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                                  UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 10-K

         [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: 0-26321
                               GASCO ENERGY, INC.
             (Exact name of registrant as specified in its charter)
                NEVADA                                        98-0204105
   (State or other jurisdiction of                         (I.R.S. Employer
    incorporation or organization)                         Identification No.)

  8 Inverness Drive East, Suite 100, Englewood, CO              80112
     (Address of principal executive offices)                 (Zip Code)

       Registrant's telephone number, including area code: (303) 483-0044

         Securities registered under Section 12(b) of the Exchange Act:

    Title of each class                Name of each exchange on which registered
COMMON STOCK, $0.0001 PAR VALUE                AMERICAN STOCK EXCHANGE

      Securities registered under Section 12(g) of the Exchange 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 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 the 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. [ ]

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. (Check
one):

Large accelerated filer __     Accelerated filer X      Non-accelerated filer __

Indicate by check mark whether the  registrant is a shell company (as defined in
Rule 12b-2 of the Act). Yes __ No X -



<PAGE>


As of June 30, 2006,  approximately 78,766,808 shares of Common Stock, par value
$0.0001  per share  were  outstanding,  and the  aggregate  market  value of the
outstanding  shares of Common  Stock of the Company held by  non-affiliates  was
approximately  $341,847,947  based on a closing price of $4.34 per share,  which
was the  closing  price per share on June 30,  2006.  As of February  27,  2007,
86,100,015 shares of Common Stock, par value $0.0001 per share were outstanding.

                      Documents incorporated by reference:

Certain  information  required  by Items  10,  11,  12, 13 and 14 of Part III is
incorporated  by reference from portions of the  registrant's  definitive  proxy
statement relating to its 2007 annual meeting of stockholders to be filed within
120 days after December 31, 2006.


<PAGE>


                                Table of Contents

                                     Part I

Item 1.  Business..............................................................2
           Business of Gasco...................................................2
           History.............................................................2
           Acquisition, Exploration and Development Expenses.................. 3
           Principal Products or Services and Markets......................... 4
           Competitive Business Conditions, Competitive Position in the
              Industry and Methods of Competition..............................4
           Governmental Regulations and Environmental Laws.....................5
           Number of Total Employees and Number of Full-Time Employees.........7
           Available Information...............................................7
           Cautionary Statement Regarding Forward-Looking Statements...........7

Item 1 A.Risk Factors..........................................................9

Item 1 B.Unresolved Staff Comments............................................21

Item 2.  Properties...........................................................22
          Petroleum and Natural Gas Properties................................22
          Company Reserve Estimates...........................................25
          Volumes, Prices and Operating Expenses..............................26
          Development, Exploration and Acquisition Capital Expenditures.......26
          Productive Gas Wells................................................27
          Oil and Gas Acreage.................................................27
          Drilling Activity...................................................28
          Office Space........................................................29

Item 3.  Legal Proceedings....................................................29

Item 4.  Submission of Matters to a Vote of Security Holders..................29

                                     Part II

Item 5.  Market for Registrant's Common Equity, Related Stockholder Matters and
           Issuer Purchases of Equity Securities..............................30
           Securities Transactions............................................30

Item 6.  Selected Financial Data..............................................31

Item 7.  Management's Discussion and Analysis of Financial Condition and Results
            of Operations.....................................................31
          Forward Looking Statements..........................................31
          Overview............................................................31
          Recent Developments.................................................32
          Liquidity and Capital Resources.....................................37
          Capital Budget......................................................38
          Schedule of Contractual Obligations.................................39
          Critical Accounting Policies and Estimates..........................39

<PAGE>

          Results of Operations...............................................42
          Recent Accounting Pronouncements....................................45

Item 7A.Quantitative and Qualitative Disclosures about Market Risk............47

Item 8. Financial Statements and Supplementary Data...........................48

Item 9. Changes in and Disagreements with Accountants on Accounting and
           Financial Disclosure...............................................91

Item 9A.Controls and Procedures...............................................91

Item 9B.Other Information.....................................................94

                           Part III

Item 10.Directors, Executive Officers and Corporate Governance................94

Item 11.Executive Compensation................................................94

Item 12.Security Ownership of Certain Beneficial Owners and Management and
           Related Stockholder Matters........................................95

Item 13.Certain Relationships and Related Transactions and Director
           Independence.......................................................95

