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)

--------------------------------------------------------------------------------

                  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.

                                       5


General

         We  are  an  independent   energy  company  primarily  engaged  in  the
development and production of natural gas and crude oil.  Historically,  we have
grown through the  acquisition  and subsequent  development  and  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

                                       6


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.

                                       11


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;

                                       12


         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.

                                       13


     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;

                                       14


            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;

                                       16


              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.

                                       18


     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.

                                       19


     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