all material respects, based on the COSO
criteria. Also, in our opinion, Abraxas Petroleum Corporation maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2006, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets as of December 31, 2006 and 2005 and the related consolidated statements
of operations, stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 2006 of Abraxas Petroleum Corporation and our
report dated March 9, 2007 expressed an unqualified opinion thereon.
/s/ BDO Seidman, LLP
Dallas, Texas
March 9, 2007
F-4
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31
--------------------------------------
2006 2005
Restated
------------------ -------------------
(Dollars in thousands)
Current assets:
Cash ................................................... $ 43 $ 42
Accounts receivable:
Joint owners ....................................... 556 540
Oil and gas production sales ....................... 5,645 7,957
Other .............................................. 39 100
------------------ -------------------
6,240 8,597
Other current assets ................................... 470 1,638
------------------ -------------------
Total current assets................................ 6,753 10,277
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ............................................. 347,245 333,373
Unproved properties excluded from amortization...... - -
Other property and equipment ......................... 3,519 3,289
------------------ -------------------
Total .......................................... 350,764 336,662
Less accumulated depreciation, depletion, and
amortization ....................................... 246,353 231,414
------------------ -------------------
Total property and equipment - net ................. 104,411 105,248
Deferred financing fees, net .............................. 4,446 6,037
Other assets .............................................. 1,330 304
------------------ -------------------
Total assets ........................................... $ 116,940 $ 121,866
================== ===================
See accompanying notes to consolidated financial statements
F-5
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS (CONTINUED)
LIABILITIES AND STOCKHOLDERS' DEFICIT
December 31
--------------------------------------
2006 2005
Restated
------------------ -------------------
(Dollars in thousands)
Current liabilities:
Accounts payable .......................................... $ 5,268 $ 9,814
Joint interest oil and gas production payable ............. 2,621 3,481
Accrued interest .......................................... 1,427 1,368
Other accrued expenses .................................... 1,156 494
------------------ -------------------
Total current liabilities................................ 10,472 15,157
Long-term debt ............................................... 127,614 129,527
Future site restoration ..................................... 1,019 883
Commitments and contingencies - -
Stockholders' equity (deficit):
Common stock, par value $.01 per share - authorized
200,000,000 shares; issued 42,762,466 and 42,063,167 . 428 421
Additional paid-in capital ................................ 164,210 162,795
Accumulated deficit ...................................... (187,493) (188,193)
Treasury stock, at cost, 35,552 and 56,477 shares.......... (285) (408)
Accumulated other comprehensive income..................... 975 1,684
------------------ -------------------
Total stockholders' deficit................................... (22,165) (23,701)
------------------ -------------------
Total liabilities and stockholders' deficit................ $ 116,940 121,866
================== ===================
See accompanying notes to consolidated financial statements
F-6
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31
----------------------------------------------------------
2006 2005 2004
Restated
------------------- ------------------- ------------------
(In thousands except per share data)
Revenues:
Oil and gas production revenues ......................... $ 50,094 $ 47,314 $ 33,073
Rig revenues ............................................ 1,613 1,295 771
Other .................................................. 16 16 10
----------------- ------------------- ------------------
51,723 48,625 33,854
Operating costs and expenses:
Lease operating and production taxes .................... 11,776 11,094 8,567
Depreciation, depletion, and amortization ............... 14,939 8,914 7,213
Rig operations .......................................... 819 756 671
General and administrative (including stock-based
compensation of $998; $247; and $112)................. 5,160 5,757 5,238
----------------- ------------------- ------------------
32,694 26,521 21,689
----------------- ------------------- ------------------
Operating income ........................................... 19,029 22,104 12,165
Other (income) expense:
Interest income ......................................... (29) (19) (10)
Amortization of deferred financing fees ................. 1,591 1,589 1,848
Interest expense ........................................ 16,767 13,989 17,867
Financing costs.......................................... - - 1,657
Gain on debt redemption.................................. - - (12,561)
Other ................................................... - 274 387
----------------- ------------------- ------------------
19,029 15,833 9,188
Net Income from continuing operations before income tax..... 700 6,271 2,977
Deferred income tax benefit................................. - - (6,060)
----------------- ------------------- ------------------
Income from continuing operations........................... 700 6,271 9,037
Net income from discontinued operations.................... - 12,846 3,323
----------------- ------------------- ------------------
Net income.................................................. $ 700 $ 19,117 $ 12,360
================= =================== ==================
Basic earnings per common share:
Net earnings from continuing operations................. $ 0.02 $ 0.16 $ 0.25
Discontinued operations ................................. - 0.33 0.09
----------------- ------------------- ------------------
Net income per common share - basic ....................... $ 0.02 $ 0.49 $ 0.34
================= =================== ==================
Diluted earnings per common share:
Net earnings from continuing operations.................. $ 0.02 $ 0.15 $ 0.23
Discontinued operations ................................. - 0.31 0.09
----------------- ------------------- ------------------
Net income per common share - diluted..................... $ 0.02 $ 0.46 $ 0.32
================= =================== ==================
See accompanying notes to consolidated financial statements
F-7
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' DEFICIT
(In thousands except number of shares)
Accumulated
Common Stock Treasury Stock Additional Other Receivable
---------------------------------------- Paid-In Accumulated Comprehensive From
Shares Amount Shares Amount Capital Deficit Income (loss) Stock Sale Total
----------- ------------------------------------------------------------------------------------------
Balance at December 31, 2003 36,024,308 $360 165,883 $ (964) $ 147,804 $(219,670) $ 364 $(97) $(72,203)
Net Income.............. - - - - - 12,360 - - 12,360
Foreign currency
translation
adjustment ........ - - - - - - 2,704 - 2,704
Proceeds from receivable - - - - - - - 97 97
Stock issued for
compensation........... 58,808 1 (59,894) 415 (87) - - - 329
Stock-based compensation
expense................ - - - - 112 - - - 112
Stock options and
warrants exercised .... 513,929 5 - - 3,132 - - - 3,137
-------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 36,597,045 366 105,989 (549) 150,961 (207,310) 3,068 - (53,464)
Net Income............... - - - - - 19,117 - - 19,117
Foreign currency
translation
adjustment ........ - - - - - - (3,068) - (3,068)
Increase in carrying
value of
investments........ - - - - - - 1,684 - 1,684
Stock-based compensation. - - - - 247 - - - 247
Shares issued for
compensation............ - - (49,512) 141 (39) - - - 102
Stock options exercised.. 461,408 5 - - 423 - - - 428
Stock warrants exercised. 996,479 10 - - (10) - - - -
Stock issued in private
placement.............. 4,000,000 40 - - 11,213 - - - 11,253
Other.................... 8,235 - - - - - - - -
-------------------------------------------------------------------------------------------------------
Balance at December 31, 2005 42,063,167 421 56,477 (408) 162,795 (188,193) 1,684 - (23,701)
Net Income - Restated.... - - - - - 700 - - 700
Decrease in carrying
value of
investments....... - - - - - - (709) - (709)
Stock-based compensation. - - - - 998 - - - 998
Shares issued for
compensation............ 5,782 - (20,925) 123 14 - - - 137
Stock options exercised.. 693,517 7 - - 403 - - - 410
-------------------------------------------------------------------------------------------------------
Balance at December 31, 2006
- Restated 42,762,466 $428 35,552 $ (285) $ 164,210 $(187,493) $ 975 $ - $(22,165)
========================================================================================================
See accompanying notes to consolidated financial statements.