Item 14.Principal Accounting Fees and Services................................95

Item 15.Exhibits, Financial Statement Schedules...............................95










<PAGE>

PART I

ITEM 1 - BUSINESS

Business of Gasco

Gasco  Energy,   Inc.   ("Gasco,"  "the  Company,"  "we,"  "our"  or  "us")  was
incorporated  under  the laws of the  State of  Nevada  on  April  21,  1997 and
operated as a "shell"  company until  December 31, 1999.  Gasco is a natural gas
and  petroleum  exploitation,  development  and  production  company  engaged in
locating and developing hydrocarbon  resources,  primarily in the Rocky Mountain
region. Our principal business strategy is to enhance stockholder value by using
technologies  new to a specific  area to  generate  and  develop  high-potential
exploitation  resources in this area. Our principal  business is the acquisition
of leasehold  interests in petroleum and natural gas rights,  either directly or
indirectly,  and the exploitation and development of properties subject to these
leases. We are currently  focusing our drilling efforts in the Riverbend Project
located  in the  Uinta  Basin  of  northeastern  Utah,  targeting  the  Wasatch,
Mesaverde and Blackhawk  formations.  As of December 31, 2006, we held interests
in 256,429 gross acres (121,440 net acres) located in Utah, Wyoming,  California
and Nevada.  As of December 31, 2006, we held an interest in 81 gross  producing
wells (50.8 wells,  net to our interest) and 16 shut-in wells (15.4 net) located
on these properties.

During 2006 we spudded 30 gross  wells (18.5 net) and reached  total depth on 29
gross wells (18.0 net) in the Riverbend Project.  Initial completion  operations
were  conducted  on 26  wells  (16.5  net)  and 16 well  bores  (8.0  net)  were
re-entered to complete  behind-pipe  pay. During 2006, we also spudded two wells
in Gasco's Wyoming  projects.  As of December 31, 2006,  Gasco operated 77 gross
wells with two additional  wells awaiting  completion  activities.  All 77 gross
wells are currently producing.  Currently,  we are operating three drilling rigs
in the Riverbend Project and expect delivery of a fourth rig at the end of March
2007.

History

Gasco (formerly known as San Joaquin  Resources Inc.  ("SJRI")) was incorporated
on April 21, 1997 under the laws of the State of Nevada, as "LEK  International,
Inc." The Company  operated as a "shell"  company until December 31, 1999,  when
the Company combined with San Joaquin Oil & Gas Ltd., a Nevada corporation ("Oil
& Gas").  As a  result  of that  transaction,  Oil & Gas  became a wholly  owned
subsidiary of Gasco.

In February  2001,  a  subsidiary  of the Company  merged with Gasco  Production
Company  (formerly  known  as  Pannonian  Energy,   Inc.)  ("GPC"),   a  private
corporation  incorporated  under the laws of the State of  Delaware.  GPC was an
independent   energy  company  engaged  in  the  exploration,   development  and
acquisition  of crude oil and natural gas reserves in the western United States.
Prior to closing of the merger GPC divested  itself of all assets not associated
with  its  "Riverbend"  area  of  interest  (the  "non-Riverbend  assets").  The
"spin-offs"  were accounted for at the recorded  amounts.  The net book value of
the  non-Riverbend  assets in the United States  transferred,  including cash of
$1,000,000  and  liabilities  of $555,185,  was  approximately  $1,850,000.  The
non-Riverbend assets located outside of the United States were held by Pannonian


                                       2
<PAGE>

International  Ltd.  ("PIL"),  the shares of which were  distributed  to the GPC
stockholders.  The net  book  value of PIL as of the  date of  distribution  was
approximately $174,000.

Certain  shareholders of SJRI  surrendered  for  cancellation  2,438,930  common
shares  of  the  Company's  capital  stock  on  completion  of  the  transaction
contemplated by the GPC Agreement.

Upon completion of the transaction,  GPC became a wholly owned subsidiary of the
Company.  However,  since this transaction resulted in the existing shareholders
of GPC acquiring control of the Company,  for financial  reporting  purposes the
business  combination is accounted for as a reverse  acquisition with GPC as the
accounting acquirer.

Acquisition, Exploration and Development Expenses

During the years ended December 31, 2006 and 2005, the Company spent $87,270,883
and  $50,069,968,  respectively  for  acquisitions,  development and exploration
activities.  During  2006,  the  Company  completed  a property  acquisition  of
approximately 21 miles of mainline gathering  pipelines and working interests in
24 oil and gas  wells  in the  Uinta  Basin  of Utah  for  $4,875,000,  which is
included in the total expenditures for 2006.