F-8
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31
--------------------------------------------------------------------------
2006 2005 2004
Restated
------------------ ----------------------- -------------------------
(In thousands)
Operating Activities
Net income ........................................ $ 700 $ 19,117 $ 12,360
Income from discontinued operations................ - 12,846 3,323
------------------ ----------------------- -------------------------
Income from continuing operations.................. 700 6,271 9,037
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion, and
amortization ............................... 14,939 8,914 7,213
Non-cash interest and financing cost........... - - 5,967
Accretion of future site restoration........... 133 19 108
Deferred tax benefit........................... - - (6,060)
Amortization of deferred financing fees........ 1,591 1,589 1,848
Stock-based compensation ...................... 998 247 112
Other non-cash transactions.................... 92 - -
Changes in operating assets and liabilities:
Accounts receivable ........................ 2,357 (2,312) 7,816
Other ..................................... (567) 3,127 (291)
Accounts payable ........................... (5,406) 5,230 990
Accrued expenses ........................... 724 (1,986) 260
------------------ ----------------------- -------------------------
Net cash provided by continuing operations......... 15,561 21,099 27,000
Net cash provided by (used in) discontinued
operations.................................. - (4,132) 3,265
------------------ ----------------------- -------------------------
Net cash provided by operations.................... 15,561 16,967 30,265
------------------ ----------------------- -------------------------
Investing Activities
Capital expenditures, including purchases
and development of properties ................... (26,346) (35,350) (9,269)
Proceeds from the sale of oil and gas properties.... 12,244 - -
------------------ ----------------------- -------------------------
Net cash used in continuing operations.............. (14,102) (35,350) (9,269)
Net cash provided by (used in) discontinued
operations....................................... - 25,671 (12,069)
------------------ ----------------------- -------------------------
Net cash used in investing activities............... (14,102) (9,679) (21,338)
------------------ ----------------------- -------------------------
Financing Activities
Proceeds from issuance of common stock............ 455 11,783 3,465
Proceeds from long-term borrowings ............... 20,444 28,374 147,955
Payments on long-term borrowings ................. (22,357) (25,272) (212,146)
Deferred financing fees .......................... - (8) (5,056)
Other............................................. - - 98
------------------ ----------------------- -------------------------
Net cash provided by (used in) continuing
operations..................................... (1,458) 14,877 (65,684)
Net cash provided by (used in) discontinued
operations..................................... - (23,407) 58,041
------------------ ----------------------- -------------------------
Net cash used in financing activities............. (1,458) (8,530) (7,643)
------------------ ----------------------- -------------------------
Increase (decrease) in cash ...................... 1 (1,242) 1,284
Cash at beginning of year ........................ 42 1,284 -
------------------ ----------------------- -------------------------
Cash at end of year............................... $ 43 $ 42 $ 1,284
================== ======================= =========================
F-9
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOW (CONTINUED)
Years Ended December 31
-------------------------------------------------------------
2006 2005 2004
Restated
------------------ ---------------- -----------------
(In thousands)
Supplemental disclosures of cash flow information:
Interest paid .......................... $ 16,575 $ 12,583 $ 7,608
================== ================ =================
See accompanying notes to consolidated financial statements.
F-10
ABRAXAS PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OTHER COMPREHENSIVE INCOME
Years Ended December 31
----------------------------------------------------------------
2006 2005 2004
Restated
------------------ --------------------- -----------------
(In thousands)
Net income ................................................. $ 700 $ 19,117 $ 12,360
Other Comprehensive income:
Reclassification of foreign currency translation
adjustment relating to the sale of foreign subsidiary... - (3,068) -
Effect of change in exchange rate....................... - - 2,704
Change in carrying value of investment.................... (709) 1,684 -
------------------ --------------------- -----------------
Other comprehensive income .................................. (709) (1,384) 2,704
------------------ --------------------- -----------------
Comprehensive income ........................................ $ (9) $ 17,733 $ 15,064
================== ===================== =================
See accompanying notes to consolidated financial statements.
F-11
ABRAXAS PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Significant Accounting Policies
Nature of Operations
Abraxas Petroleum Corporation (the "Company", or "Abraxas") is an
independent energy company primarily engaged in the exploration of and the
acquisition, development, and production of crude oil and natural gas primarily
along the Texas Gulf Coast, in the Permian Basin of western Texas and in
Wyoming. The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries. All intercompany accounts and
transactions have been eliminated in consolidation.
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries. On February 28, 2005 our former wholly-owned
subsidiary, Grey Wolf Exploration, Inc. closed an initial public offering,
resulting in the substantial divestiture of our capital stock and operations in
Grey Wolf. As a result of the disposal of Grey Wolf, the results of operations
of Grey Wolf through February 28, 2005 are reflected in our financial statements
as discontinued operations.
Use of Estimates
The preparation of consolidated financial statements in conformity with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets and
liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Management believes that it is
reasonably possible that estimates of proved crude oil and natural gas revenues
could significantly change in the future.
Concentration of Credit Risk
Financial instruments, which potentially expose the Company to credit risk
consist principally of trade receivables and crude oil and natural gas price
hedges. Accounts receivable are generally from companies with significant oil
and gas marketing activities. The Company performs ongoing credit evaluations
and, generally, requires no collateral from its customers.
The Company maintains its cash and cash equivalents in excess of Federally
insured limits in prominent financial institutions considered by the Company to
be of high credit quality.
Cash and Equivalents
Cash and cash equivalents include cash on hand, demand deposits and
short-term investments with original maturities of three months or less.
Accounts Receivable
Accounts receivable are reported net of an allowance for doubtful accounts
of approximately $10,000 at December 31, 2006 and 2005. The allowance for
doubtful accounts is determined based on the Company's historical losses, as
well as a review of certain accounts. Accounts are charged off when collection
efforts have failed and the account is deemed uncollectible.
Oil and Gas Properties
The Company follows the full cost method of accounting for crude oil and
natural gas properties. Under this method, all direct costs and certain indirect
costs associated with acquisition of properties and successful as well as
unsuccessful exploration and development activities are capitalized.
Depreciation, depletion, and amortization of capitalized crude oil and natural
gas properties and estimated future development costs, excluding unproved
properties, are based on the unit-of-production method based on proved reserves.
F-12
Net capitalized costs of crude oil and natural gas properties, as adjusted for
asset retirement obligations, less related deferred taxes, are limited to the
lower of unamortized cost or the cost ceiling, defined as the sum of the present
value of estimated future net revenues from proved reserves based on unescalated
prices discounted at 10 percent, plus the cost of properties not being
amortized, if any, plus the lower of cost or estimated fair value of unproved
properties included in the costs being amortized, if any, less related income
taxes. The Company does not have any properties being exclude from amortization.
Excess costs are charged to proved property impairment expense. No gain or loss
is recognized upon sale or disposition of crude oil and natural gas properties,
except in unusual circumstances.
Other Property and Equipment
Other property and equipment are recorded on the basis of cost.
Depreciation of other property and equipment is provided over the estimated
useful lives using the straight-line method. Major renewals and betterments are
recorded as additions to the property and equipment accounts. Repairs that do
not improve or extend the useful lives of assets are expensed.
Hedging
The Company enters into agreements to hedge the risk of future crude oil
and natural gas price fluctuations. Such agreements are primarily in the form of
price floors, which limit the impact of price reductions with respect to the
Company's sale of crude oil and natural gas. The Company does not enter into
speculative hedges.
Statement of Financial Accounting Standards, ("SFAS") No. 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended and interpreted,
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. The Company elected out of hedge accounting as prescribed by
SFAS 133. Accordingly all derivatives will be recorded on the balance sheet at
fair value with changes in fair value being recognized in earnings.
Foreign Currency Translation
The functional currency for Grey Wolf was the Canadian dollar ($CDN). The
Company translates the functional currency into U.S. dollars ($US) based on the
current exchange rate at the end of the period for the balance sheet and a
weighted average rate for the period on the statement of operations. Prior to
2006, translation adjustments were reflected as accumulated other comprehensive
income (loss) in the consolidated statement of stockholders' deficit.
Fair Value of Financial Instruments
The Company includes fair value information in the notes to consolidated
financial statements when the fair value of its financial instruments is
materially different from the book value. The Company assumes the book value of
those financial instruments that are classified as current approximates fair
value because of the short maturity of these instruments. For noncurrent
financial instruments, the Company uses quoted market prices or, to the extent
that there are no available quoted market prices, market prices for similar
instruments.