On September  20, 2006,  Gasco entered into an agreement to purchase Brek Energy
Corporation  ("Brek") for equity  consideration  of 11,000,000  shares of common
stock of the Company valued at  approximately  $30,000,000  based on the closing
price of Gasco's stock on September  20, 2006.  As a result of this  acquisition
("Brek  Acquisition"),  Gasco will acquire approximately 17,095 net acres in the
Uinta Basin of Utah and approximately  12,495 net acres in the Green River Basin
of Wyoming. The acquisition is expected to simplify Gasco's acreage portfolio by
absorbing a working interest partner that previously owned  approximately 14% of
Gasco's undeveloped acreage in Utah and Wyoming.  Gasco does not expect to incur
any additional  overhead expenses as a result of the acquisition.  The boards of
directors  of  both  Brek  and  Gasco  have  each  approved  the  terms  of  the
transaction,  which is expected to close during the second  quarter of 2007. The
completion of the transaction is subject to the approval of the  stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.

Under the terms of the  transaction,  a  wholly-owned  subsidiary  of Gasco will
merge  with and into  Brek.  As a  result  of the  merger,  Brek  will  become a
wholly-owned  subsidiary  of Gasco and each  stockholder  of Brek will receive a
number of shares of common  stock of Gasco  equal to  11,000,000  divided by the
total  number of shares of common stock of Brek  outstanding  on the date of the
merger,  calculated on a fully diluted basis.  As part of the  transaction,  the
directors of Brek, who collectively own approximately 24% of Brek's  outstanding
stock,  have  entered  into an  agreement  to vote their  shares in favor of the
transaction.  In addition,  Brek's President and CEO, who owns approximately 18%
of the outstanding common stock of Brek, has agreed to deposit 550,000 shares of
Gasco common stock  acquired in the  transaction in escrow to satisfy any claims
with respect to breaches of representations and warranties of Brek.



                                       3
<PAGE>




Principal Products or Services and Markets

Gasco  focuses its  exploitation  activities  on locating  natural gas and crude
petroleum.   The  principal  markets  for  these  commodities  are  natural  gas
transmission pipeline and marketing companies, utilities, refining companies and
private industry end-users. Historically, nearly all of the Company's sales have
been to a few  customers.  During the years ended  December 31,  2006,  2005 and
2004,  over  90% of our  production  was sold to one  customer,  ConocoPhillips.
However,  Gasco does not believe that the loss of a single purchaser,  including
ConocoPhillips, would materially affect the Company's business because there are
numerous  other  potential  purchasers  in the  areas in which  Gasco  sells its
production.  For the years ended December 31, 2006, 2005 and 2004,  purchases by
the  following  company  exceeded  10% of the total oil and gas  revenues of the
Company.
<TABLE>
<CAPTION>

                                                           Percent of Production Purchased
                                                          For the Years Ended December 31,
                                               --------------------------------------------------------
                                                      2006               2005               2004
                                                      ----               ----               ----

<S>                                                   <C>                 <C>               <C>
   ConocoPhillips                                     94%                 96%               93%
   Revenues associated with these purchases    $19,777,000         $13,506,000        $2,905,000
</TABLE>

Competitive  Business  Conditions,  Competitive  Position  in the  Industry  and
Methods of Competition

The Company's natural gas and petroleum  exploration  activities take place in a
highly  competitive and speculative  business  atmosphere.  In seeking  suitable
natural gas and petroleum  properties  for  acquisition,  Gasco  competes with a
number of other  companies  operating in its areas of interest,  including large
oil and gas companies and other independent operators with greater financial and
other resources.  Management does not believe that Gasco's competitive  position
in the petroleum and natural gas industry will be significant.

Management  anticipates  a  competitive  market for hiring  field and  technical
personnel  and obtaining  drilling rigs and services.  The current high level of
drilling activity in Gasco's areas of exploration may have a significant adverse
impact on the timing and profitability of Gasco's  operations.  In addition,  as
discussed  under "Item 1A - Risk Factors,"  Gasco is required to obtain drilling
and right of way  permits  for its wells,  and there is no  assurance  that such
permits will be available timely or at all.

The prices of the  Company's  products  are  controlled  by  domestic  and world
markets.  However,  competition  in the  petroleum  and natural gas  exploration
industry also exists in the form of  competition  to acquire the most  promising
acreage  blocks and obtaining the most  favorable  prices for  transporting  the
product.  Gasco,  and ventures in which it  participates,  are relatively  small
compared to other petroleum and natural gas exploration companies.  As a result,
we may have difficulty  acquiring  additional  acreage and/or projects,  and may
have difficulty  arranging for the  transportation  of the oil or natural gas we
produce.