Restoration, Removal and Environmental Liabilities
The Company is subject to extensive Federal, state and local environmental
laws and regulations. These laws regulate the discharge of materials into the
environment and may require the Company to remove or mitigate the environmental
effects of the disposal or release of petroleum substances at various sites.
Environmental expenditures are expensed or capitalized depending on their future
economic benefit. Expenditures that relate to an existing condition caused by
past operations and that have no future economic benefit are expensed.
Liabilities for expenditures of a noncapital nature are recorded when
environmental assessments and/or remediation is probable, and the costs can be
reasonably estimated. Such liabilities are generally undiscounted unless the
timing of cash payments for the liability or component are fixed or reliably
determinable.
F-13
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143).
SFAS 143 addresses accounting and reporting for obligations associated with the
retirement of tangible long-lived assets and the associated asset retirement
costs. SFAS 143 requires that the fair value of a liability for an asset's
retirement obligation be recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated over the useful life of the
related asset. For all periods presented, we have included estimated future
costs of abandonment and dismantlement in our full cost amortization base and
amortize these costs as a component of our depletion expense in the accompanying
consolidated financial statements.
The following table summarizes the Company's asset retirement obligation
transactions related to continuing operations during the following years:
2006 2005 2004
---------------- ------------------ ---------------
Beginning asset retirement obligation......... $ 883 $ 888 $ 776
New wells placed on production and other ..... 29 115 132
Deletions related to property disposals....... (26) (139) (128)
Accretion expense............................. 133 19 108
---------------- ------------------ ---------------
Ending asset retirement obligation............ $ 1,019 $ 883 $ 888
================ ================== ===============
Revenue Recognition and Major Customers
The Company recognizes crude oil and natural gas revenue from its interest
in producing wells as crude oil and natural gas is sold from those wells, net of
royalties. Revenue from the processing of natural gas is recognized in the
period the service is performed. The Company utilizes the sales method to
account for gas production volume imbalances. Under this method, income is
recorded based on the Company's net revenue interest in production taken for
delivery. The Company had no material gas imbalances at December 31, 2006 and
2005.
Rig revenue is recognized as earned.
During 2006, 2005 and 2004 two customers accounted for 25% and 24%; 35% and
26%; and 38% and 26% of crude oil and natural gas revenues, respectively.
Deferred Financing Fees
Deferred financing fees are being amortized on a level yield basis over the
term of the related debt arrangements.
Income Taxes
The Company records deferred income taxes using the liability method. Under
this method, deferred tax assets and liabilities are determined based on
differences between financial reporting and tax bases of assets and liabilities
and are measured using the enacted tax rates and laws that will be in effect
when the differences are expected to reverse. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts expected
to be realized.
Other Comprehensive Income
FASB Statement of Financial Accounting Standards No. 130, "Reporting
Comprehensive Income" (SFAS 130) requires disclosure of comprehensive income,
which includes reported net income as adjusted for other comprehensive income.
The components of other comprehensive income for the Company are foreign
currency translation adjustments and change in the market value of marketable
securities.
New Accounting Pronouncements
In June 2006, the FASB issued FIN 48, "Accounting for Uncertainty in Income
Taxes, an interpretation of FASB Statement No. 109." FIN 48 requires an entity
to evaluate its tax positions following a two-step process. The first step
requires an entity to determine whether it is more-likely-than-not that a tax
position will be sustained based on the technical merits of the position. The
second step requires an entity to recognize in the financial statements each tax
F-14
position that meets the more-likely-than-not criterion. Each recognized tax
position should be measured at the largest amount of benefit that has a greater
than 50 percent likelihood of being realized. FIN 48 also provides guidance on
derecognition, classification, interest and penalties, accounting in interim
periods, disclosure and transition.
FIN 48 is effective for fiscal years beginning after December 15, 2006. The
impact of initially applying FIN 48 is required to be recognized as a cumulative
effect adjustment to the opening balance of retained earnings for that fiscal
year. The Company is currently evaluating the impact of applying this guidance
if any.
In September 2006, the FASB issued Statement of Financial Accounting
Standards No. 157, "Fair Value Measurements" ("SFAS No. 157"). This standard
clarifies the principle that fair value should be based on the assumptions that
market participants would use when pricing an asset or liability. Additionally,
it establishes a fair value hierarchy that prioritizes the information used to
develop those assumptions. We have not yet determined the impact that the
implementation of SFAS No. 157 will have on our results of operations or
financial condition if any. SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007.
In September 2006, the SEC issued Staff Accounting Bulletin No. 108,
Considering the Effects of Prior Year Misstatements when quantifying
Misstatements in Current Year Financial Statements ("SAB 108"). SAB 108 requires
companies to evaluate the materiality of identified unadjusted errors on each
financial statement and related financial statement disclosure using both the
rollover approach and the iron curtain approach, as those terms are defined in
SAB 108. The rollover approach quantifies misstatements based on the amount of
the error in the current year financial statement, whereas the iron curtain
approach quantifies misstatements based on the effects of correcting the
misstatement existing in the balance sheet at the end of the current year,
irrespective of the misstatement's year(s) of origin. Financial statements would
require adjustment when either approach results in quantifying a misstatement
that is material. Correcting prior year financial statements for immaterial
errors would not require previously filed reports to be amended. If a Company
determines that an adjustment to prior year financial statements is required
upon adoption of SAB 108 and does not elect to restate its previous financial
statements, then it must recognize the cumulative effect of applying SAB 108 in
fiscal 2006 beginning balances of the affected assets and liabilities with a
corresponding adjustment to the fiscal 2006 opening balance in retained
earnings. SAB 108 is effective for interim periods of the first fiscal year
ending after November 15, 2006 and was adopted by the company effective October
1, 2006. The adoption of SAB 108 did not have a material impact on the Company's
consolidated financial statements.
2. Stock-based Compensation
Effective October 1, 2005, the Company adopted SFAS No. 123R, "Share-Based
Payment." Among other items, SFAS 123R eliminates the use of the intrinsic value
method of accounting, and requires companies to recognize the cost of employee
services received in exchange for awards of equity instruments, based on the
grant date fair value of those awards, in the financial statements.
The Company has elected to use the "modified retrospective" method as
prescribed in SFAS 123, which requires the cost of all share-based payments,
including stock options, to be measured at fair value on the grant date and
recognized in the statement of operations. In accordance with this standard, all
periods prior to January 1, 2005 were restated to reflect the impact of the
standard as if it had been adopted on January 1, 1995, the original effective
date of SFAS No. 123, "Accounting for Stock-Based Compensation." Also in
accordance with the standard, the amounts that are reported in the statement of
operations for the restated periods are the pro forma amounts previously
disclosed under SFAS No. 123.
The Company currently utilizes a standard option pricing model (i.e.,
Black-Scholes) to measure the fair value of stock options granted to employees.
While SFAS 123R permits entities to continue to use such a model, the standard
also permits the use of a more complex binomial, or "lattice" model. Based upon
research done by the Company on the alternative models available to value option
grants, and in conjunction with the type and number of stock options expected to
be issued in the future, the Company has determined that it will continue to use
the Black-Scholes model for option valuation. The fair value for these options
was estimated at the date of grant using a Black-Scholes option pricing model
with the following weighted-average assumptions for 2004, 2005 and 2006,
risk-free interest rates of 1.5% in 2004, 4.14% in 2005 and 4.62% in 2006;
dividend yields of -0-%; volatility factors of the expected market price of the
Company's common stock of .35 in 2004, .89 in 2005 and .62 in 2006, determined
F-15
by daily historical prices as well as other market indicators, and a
weighted-average expected life of the option of ten years in 2004, 8.3 years in
2005 and 4.71 to 5.06 years in 2006.
As a result of the adoption of this standard, the Company recognized a
reduction of stock based compensation expense of approximately $1.2 million for
the year ended December 31, 2004. This resulted in an increase in net income
from continuing operations, net income before tax, net income and cash flow from
operations of $1.2 million for 2004 and an increase of $0.03 earnings per share
for the period. The Company recognized $998,000, $247,000, and $112,000 in
stock-based compensation expense for 2006, 2005 and 2004, respectively as a
result of the adoption of this standard.
3. Discontinued Operations
On February 28, 2005, Abraxas substantially divested its investment in Grey
Wolf. The operations of Grey Wolf, previously reported as a business segment,
are reported as discontinued operations for all periods presented in the
accompanying financial statements and the operating results are reflected
separately from the results of continuing operations. Interest attributable to
discontinued operations represents interest on debt attributable to the Canadian
subsidiary. Summarized discontinued operating results for the years ended
December 31, 2005 and 2004 were:
Years Ended
------------------------------------
2005 2004
--------------- ----------------
Total revenue........................................ $ 3,129 $ 15,082
================ ================
Income from operations before income tax ............ 18,906 (1) 3,323
Income tax expense (benefit)......................... 6,060 -
---------------- ----------------
Income from discontinued operations ................. $ 12,846 $ 3,323
================ ================
(1) Includes gain on sale of foreign subsidiary of $17.3 million in 2005.
4. Long-Term Debt
The following is a description of the Company's debt as of December 31, 2006 and
2005, respectively:
December 31
--------------------------------
2006 2005
--------------------------------
(in thousands)
Floating rate senior secured notes due 2009................ $ 125,000 $ 125,000
Senior secured revolving credit facility................... 2,614 4,527
--------------------------------
127,614 129,527
Less current maturities ................................... - -
--------------------------------
$ 127,614 $ 129,527
================================
Floating Rate Senior Secured Notes due 2009. In connection with the October
2004 financial restructuring, Abraxas issued $125 million in principal aggregate
amount of Floating Rate Senior Secured Notes due 2009. The notes will mature on
December 1, 2009 and began accruing interest from the date of issuance, October
28, 2004 at a per annum floating rate of six-month LIBOR plus 7.50%. The current
interest rate is 12.85% per annum. The interest rate is reset semi-annually on
each June 1 and December 1. Interest is payable semi-annually in arrears on June
1 and December 1 of each year.
The notes rank equally among themselves and with all of our unsubordinated
and unsecured indebtedness, including our credit facility and senior in right of
payment to our existing and future subordinated indebtedness.
Each of our subsidiaries, Eastside Coal Company, Inc., Sandia Oil & Gas
Corporation, Sandia Operating Corp., Wamsutter Holdings, Inc. and Western
Associated Energy Corporation (collectively, the "Subsidiary Guarantors"), has
unconditionally guaranteed, jointly and severally, the payment of the principal,
premium and interest on the notes on a senior secured basis. In addition, any
other subsidiary or affiliate of ours, that in the future guarantees any other
indebtedness with us, or our restricted subsidiaries, will also be required to
guarantee the notes.
F-16
The notes and the Subsidiary Guarantors' guarantees thereof, together with
our revolving credit facility and the Subsidiary Guarantors' guarantees thereof,
are secured by shared first priority perfected security interests, subject to
certain permitted encumbrances, in all of our and each of our restricted
subsidiaries' material property and assets, including substantially all of our
and their natural gas and crude oil properties and all of the capital stock (or
in the case of an unrestricted subsidiary that is a controlled foreign
corporation, up to 65% of the outstanding capital stock) of any entity, owned by
us and our restricted subsidiaries (collectively, the "Collateral").
The notes may be redeemed, at our election, as a whole or from time to time
in part, at any time after April 28, 2007, upon not less than 30 nor more than
60 days notice to each holder of notes to be redeemed, subject to the conditions
and at the redemption prices (expressed as percentages of principal amount) set
forth below, together with accrued and unpaid interest and Liquidating Damages
(as defined in the indenture) if any, to the applicable redemption date.
Year Percentage
-----------------------------------------------------------------
From April 29, 2007 to April 28, 2008 104.00%
From April 29, 2008 to April 28, 2009 102.00%
After April 28, 2009 100.00%
Prior to April 28, 2007, we may redeem up to 35% of the aggregate original
principal amount of the notes using the net proceeds of one or more equity
offerings, in each case at the redemption price equal to the product of (i) the
principal amount of the notes being so redeemed and (ii) a redemption price
factor of 1.00 plus the per annum interest rate on the notes (expressed as a
decimal) on the applicable redemption date plus accrued and unpaid interest to
the applicable redemption date, provided certain conditions are also met.
If we experience specific kinds of change of control events, each holder of
notes may require us to repurchase all or any portion of such holder's notes at
a purchase price equal to 101% of the principal amount of the notes, plus
accrued and unpaid interest to the date of repurchase.
The indenture governing the notes contains covenants that, among other
things, limit our ability to:
o incur or guarantee additional indebtedness and issue certain types
of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o permit restrictions on the ability of our subsidiaries to
distribute or lend money to us;
o cause a restricted subsidiary to issue or sell its' capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of our and our restricted subsidiaries.
The indenture also contains customary events of default, including nonpayment of
principal or interest, violations of covenants, cross default and cross
acceleration to certain other indebtedness, including our revolving credit
facility, bankruptcy, and material judgments and liabilities.
Senior Secured Revolving Credit Facility. On October 28, 2004, we entered
into an agreement for a revolving credit facility having a maximum commitment of
$15 million, which includes a $2.5 million subfacility for letters of credit.
F-17
Availability under the revolving credit facility is subject to a borrowing base
consistent with normal and customary natural gas and crude oil lending
transactions.
Outstanding amounts under the revolving credit facility bear interest at
the prime rate announced by Wells Fargo Bank, National Association plus 1.00%.
The current interest rate is 9.25% per annum. Subject to earlier termination
rights and events of default, the stated maturity date under the revolving
credit facility is October 28, 2008.
We are permitted to terminate the revolving credit facility, and under
certain circumstances, may be required, from time to time, to permanently reduce
the lenders' aggregate commitment under the revolving credit facility. Such
termination and each such reduction is subject to a premium equal to the
percentage listed below multiplied by the lenders' aggregate commitment under
the revolving credit facility, or, in the case of partial reduction, the amount
of such reduction.
Year % Premium
-------------- --------------------
1 1.5
2 1.0
3 0.5
4 0.0
Each of our current subsidiaries has guaranteed, and each of our future
restricted subsidiaries will guarantee, our obligations under the revolving
credit facility on a senior secured basis. In addition, any other subsidiary or
affiliate of ours, that in the future guarantees any of our other indebtedness
or of our restricted subsidiaries will be required to guarantee our obligations
under the revolving credit facility. Obligations under the revolving credit
facility are secured, together with the notes, by a shared first priority
perfected security interest, subject to certain permitted encumbrances, in all
of our and each of our restricted subsidiaries' material property and assets,
including substantially all of our and their natural gas and crude oil
properties and all of the capital stock (or in the case of an unrestricted
subsidiary that is a controlled foreign corporation, up to 65% of the
outstanding capital stock) in any entity, owned by us and our restricted
subsidiaries.
Under the revolving credit facility, we are subject to customary covenants,
including certain financial covenants and reporting requirements. The revolving
credit facility requires us to maintain a minimum net cash interest coverage and
also requires us to enter into hedging agreements on not less than 25% or more
than 75% of our projected natural gas and crude oil production.
In addition to the foregoing and other customary covenants, the revolving
credit facility contains a number of covenants that, among other things,
restrict Abraxas' ability to:
o incur or guarantee additional indebtedness and issue certain types
of preferred stock or redeemable stock;
o transfer or sell assets;
o create liens on assets;
o pay dividends or make other distributions on capital stock or make
other restricted payments, including repurchasing, redeeming or
retiring capital stock or subordinated debt or making certain
investments or acquisitions;
o engage in transactions with affiliates;
o guarantee other indebtedness;
o make any change in the principal nature of our business;
o prepay, redeem, purchase or otherwise acquire any of our or our
restricted subsidiaries' indebtedness;
o permit a change of control;
o directly or indirectly make or acquire any investment;
o cause a restricted subsidiary to issue or sell our capital stock;
and
o consolidate, merge or transfer all or substantially all of the
consolidated assets of Abraxas and our restricted subsidiaries.