                                       4
<PAGE>

Governmental Regulations and Environmental Laws

We are  subject to  stringent  federal,  state,  and local laws and  regulations
governing the discharge of materials into the environment or otherwise  relating
to  environmental  protection.  These  laws  and  regulations  may  require  the
acquisition of permits before drilling  commences,  limit or prohibit operations
on environmentally  sensitive lands such as wetlands or wilderness areas, result
in capital  expenditures to limit or prevent emissions or discharges,  and place
restrictions on the management of wastes.  Failure to comply with these laws and
regulations may result in the assessment of  administrative,  civil and criminal
penalties,  the  imposition  of  remedial  obligations,   and  the  issuance  of
injunctive relief. Any changes in environmental laws and regulations that result
in more stringent and costly waste  handling,  disposal or cleanup  requirements
could have a material adverse effect on our operations. While we believe that we
are in substantial  compliance with current  environmental  laws and regulations
and that continued  compliance with existing  requirements  would not materially
affect us, there is no assurance that this trend will continue in the future.

The  Comprehensive  Environmental  Response,  Compensation and Liability Act, as
amended, also known as "CERCLA" or "Superfund," and comparable state laws impose
liability  without regard to fault or the legality of the original  conduct,  on
certain  classes of persons who are considered to be responsible for the release
of a hazardous substance into the environment.  Under CERCLA, these "responsible
persons" may be subject to joint and several liability for the costs of cleaning
up the hazardous  substances that have been released into the  environment,  for
damages to natural resources,  and for the costs of certain health studies,  and
it is not uncommon for  neighboring  landowners  and other third parties to file
claims for personal injury and property damage  allegedly  caused by the release
of hazardous substances into the environment.  We also may incur liability under
the Resource  Conservation and Recovery Act, also known as "RCRA", which imposes
requirements  relating to the  management  and  disposal of solid and  hazardous
wastes.  While there exists an exclusion from the definition of hazardous wastes
for "drilling  fluids,  produced  waters,  and other wastes  associated with the
exploration,  development, or production of crude oil, natural gas or geothermal
energy," in the course of our operations,  we may generate  ordinary  industrial
wastes,  including paint wastes, waste solvents,  and waste compressor oils that
may be regulated as hazardous waste.

We currently own or lease, and have in the past owned or leased, properties that
for a number of years have been used for the  exploration  and production of oil
and gas.  Although we have utilized  operating and disposal  practices that were
standard in the industry at the time, hydrocarbons or other wastes may have been
disposed of or released on or under the  properties  owned or leased by us or on
or under other  locations  where such wastes  have been taken for  disposal.  In
addition, some of these properties may have been operated by third parties whose
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,
and  analogous  state laws.  Under such laws,  we could be required to remove or
remediate  previously  disposed wastes or property  contamination  or to perform
remedial operations to prevent future contamination.

The Federal Water Pollution  Control Act of 1972, as amended,  also known as the
"Clean  Water Act" and  analogous  state  laws  impose  restrictions  and strict
controls  regarding the discharge of pollutants,  including  produced waters and
other oil and gas  wastes,  into  state or  federal  waters.  The  discharge  of
pollutants into regulated waters is prohibited,  except in accord with the terms


                                       5
<PAGE>

of a permit issued by EPA or the state.  The Clean Water Act provides  civil and
criminal  penalties for any discharge of oil in harmful  quantities  and imposes
liabilities for the costs of removing an oil spill.

The Clean Air Act, as amended ("CAA"),  restricts the emission of air pollutants
from many  sources,  including oil and gas  operations.  New  facilities  may be
required to obtain permits before work can begin, and existing facilities may be
required to incur capital costs in order to remain in  compliance.  In addition,
the EPA has promulgated more stringent  regulations governing emissions of toxic
air pollutants from sources in the oil and gas industry,  and these  regulations
may increase the costs of compliance for some facilities.

In response to  increasing  levels of concern that  emissions of certain  gases,
including  carbon dioxide  resulting  from  combustion of  hydrocarbons,  may be
contributing  to warming of the Earth's  atmosphere,  many foreign  nations have
agreed to limit emissions of these gases,  generally  referred to as "greenhouse
gases," pursuant to the United Nations  Framework  Convention on Climate Change,
also  known  as  the  "Kyoto  Protocol".  Although  the  United  States  is  not
participating  in the Kyoto  Protocol,  the  Congress  is  considering  numerous
proposals for climate control  legislation,  including bills that could restrict
greenhouse  gas  emissions.  In addition,  several  states have already  adopted
legislation,  regulations  and/or regulatory  initiatives to reduce emissions of
greenhouse  gases.  Also,  on November 29, 2006,  the U.S.  Supreme  Court heard
arguments  on a case  appealed  from the U.S.  Circuit  Court of Appeals for the
District  Columbia,  Massachusetts,  et al. v. EPA, in which the appellate court
held that the U.S.  Environmental  Protection  Agency had  discretion  under the
federal Clean Air Act to refuse to regulate carbon dioxide emissions from mobile
sources.  Passage of climate control  legislation by Congress or a Supreme Court
reversal of the appellate  decision could result in federal regulation of carbon
dioxide emissions and other greenhouse gases. Any federal or state  restrictions
on emissions of greenhouse  gases that may be imposed in the United States could
adversely affect our operations and the demand for our products.

Under the National  Environmental  Policy Act  ("NEPA"),  a federal  agency,  in
conjunction  with a permit holder,  may be required to prepare an  environmental
assessment or a detailed environmental impact statement, also known as an "EIS,"
before  issuing  a permit  that may  significantly  affect  the  quality  of the
environment. We are currently working with the U.S. Bureau of Land Management or
"BLM" regarding the  preparation of an EIS in connection  with certain  proposed
exploration and production operations in the Uinta Basin of Utah. We expect that
the EIS will take  approximately  18 to 24 months to  complete,  at an estimated
cost to us of about $500,000.  Until the EIS is completed and issued by the BLM,
we will be  limited  in the number of oil and gas wells that we can drill in the
areas  undergoing  EIS  review.  To add  further  assurance  that  we  will  not
experience a significant  curtailment,  we signed a Memorandum of  Understanding
with the BLM during the first half of 2005 that allows us to  continue  drilling
while the EIS is being  completed.  While we do not expect  that the EIS process
will result in a significant  curtailment in future oil and gas production  from
this particular  area, we can provide no assurance  regarding the outcome of the
EIS process.



                                       6
<PAGE>



Number of Total Employees and Number of Full-Time Employees

As of February 27, 2007, Gasco had 21 full-time employees.

Available Information

Our Internet website is  http://www.gascoenergy.com  and you may access, free of
charge,  through  the  Investor  Relations  portion of our  website,  our annual
reports on Form 10-K,  quarterly  reports on Form 10-Q,  current reports on Form
8-K and amendments to such reports filed or furnished  pursuant to Section 13(a)
or  15(d)  of the  Securities  Exchange  Act of  1934,  as  amended,  as soon as
reasonably  practicable  after we  electronically  file such  material  with, or
furnish it to, the SEC. Information contained on our website is not part of this
report.

              CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some  of  the  information  in  this  annual  report  contains   forward-looking
statements  within the  meaning of Section  27A of the  Securities  Act of 1933,
Section  21E of the  Private  Securities  Litigation  Reform Act of 1995.  These
statements  express,  or are based on, our  expectations  about  future  events.
Forward-looking  statements give our current expectations or forecasts of future
events.  Forward-looking  statements  generally  can be identified by the use of
forward  looking   terminology  such  as  "may,"  "will,"  "expect,"   "intend,"
"project,"  "estimate,"  "anticipate,"  "believe" or  "continue" or the negative
thereof or similar terminology. They include statements regarding our:

          o    financial position;

          o    business strategy;

          o    budgets;

          o    amount, nature and timing of capital expenditures;

          o    estimated reserves of natural gas and oil;

          o    drilling of wells;

          o    acquisition and development of oil and gas properties;

          o    timing and amount of future production of natural gas and oil;

          o    operating costs and other expenses;

          o    cash flow and anticipated liquidity;

          o    future operating results;

          o    marketing of oil and natural gas;

                                       7
<PAGE>


          o    competition and regulation; and

          o    plans, objectives and expectations.