F-18
The revolving credit facility also contains customary events of default,
including nonpayment of principal or interest, violations of covenants, cross
default and cross acceleration to certain other indebtedness, bankruptcy and
material judgments and liabilities, and is subject to an Intercreditor, Security
and Collateral Agency Agreement, which specifies the rights of the parties
thereto to the proceeds from the Collateral.
Intercreditor Agreement. The holders of the notes, together with the
lenders under our credit facility, are subject to an Intercreditor, Security and
Collateral Agency Agreement, which specifies the rights of the parties thereto
to the proceeds from the Collateral. The Intercreditor Agreement, among other
things, (i) creates security interests in the Collateral in favor of a
collateral agent for the benefit of the holders of the notes and the credit
facility lenders and (ii) governs the priority of payments among such parties
upon notice of an event of default under the Indenture or the credit facility.
So long as no such event of default exists, the collateral agent will not
collect payments under the new credit facility documents or the indenture
governing the notes and other note documents (collectively, the "Secured
Documents"), and all payments will be made directly to the respective creditor
under the applicable Secured Document. Upon notice of an event of default and
for so long as an event of default exists, payments to each credit facility
lender and holder of the notes from us and our current subsidiaries and proceeds
from any disposition of any collateral, will, subject to limited exceptions, be
collected by the collateral agent for deposit into a collateral account and then
distributed as provided in the following paragraph.
Upon notice of any such event of default and so long as an event of default
exists, funds in the collateral account will be distributed by the collateral
agent generally in the following order of priority:
first, to reimburse the collateral agent for expenses incurred in
protecting and realizing upon the value of the Collateral;
second, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was acting on behalf
of the Control Party (as defined below);
third, to reimburse the credit facility administrative agent and the
trustee, on a pro rata basis, for expenses incurred in protecting and realizing
upon the value of the Collateral while any of these parties was not acting on
behalf of the Control Party;
fourth, to pay all accrued and unpaid interest (and then any unpaid
commitment fees) under the credit facility;
fifth, if, the collateral coverage value of three times the outstanding
obligations under the credit facility would be met after giving effect to any
payment under this clause "fifth," to pay all accrued and unpaid interest on the
notes;
sixth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any fees, expenses, premiums and
reimbursement obligations) the credit facility;
seventh, to pay all accrued and unpaid interest on the notes (if not
paid under clause "fifth");
eighth, to pay all outstanding principal of (and then any other unpaid
amounts, including, without limitation, any premium with respect to) the notes;
and
ninth, to pay each credit facility lender, holder of the notes, and
other secured party, on a pro rata basis, all other amounts outstanding under
the credit facility and the notes.
To the extent there exists any excess monies or property in the collateral
account after all of ours and our subsidiaries' obligations under the credit
facility, the indenture and the notes are paid in full, the collateral agent
will be required to return such excess to us.
The collateral agent will act in accordance with the Intercreditor
Agreement and as directed by the "Control Party" which for purposes of the
Intercreditor Agreement is the holders of the notes and the credit facility
lenders, acting as a single class, by vote of the holders of a majority of the
aggregate principal amount of outstanding obligations under the notes and the
credit facility.
F-19
The Intercreditor Agreement provides that the lien on the assets
constituting part of the Collateral that is sold or otherwise disposed of in
accordance with the terms of each Secured Document may be released if (i) no
default or event of default exists under any of the Secured Documents, (ii) we
have delivered an officers' certificate to each of the collateral agent, the
trustee, the credit facility administrative agent certifying that the proposed
sale or other disposition of assets is either permitted or required by, and is
in accordance with the provisions of, the applicable Secured Documents and (iii)
the collateral agent has acknowledged such certificate.
The Intercreditor Agreement provides for the termination of security
interests on the date that all obligations under the Secured Documents are paid
in full.
5. Property and Equipment
The major components of property and equipment, at cost, are as follows:
December 31
Estimated ----------------------------------
Useful Life 2006 2005
----------------- ---------------- -----------------
Years (In thousands)
Crude oil and natural gas properties ........... - $ 347,245 $ 333,373
Equipment and other ............................ 3-39 3,519 3,289
---------------- -----------------
$ 350,764 $ 336,662
================ =================
6. Stock Option Plans and Warrants
Stock Options
The Company grants options to its officers, directors, and other employees
under various stock option and incentive plans.
The Company's 1994 Long-Term Incentive Plan has authorized the grant of
options to management, employees and directors for up to approximately 6.1
million shares of the Company's common stock. All options granted generally have
a ten year term and vest and become fully exercisable over three to four years
of continued service at 25% to 33% on each anniversary date or as specified by
the Compensation Committee of the Board of Directors. At December 31, 2006
approximately 1.2 million options remain available for grant.
The Company's 2005 Employee Long-Term Equity Incentive Plan has authorized
the grant of 1.2 million options to management and employees. Options have a
term not to exceed 10 years. Options issued under this plan vest according to a
vesting schedule as determined by the compensation committee. Vesting may occur
upon (1) the attainment of one or more performance goals or targets established
by the committee (2) the optionee's continued employment or service for a
specified period of time, (3) the occurrence of any event or the satisfaction of
any other condition specified by the committee; or (4) a combination of any of
the foregoing
A summary of the Company's stock option activity for the three years ended
December 31, follows:
Options Weighted-Average Weighted Aggregate
(000s) Exercise Price Average Intrinsic
Remaining Life value (000s)
----------------------------------------------------------------------------------------------------------
Options outstanding December 31, 2003 3,364 $ 0.90
Granted .......................... - -
Exercised ........................ (414) 0.69
Forfeited/Expired ................ (57) 0.77
--------------
Options outstanding December 31, 2004 2,893 0.93
Granted .......................... 716 4.33
Exercised ........................ (461) 0.93
Forfeited/Expired ................ (132) 0.67
--------------
Options outstanding December 31, 2005 3,016 0.88
F-20
Granted .......................... 190 5.29
Exercised ........................ (747) 0.87
Forfeited/Expired ................ (2) 4.39
--------------
Options outstanding December 31, 2006 2,457 $ 2.29 5.35 $ 3,385
============== ================================
Exercisable at end of year .......... 1,884 $ 1.55 4.33 $ 1,730
============== ================================
Other information pertaining to option activity was as follows during the
twelve months ended December 31:
2006 2005 2004
----------- ----------- -----------
Weighted average grant-date fair value of stock
options granted (per share)...................... $ 2.98 $ 3.40 $ -
Total fair value of options vested (000's)........ $ 890 $ 166 $ 138
Total intrinsic value of options exercised (000's) $ 409 $ 245 $ 153
As of December 31, 2006 the total compensation cost related to nonvested
awards not yet recognized is approximately $1.6 million, which will be
recognized in 2007 through 2010.
The following table represents the range of option prices and the weighted
average remaining life of outstanding options as of December 31, 2006:
Options outstanding Exercisable
------------------------------------------------- -------------------------------------------------------
Weighted Weighted Weighted
average average average
Number outstanding remaining exercise Number remaining Weighted average
Exercise price life price exercisable life exercise price
-------------------- ------------------- ---------------- ------------ ----------------- ---------------- --------------------
$ 0.50 - 0.97 1,138,258 3.66 $ 0.71 1,122,008 3.66 $ 0.71
$ 1.01 - 1.41 240,000 4.93 1.20 240,000 4.93 1.20
$ 2.06 - 2.75 244,857 3.09 2.32 244,857 3.09 2.32
$ 3.09 - 4.83 737,001 8.37 4.59 277,501 8.37 4.59
$ 6.05 97,000 9.16 6.05 - - -
------------------- -----------------
2,457,116 1,884,366
=================== =================
For the year ended December 31, 2006, 97,000 shares exercisable in
connection with outstanding options were excluded from dilutive shares for
purposes of calculating diluted earnings per share. These options were excluded
because their exercise price was greater than the average price of the Company's
Common stock for the year then ended.
Stock Awards
In addition to stock options granted under the plan described above, the
1994 Long-Term Incentive Plan also provides for the right to receive
compensation in cash, awards of common stock, or a combination thereof. There
were no awards in 2006 or 2005. In 2004, 37,719 shares were awarded related to
incentive bonus plans.
The Company also has adopted the Restricted Share Plan for Directors which
provides for awards of common stock to non-employee directors of the Company who
did not, within the year immediately preceding the determination of the
director's eligibility, receive any award under any other plan of the Company.
On June 1, 2005, the stockholders approved the 2005 Non-Employee Directors
Long-Term Equity Incentive Plan (the "2005 Directors Plan"). The following is a
summary of the 2005 Directors Plan.
Purpose. The purpose of the 2005 Directors Plan is to attract and retain
members of the Board of Directors and to promote the growth and success of
Abraxas by aligning the long-term interests of the Board of Directors with those
of Abraxas' stockholders by providing an opportunity to acquire an interest in
Abraxas and by providing both rewards for performance and long term incentives
for future contributions to the success of Abraxas.
F-21
Administration and Eligibility. The 2005 Directors Plan will be
administered by the Compensation Committee (the "Committee") of the Board of
Directors and authorizes the Board to grant non-qualified stock options or issue
restricted stock to those persons who are non-employee directors of Abraxas,
including advisory directors of Abraxas, which currently amounts to a total of
nine people.
Shares Reserved and Awards. The 2005 Directors Plan reserves 900,000 shares
of Abraxas common stock, subject to adjustment following certain events, as
discussed below. The 2005 Directors Plan provides that each year, at the first
regular meeting of the Board of Directors immediately following Abraxas' annual
stockholder's meeting, each non-employee director shall be granted or issued
awards of 10,000 shares of Abraxas common stock, for participation in Board and
Committee meetings during the previous calendar year. The maximum annual award
for any one person is 10,000 shares of Abraxas common stock or options for
common stock. If options, as opposed to shares, are awarded, the exercise share
price shall be no less than 100% of the fair market value on the date of the
award while the option terms and vesting schedules are at the discretion of the
Committee. In addition to the 10,000 shares or options, directors are
compensated $12,000 per year, paid quarterly by issuance of common stock. During
2006, there were 5,782 shares issued related to this compensation. The number of
shares issued is determined based on the stock price on the date of issuance.
At December 31, 2006, the Company has approximately 3.7 million shares
reserved for future issuance for conversion of its stock options, warrants, and
incentive plans for the Company's directors, employees and consultants.
7. Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences
between the carrying amounts of assets and liabilities for financial reporting
purposes and the amounts used for income tax purposes. Significant components of
the Company's deferred tax liabilities and assets are as follows:
December 31
--------------------------
2006 2005
------------- ------------
(In thousands)
Deferred tax liabilities:
Marketable securities.......................... $ 261 $ 509
U.S. full cost pool ........................... 10,806 11,621
------------- ------------
Total deferred tax liabilities .................. 11,067 12,130
Deferred tax assets:
Capital loss carryforward...................... 4,234 5,325
Depletion carryforward......................... 4,311 3,542
Net operating losses ("NOL") carryforward..... 67,429 66,596
Canadian loss (Grey Wolf)...................... - 572
Other ......................................... 1,965 3,023
------------- ------------
Total deferred tax assets ....................... 77,939 79,058
Valuation allowance for deferred tax assets ..... (66,872) (66,928)
------------- ------------
Net deferred tax assets ......................... 11,067 12,130
------------- ------------
Net deferred tax ............................... $ - $ -
============= ============
Significant components of the provision (benefit) for income taxes are
as follows:
2006 2005 2004
-----------------------------------------
(in thousands)
Current:
Federal..................................... $ - $ - $ -
Foreign .................................... - - -
------------- ------------ ------------
$ - $ - $ -
============= ============ ============
Deferred:
Federal .................................... $ - $ (6,060) $ 6,060
Foreign .................................... - - -
------------- ------------ -------------
$ - (6,060) 6,060
Attributable to discontinued operations..... - (6,060) -
------------- ------------ -------------
Attributable to continuing operations....... $ - $ - $ 6,060
============= ============ =============
F-22
At December 31, 2006 the Company had, subject to the limitation discussed
below, $192.7 million of net operating loss carryforwards for U.S. tax purposes.
These loss carryforwards will expire from 2014 through 2026 if not utilized.
In addition to any Section 382 limitations, uncertainties exist as to the
future utilization of the operating loss carryforwards under the criteria set
forth under FASB Statement No. 109. Therefore, the Company has established a
valuation allowance of $66.9 million for deferred tax assets at December 31,
2006 and 2005.
The reconciliation of income tax computed at the U.S. federal statutory tax
rates to income tax expense is:
December 31
-------------------------------------------------------------
2006 2005 2004
------------------ --------------------- --------------------
(in thousands)
Tax (expense) benefit at U.S. statutory
rates (35%) ............................ $ (245) $ (6,691) $ (1,875)
Decrease in deferred tax asset valuation
allowance .............................. 56 6,068 8,123
Higher effective rate of foreign - - (140)
operations............................
Permanent differences................... (6) - -
Deferred tax expense - Disc. Ops. ..... - (6,060) -
Other .................................. 195 623 (48)
------------------ --------------------- --------------------
$ - $ (6,060) $ 6,060
Attributable to discontinued operations - (6,060) -
------------------ --------------------- --------------------
Attributable to continuing operations.. $ - $ - $ 6,060
================== ===================== ====================
8. Commitments and Contingencies
Operating Leases
During the years ended December 31, 2006, 2005 and 2004 the Company
incurred rent expense related to leasing office facilities of approximately
$252,146, $248,684 and $256,355 respectively. Future minimum rental payments are
as follows at December 31, 2006.
2007..................................................... $ 259,092
2008..................................................... 254,702
2009..................................................... 21,152
2010..................................................... -
Thereafter............................................... -
-----------------
$ 534,946
=================
Litigation and Contingencies
From time to time, the Company is involved in litigation relating to claims
arising out of its operations in the normal course of business. At December 31,
2006 the Company was not engaged in any legal proceedings that are expected,
individually or in the aggregate, to have a material adverse effect on the
Company.
9. Earnings per Share
Basic earnings per share excludes any dilutive effects of options, warrants
and convertible securities and is computed by dividing income available to
common stockholders by the weighted average number of common shares outstanding
for the period. Diluted earnings per share are computed similar to basic,
however diluted earnings per share reflects the assumed conversion of all
potentially dilutive securities.