Although we believe the expectations and forecasts  reflected in these and other
forward-looking  statements are  reasonable,  we can give no assurance they will
prove to have been correct. They can be affected by inaccurate assumptions or by
known or  unknown  risks and  uncertainties.  Factors  that could  cause  actual
results to differ  materially  from expected  results are described  under "Risk
Factors" and include:

          o    delays in obtaining drilling permits;

          o    uncertainties in the availability of distribution  facilities for
               our natural gas;

          o    general economic conditions;

          o    natural gas and oil price volatility;

          o    the fluctuation in the demand for natural gas and oil;

          o    uncertainties in the projection of future rates of production and
               timing of development expenditures;

          o    operating hazards attendant to the natural gas and oil business;

          o    climatic conditions;

          o    the risks associated with exploration;

          o    our ability to generate sufficient cash flow to operate;

          o    availability of capital;

          o    the strength and financial resources of our competitors;

          o    downhole  drilling and  completion  risks that are  generally not
               recoverable from third parties or insurance;

          o    actions or inactions of third-party operators of our properties;

          o    environmental risks;

          o    regulatory developments;

          o    potential  mechanical failure or under-performance of significant
               wells;

          o    availability and cost of services, material and equipment;

                                       8
<PAGE>

          o    our ability to find and retain skilled personnel;

          o    the lack of liquidity of our common stock; and

          o    our ability to eliminate any material  weaknesses in our internal
               controls over financial reporting.

Any of the  factors  listed  above and other  factors  contained  in this annual
report  could  cause our actual  results to differ  materially  from the results
implied by these or any other  forward-looking  statements  made by us or on our
behalf. We cannot assure you that our future results will meet our expectations.

When you  consider  these  forward-looking  statements,  you should keep in mind
these risk factors and the other  cautionary  statements in this annual  report.
Our forward-looking statements speak only as of the date made.

ITEM 1A. Risk Factors

Due to the nature of the Company's business and the present stage of exploration
on its oil and gas  prospects,  the  following  risk  factors  apply to  Gasco's
operations:

We have incurred  losses since our inception and may continue to incur losses in
the future.

To date our  operations  have not generated  sufficient  operating cash flows to
provide  working  capital  for our  ongoing  overhead,  the funding of our lease
acquisitions  and the exploration  and  development of our  properties.  Without
adequate  financing,  we may not be able to  successfully  develop any prospects
that we have or acquire and we may not achieve  profitability from operations in
the near future or at all.

During the years ended December 31, 2006,  2005 and 2004, we incurred a net loss
of $55,817,767,  $37,635 and $4,205,830,  respectively. As of December 31, 2006,
we  had  an  accumulated   deficit  of  $85,352,993.   Our  failure  to  achieve
profitability  in the future  could  adversely  affect the trading  price of our
common  stock  or  our  ability  to  raise  additional  capital.  Any  of  these
circumstances  could have a material  adverse effect on our financial  condition
and results of operations.

The  volatility  of  natural  gas and oil prices  could have a material  adverse
effect on our business.

Our revenue,  profitability  and cash flow depend upon the prices and demand for
natural  gas and oil.  Moreover,  changes in natural  gas and oil prices  have a
significant  impact  on the  value  of  our  reserves.  The  markets  for  these
commodities  are very  volatile and even  relatively  modest drops in prices can
significantly  affect our  financial  results and impede our growth.  Prices for
natural gas and oil may fluctuate  widely in response to a variety of additional
factors that are beyond our control, such as:

     o  changes in global supply and demand for natural gas and oil;

                                       9
<PAGE>

     o  commodity processing, gathering and transportation availability;

     o  domestic and global political and economic conditions;

     o  the  ability of members of the  Organization  of  Petroleum  Exporting
        Countries to agree to and maintain oil price and production controls;

     o  weather conditions, including hurricanes;

     o  technological advances affecting energy consumption;

     o  domestic and foreign governmental regulations; and

     o  the price and availability of alternative fuels.

Lower  natural  gas and oil prices may not only  decrease  our  revenue on a per
share  basis,  but also may reduce the amount of natural gas and oil that we can
produce  economically.   This  reduction  may  result  in  our  having  to  make
substantial downward adjustments to our estimated proved reserves.

All of our natural gas production is currently located in, and all of our future
natural gas  production  is  anticipated  to be located  in, the Rocky  Mountain
Region of the United States.  The gas prices that we and other  operators in the
Rocky  Mountain  region  have  received  and are  currently  receiving  are at a
discount to gas prices in other  parts of the  country.  Factors  that can cause
price volatility for crude oil and natural gas within this region are:

     o    the  availability  of gathering  systems with  sufficient  capacity to
          handle local production;

     o    seasonal fluctuations in local demand for production;

     o    local and national gas storage capacity;

     o    interstate pipeline capacity; and

     o    the  availability and cost of gas  transportation  facilities from the
          Rocky Mountain region.