The following table sets forth the computation of basic and diluted earnings
per share:
F-23
2006 2005 2004
--------------------------------------------------------
Numerator:
Net income before effect of discontinued
operations ..................................... $ 700,000 $ 6,271,000 $ 9,037,000
Discontinued operations........................... - 12,846,000 3,323,000
----------------- ------------------ --------------------
$ 700,000 $ 19,117,000 $ 12,360,000
================= ================== ====================
Denominator:
Denominator for basic earnings per share -
weighted-average shares ........................ 42,578,584 39,366,561 36,221,887
Effect of dilutive securities:
Stock options and warrants..................... 1,283,797 1,796,942 2,672,778
----------------- ------------------ --------------------
Dilutive potential common shares
Denominator for diluted earnings per share
- adjusted weighted-average shares and assumed
exercise of options and warrants................ 43,862,381 41,163,503 38,894,665
================= =================== ===================
Basic earnings per share:
Net income before effect of discontinued
operations ....................................... $ 0.02 $ 0.16 $ 0.25
Discontinued operations - 0.33 0.09
----------------- ------------------- ------------------
Net income per common share....................... $ 0.02 $ 0.49 $ 0.34
================= =================== ==================
Diluted earnings per share:
Net income before effect of discontinued
operations........................................ $ 0.02 $ 0.15 $ 0.23
Discontinued operations........................... - 0.31 0.09
----------------- ------------------- -------------------
Net income per common share - diluted........ $ 0.02 $ 0.46 $ 0.32
================= =================== ===================
10. Quarterly Results of Operations (Unaudited)
Selected results of operations for each of the fiscal quarters during
the years ended December 31, 2005 and 2006 are as follows, 2005 includes results
of discontinued operations:
1st 2nd 3rd 4th
Quarter Quarter Quarter Quarter
---------------- ---------------- --------------- --------------------
(In thousands, except per share data)
Year Ended December 31, 2005
Net revenue .......................... $ 7,822 $ 9,627 $ 14,164 $ 17,012
Operating income ..................... $ 2,657 $ 4,008 $ 7,905 $ 7,534
Net income (loss)..................... $ 11,985 $ (64) $ 3,783 $ 3,413
Net income per common share - basic... $ 0.33 $ 0.00 $ 0.09 $ 0.08
Net income per common share - diluted. $ 0.33 $ 0.00 $ 0.09 $ 0.08
Year Ended December 31, 2006
Net revenue........................... $ 13,305 $ 13,304 $ 13,216 $ 11,898
Operating income...................... $ 5,587 $ 5,496 $ 5,426 $ 3,066
Net income (loss)..................... $ 1,220 $ 983 $ 589 $ (2,092) (1)
Net income (loss) per common share -
basic............................... $ 0.03 $ 0.02 $ 0.01 $ (0.04)
Net income (loss) per common share -
diluted............................. $ 0.03 $ 0.02 $ 0.01 $ (0.04)
(1) The loss during the fourth quarter was due to lower commodity
prices realized, accrual of bonuses and an increase in non-cash
compensation expense related to director stock options.
F-24
11. Benefit Plans
The Company has a defined contribution plan (401(k)) covering all eligible
employees of the Company. The Company matched employee contributions in 2004 and
matched 50% of employee contributions in 2005 and 2006. Company contributions to
the plan were $128,523, $116,136 and $101,499 in 2006, 2005 and 2004
respectively. The employee contribution limitations are determined by formulas,
which limit the upper one-third of the plan members from contributing amounts
that would cause the plan to be top-heavy. The employee contribution is limited
to the lesser of 20% of the employee's annual compensation or $15,000, $14,000
and $13,000 in 2006, 2005 and 2004, respectively. The contribution limit for
2006, 2005 and 2004 was $20,000, $18,000 and $16,000 for employees 50 years of
age or older, respectively.
12. Hedging Program and Derivatives
The Company elected out of hedge accounting as prescribed by SFAS 133.
Accordingly, instruments are recorded on the balance sheet at their fair value
with adjustments to the carrying value of the instruments being recognized in
oil and gas income in the current period.
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 2005, we incurred a hedging loss of $592,000,
resulting from the price floors we established. For the year ended December 31,
2004 and 2006, we recognized a gain from hedging activities of approximately
$118,000 and $646,000 respectively. Currently, we believe our hedging
arrangements, which are in the form of price floors, do not expose us to
significant financial risk.
Under the terms of the Company's revolving credit facility, the Company is
required to maintain hedging agreements with respect to not less than 25% nor
more than 75% of it crude oil and natural gas production for a rolling six month
period. We currently have hedging positions as follows:
Time Period Notional Quantities Price
---------------------------------- -------------------------------------------- ----------------------
April 2007 10,000 MMbtu of production per day Floor of $ 4.50
May 2007 10,000 MMbtu of production per day Floor of $ 5.00
June 2007 10,000 MMbtu of production per day Floor of $ 5.00
July 2007 10,000 MMbtu of production per day Floor of $ 4.25
August 2007 10,000 MMbtu of production per day Floor of $ 5.00
September 2007 10,000 MMbtu of production per day Floor of $ 5.50
All hedge transactions are subject to the Company's risk management policy,
approved by the Board of Directors.
13. Supplemental Oil and Gas Disclosures (Unaudited)
The accompanying table presents information concerning the Company's crude
oil and natural gas producing activities as required by Statement of Financial
Accounting Standards No. 69, "Disclosures about Oil and Gas Producing
Activities." Capitalized costs relating to oil and gas producing activities from
continuing operations are as follows:
Years Ended December 31
-----------------------------------
2006 2005
---------------- ---------------
(In thousands)
Proved crude oil and
natural gas properties ... $ 347,245 $ 333,373
Unproved properties ........ - -
---------------- ---------------
Total..................... 347,245 333,373
Accumulated depreciation,
depletion, and
amortization, and
impairment ............... (243,353) (228,544)
---------------- ---------------
Net capitalized costs .. $ 103,892 $ 104,829
================ ===============
F-25
Cost incurred in oil and gas property acquisitions and development
activities related to continuing operations are as follows:
Years Ended December 31
---------------------------------------------
2006 2005 2004
-------------- -------------- ---------------
(In thousands)
---------------------------------------------
Property development and
exploration costs ........... $ 26,117 $ 34,991 $ 9,088
============== ============== ===============
The results of operations for oil and gas producing activities from
continuing operations for the three years ending December 31, 2006, 2005 and
2004, respectively are as follows:
Years Ended December 31
---------------------------------------------
2006 2005 2004
-------------- -------------- ---------------
(In thousands)
Revenues ................... $ 50,094 $ 47,314 $ 33,073
Production costs ........... (11,776) (11,094) (8,567)
Depreciation, depletion,
and amortization ......... (14,809) (8,818) (7,117)
General and administrative . (1,040) (1,378) (1,281)
-------------- -------------- ---------------
Results of operations from oil
and gas producing activities
(excluding corporate overhead
and interest costs) .......... $ 22,469 $ 26,024 $ 16,108
============== ============== ===============
Depletion rate per barrel
of oil equivalent ........ $ 11.51 $ 8.77 $ 7.39
============== ============== ===============
Estimated Quantities of Proved Oil and Gas Reserves
The following table presents the Company's estimate of its net proved crude
oil and natural gas reserves as of December 31, 2006, 2005, and 2004 related to
continuing operations. The Company's management emphasizes that reserve
estimates are inherently imprecise and that estimates of new discoveries are
more imprecise than those of producing oil and gas properties. Accordingly, the
estimates are expected to change as future information becomes available. The
estimates have been prepared by independent petroleum reserve engineers.
Liquid Natural
Hydrocarbons Gas
----------------- --------------
(Barrels) (Mcf)
(In thousands)
----------------- --------------
Proved developed and undeveloped reserves:
Balance at December 31, 2003...................... 3,319 80,202
Revisions of previous estimates ................ (104) (4,143)
Extensions and discoveries ..................... 70 73
Production ..................................... (229) (4,403)
----------------- --------------
Balance at December 31, 2004...................... 3,056 71,729
Revisions of previous estimates ................ 5 (2,775)
Extensions and discoveries ..................... 168 16,259
Production ..................................... (194) (4,942)
----------------- --------------
Balance at December 31, 2005 3,035 80,271
Revisions of previous estimates ................ (90) (2,053)
Extensions and discoveries ..................... 11 440
Sales of minerals in place...................... - (1,810)
Production ..................................... (200) (6,515)
----------------- --------------
Balance at December 31, 2006...................... 2,756 70,333
================= ==============
F-26
Liquid Natural
Hydrocarbons Gas
----------------- --------------
(Barrels) (Mcf)
Proved developed reserves:
December 31, 2004................................. 1,878 36,247
================= ==============
December 31, 2005................................. 1,942 38,797
================= ==============
December 31, 2006................................. 1,708 37,333
================= ==============
Due to continuing development activities, the Company added additonal
reserves of approximately 16.3 Mmcf during 2005 in South and West Texas. During
2006, due to the level of production in the Edwards field in South Texas,
reserves previously estimated for the area were revised upwardly.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil
and Gas Reserves
The following disclosures concerning the standardized measure of future
cash flows from proved crude oil and natural gas are presented in accordance
with SFAS No. 69. The standardized measure does not purport to represent the
fair market value of the Company's proved crude oil and natural gas reserves. An
estimate of fair market value would also take into account, among other factors,
the recovery of reserves not classified as proved, anticipated future changes in
prices and costs, and a discount factor more representative of the time value of
money and the risks inherent in reserve estimates.