In  addition,  because of our size we do not own or lease firm  capacity  on any
interstate  pipelines.  As a result, our  transportation  costs are particularly
subject  to  short-term  fluctuations  in  the  availability  of  transportation
facilities.  Our  management  believes that the steep  discount in the prices it
receives may be due to pipeline  constraints out of the region,  but there is no
assurance  that  increased  capacity  will  improve the prices to levels seen in
other parts of the country in the future. Even if we acquire additional pipeline
capacity, conditions may not improve due to other factors listed above.

                                       10
<PAGE>

It is impossible to predict  natural gas and oil price movements with certainty.
Lower  natural gas and oil prices may not only  decrease  our  revenues on a per
unit basis but also may  reduce  the  amount of natural  gas and oil that we can
produce  economically.  A substantial or extended decline in natural gas and oil
prices would  materially  and adversely  affect our future  business,  financial
condition,  results of  operations,  liquidity  and  ability to finance  planned
capital  expenditures.  Further,  oil  prices  and  natural  gas  prices  do not
necessarily move together.

Pipeline  constraints  may limit our ability to sell our gas  production and may
negatively affect the price at which we sell our gas.

Gasco's  production  is  transported  through a single  intrastate  pipeline and
therefore  any  constraints  on the capacity of this  pipeline  could  adversely
affect  our  ability  to sell  our  production.  Additionally,  many  pipelines,
particularly those connecting to higher - priced eastern markets,  are operating
at or near capacity.  Management believes that this situation could continue, at
least, into early 2008. In certain  circumstances  this may limit our ability to
sell any, or all, of our natural gas production in a given period.  As producers
vie one with another to sell their gas, this  situation may also serve to reduce
the price at which we are able to sell the gas that does flow.  A  reduction  in
the  amount of natural  gas that we can sell or the price at which such  natural
gas can be sold could  materially  adversely  affect our financial  position and
results of operation.

Our oil and gas reserve  information is estimated and may not reflect our actual
reserves.

Estimating  accumulations  of gas and oil is complex and is not exact because of
the  numerous  uncertainties  inherent in the  process.  The  process  relies on
interpretations of available geological, geophysical, engineering and production
data. The extent,  quality and  reliability of this technical data can vary. The
process also requires certain economic  assumptions,  some of which are mandated
by the SEC, such as gas and oil prices, drilling and operating expenses, capital
expenditures,  taxes  and  availability  of  funds.  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; and

     o    the judgment of the persons preparing the estimate.

The  estimated  proved  reserve  information  as of December 31, 2006,  included
herein is based on estimates prepared by Netherland,  Sewell & Associates, Inc.,
independent petroleum engineers.

The most accurate method of determining proved reserve estimates is based upon a
decline  analysis  method,  which  consists of  extrapolating  future  reservoir
pressure and production from historical  pressure  decline and production  data.
The accuracy of the decline analysis method generally  increases with the length
of the production history.  Since most of our wells had been producing less than
six years as of December  31,  2006,  their  production  history was  relatively
short, so other  (generally less accurate)  methods such as volumetric  analysis
and analogy to the  production  history of wells of other  operators in the same


                                       11
<PAGE>

reservoir were used in conjunction with the decline analysis method to determine
our estimates of proved  reserves.  As our wells are produced over time and more
data is available,  the estimated  proved  reserves will be  redetermined  on an
annual basis and may be adjusted  based on that data.  These  adjustments  could
result in downward revisions of our reserve estimates.

Actual  future  production,  gas and oil prices,  revenues,  taxes,  development
expenditures,  operating  expenses and  quantities  of  recoverable  gas and oil
reserves  most likely will vary from our  estimates.  Any  significant  variance
could  materially  affect the quantities  and present value of our reserves.  In
addition,  we may adjust  estimates  of proved  reserves  to reflect  production
history,  results of  exploration  and  development  and  prevailing gas and oil
prices.  Our  reserves  may also be  susceptible  to  drainage by  operators  on
adjacent properties.

It  should  not be  assumed  that the  present  value of future  net cash  flows
included herein is the current market value of our estimated  proved gas and oil
reserves.  In accordance with SEC requirements,  we generally base 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.

Future changes in commodity prices or our estimates and operational developments
may result in impairment charges.

We may be  required  to  write  down  the  carrying  value  of our  gas  and oil
properties  when gas and oil prices are low or if there is substantial  downward
adjustments  to the  estimated  proved  reserves,  increases in the estimates of
development costs or deterioration in the exploration results.