Under the standardized measure, future cash inflows were estimated by
applying period-end prices at December 31, 2006 adjusted for fixed and
determinable escalations, to the estimated future production of year-end proved
reserves. Future cash inflows were reduced by estimated future production and
development costs based on year-end costs to determine pre-tax cash inflows.
Future income taxes were computed by applying the statutory tax rate to the
excess of pre-tax cash inflows over the tax basis of the properties. Operating
loss carryforwards, tax credits, and permanent differences to the extent
estimated to be available in the future were also considered in the future
income tax calculations, thereby reducing the expected tax expense.
Future net cash inflows after income taxes were discounted using a 10%
annual discount rate to arrive at the Standardized Measure.
Set forth below is the Standardized Measure relating to proved oil and gas
reserves relating to continuing operations for the three years ending December
31, 2006, 2005 and 2004.
Years Ended December 31
------------------------------------------------------
2006 2005 2004
------------------------------------------------------
(in thousands)
Future cash inflows ... $ 567,805 $ 880,116 $ 480,389
Future production costs (169,805) (201,051) (146,092)
Future development
costs ............... (73,377) (78,205) (42,104)
Future income tax
expense ............. - - -
------------------------------------------------------
Future net cash flows . 324,623 600,860 292,193
Discount .............. (167,779) (290,965) (144,916)
------------------------------------------------------
Standardized Measure
of discounted future
net cash relating to
proved reserves ..... $ 156,844 $ 309,895 $ 147,277
======================================================
F-27
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to
Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure
related to continuing operations:
Year Ended December 31
----------------------------------------------------------
2006 2005 2004
------------------- ------------------- ------------------
(In thousands)
Standardized Measure, beginning
of year ................................. $ 308,895 $ 147,277 $ 161,584
Sales and transfers of oil and gas
produced, net of production costs ....... (38,318) (36,220) (24,506)
Net changes in prices and development
and production costs from prior year .... (114,517) 142,389 (45)
Extensions, discoveries, and improved
recovery, less related costs ............ 914 54,335 833
Sales of minerals in place................. (3,268) - -
Revision of previous quantity estimates ... (15,914) (3,977) (8,045)
Changes in timing and other ............... (12,937) (8,637) 1,298
Accretion of discount ..................... 30,989 14,728 16,158
------------------- ------------------- ------------------
Standardized Measure, end of year ....... $ 156,844 $ 309,895 $ 147,277
=================== =================== ==================
F-28
Note 14. Restatement
The Company's reserve estimates at December 31, 2006 included approximately
12 Bcf of reserves classified as proved undeveloped reserves in our reserve
report prepared by independent third-party engineers as of December 31, 2006.
The subject reserves, predominately located in West Texas, are scheduled to be
produced from deeper recompletions of wellbores that are currently producing in
commercial quantities from a shallower formation. The Company scheduled the
re-completions to produce such reserves from the deeper formation beginning at
the time the shallower formation is expected to be depleted, which according to
its reserve report would not occur within the next five years.
In connection with the filing of the Registration Statement on Form S-1 of
Abraxas Energy, the Company concluded that it should reclassify these reserves
and remove them from the proved undeveloped category as previously reported in
its 2006 Form 10-K because the future re-completions are not scheduled to be
performed for many years in the future and require significant additional
capital such as for deepening wells are subject to greater uncertainties such as
depletion from offsetting wells, changes in management, greater geological
risks, changes in the company's strategy or focus and other factors. The Company
believes that these greater uncertainties suggest that these volumes should
remain as unproved until they are more reasonably certain of being developed.
These reserves represented approximately 12% of the Company's proved reserves at
December 31, 2006 but only approximately 3% of its PV-10 at such date.
As a result of this correction of the Company's proved reserves, depletion
of oil and gas properties was understated by approximately $546,000. This
resulted in the restatement of the consolidated balance sheet, consolidated
statement of operations and statement of cash flows for the year ended December
31, 2006. Cash flows from operations were not impacted by this correction. The
impact of this revision on all periods prior to 2006 was not material.
A summary of the significant effects of the restatement is as follows (In
thousands):
December 31, 2006
-----------------------------------------------
As Previously Adjustment Restated
Reported
-----------------------------------------------
Current assets:
Cash ........................................... $ 43 $ - $ 43
Accounts receivable:
Joint owners ............................... 556 - 556
Oil and gas production sales ............... 5,645 - 5,645
Other ...................................... 39 - 39
-----------------------------------------------
6,240 - 6,240
Other current assets ........................... 470 - 470
-----------------------------------------------
Total current assets........................ 6,753 - 6,753
F-29
Property and equipment:
Oil and gas properties, full cost method of accounting:
Proved ..................................... 347,245 - 347,245
Unproved properties excluded from depletion. - - -
Other property and equipment ................. 3,519 - 3,519
-----------------------------------------------
Total .................................. 350,764 - 350,764
Less accumulated depreciation, depletion,
and amortization ........................... 245,807 546 246,353
-----------------------------------------------
Total property and equipment - net ......... 104,957 546 104,411
Deferred financing fees, net ...................... 4,446 - 4,446
Other assets ...................................... 1,330 - 1,330
-----------------------------------------------
Total assets ................................... $ 117,486 $ 546 $ 116,940
===============================================
Current liabilities:
Accounts payable .................................... $ 5,268 $ - $ 5,268
Joint interest oil and gas production payable ....... 2,621 - 2,621
Accrued interest .................................... 1,427 - 1,427
Other accrued expenses .............................. 1,156 - 1,156
-----------------------------------------------
Total current liabilities.......................... 10,472 - 10,472
Long-term debt ......................................... 127,614 - 127,614
Future site restoration ............................... 1,019 - 1,019
Stockholders' equity (deficit):
Common stock, par value $.01 per share -
authorized 200,000,000 shares; issued
42,762,466 and 42,063,167 ......................... 428 - 428
Additional paid-in capital .......................... 164,210 - 164,210
Accumulated deficit ................................. (186,947) (546) (187,493)
Treasury stock, at cost, 35,552 and 56,477 shares.... (285) - (285)
Accumulated other comprehensive income............... 975 - 975
-----------------------------------------------
Total stockholders' deficit............................. (21,619) (546) (22,165)
-----------------------------------------------
Total liabilities and stockholders' deficit.......... $ 117,486 $ (546) $ 116,940
===============================================
For the year ended December 31, 2006
-----------------------------------------------
As Previously Adjustment Restated
Reported
-----------------------------------------------
Revenues:
Oil and gas production revenues ......................... $ 50,094 $ - $ 50,094
Rig revenues ............................................ 1,613 - 1,613
Other .................................................. 16 - 16
-----------------------------------------------
51,723 - 51,723
Operating costs and expenses:
Lease operating and production taxes .................... 11,776 - 11,776
Depreciation, depletion, and amortization ............... 14,393 546 14,939
Rig operations .......................................... 819 - 819
General and administrative (including stock-based
compensation of $998; $247; and $112)................. 5,160 - 5,160
-----------------------------------------------
32,148 546 32,694
-----------------------------------------------
Operating income ........................................... 19,575 (546) 19,029
Other (income) expense:
Interest income ......................................... (29) - (29)
Amortization of deferred financing fees ................. 1,591 - 1,591
Interest expense ........................................ 16,767 - 16,767
Financing costs.......................................... - - -
Gain on debt redemption.................................. - - -
Other ................................................... - - -
-------------------------------------------------
18,329 - 18,329
-------------------------------------------------
Net Income ............................................... 1,246 (546) 700
Deferred income tax benefit................................ - - -
-------------------------------------------------
Net income $ 1,246 $ (546) $ 700
=================================================
F-30