We follow the full cost method of accounting,  under which,  capitalized gas and
oil property costs less  accumulated  depletion and net of deferred income taxes
may not exceed an amount  equal to the  present  value,  discounted  at 10%,  of
estimated  future net revenues  from proved gas and oil reserves less the future
cash outflows  associated with the asset  retirement  obligations that have been
accrued on the balance sheet plus the cost, or estimated fair value, if lower of
unproved properties.

Should capitalized costs exceed this ceiling, an impairment would be recognized.
The  present  value of  estimated  future net  revenues  is computed by applying
current prices of gas and oil to estimated  future  production of proved gas and
oil reserves as of period-end, less estimated future expenditures to be incurred
in developing and producing the proved  reserves  assuming the  continuation  of
existing  economic  conditions.  Once an impairment of gas and oil properties is
recognized,  it is not  reversible  at a later  date  even if oil or gas  prices
increase. As of June 30, 2006, the Company's full cost pool exceeded the ceiling
limitation  based on oil and gas  prices of $59.87 per barrel and $5.42 per Mcf.
Subsequent  commodity  price increases were not sufficient to eliminate the need
for the impairment and therefore, impairment expense of $51,000,000 was recorded
during the quarter ended June 30, 2006.

                                       12
<PAGE>

The development of oil and gas properties  involves  substantial  risks that may
materially and adversely affect us.

The business of exploring  for and  producing oil and gas involves a substantial
risk of investment  loss that even a combination  of  experience,  knowledge and
careful  evaluation  may not be able to  overcome.  Drilling  oil and gas  wells
involves  the risk  that  the  wells  will be  unproductive  or  that,  although
productive,  the wells do not  produce  oil and/or gas in  economic  quantities.
Other hazards, such as unusual or unexpected geological  formations,  pressures,
fires, blowouts,  loss of circulation of drilling fluids or other conditions may
substantially   delay  or  prevent  completion  of  any  well.  Adverse  weather
conditions can also hinder drilling operations.

A productive well may become  uneconomic in the event water or other deleterious
substances are encountered, which impair or prevent the production of oil and/or
gas from the well. In addition,  production from any well may be unmarketable if
it is contaminated with water or other deleterious substances.

If we  experience  any one or more  of  these  risks,  our  business,  financial
condition and results of operations could be materially and adversely affected.

We may not be able to obtain adequate financing to continue our operations.

We have relied in the past  primarily on the sale of equity capital and farm-out
and  other  similar  types  of  transactions  to fund  working  capital  and the
acquisition of our prospects and related leases.  Failure to generate  operating
cash flow or to obtain additional financing could result in substantial dilution
of our property interests,  or delay or cause indefinite postponement of further
exploration  and  development  of our  prospects  with the possible  loss of our
properties.

We will require significant additional capital to fund our future activities and
to  service  current  and  any  future  indebtedness.  In  particular,  we  face
uncertainties  relating to our ability to  generate  sufficient  cash flows from
operations  to fund the level of capital  expenditures  required for our oil and
gas  exploration  and production  activities and our  obligations  under various
agreements with third parties relating to exploration and development of certain
prospects.  Our failure to find the  financial  resources  necessary to fund our
planned  activities and service our debt and other  obligations could materially
and  adversely  affect  our  business,   financial   condition  and  results  of
operations.

Delays in obtaining  drilling permits could have a materially  adverse effect on
our ability to develop our properties in a timely manner.

The average processing time at the Bureau of Land Management in Vernal, Utah for
an application  to drill on federal leases has been  increasing and currently is
approximately  14  months.  Approximately  82% of our gross  acreage  in Utah is
located on federal leases.  If we are delayed in procuring  sufficient  drilling
permits for our federal  properties,  we will shift more of our drilling in Utah
to our state leases, the permits for which require an average processing time of
approximately two months.  While such a shift in resources would not necessarily
affect the rate of growth of our cash flow,  it would result in a slower  growth
rate of our total  proved  reserves,  because a higher  percentage  of the wells
drilled  on the  state  leases  will  be  drilled  on  leases  to  which  proved
undeveloped reserves my already have been attributed.

                                       13
<PAGE>

We may have difficulty managing growth in our business.

Because of our small size,  growth in  accordance  with our business  plans,  if
achieved,  will  place  a  significant  strain  on  our  financial,   technical,
operational and management  resources.  As we expand our activities and increase
the number of projects we are evaluating or in which we participate,  there will
be additional demands on our financial,  technical and management resources. The
failure to continue  to upgrade our  technical,  administrative,  operating  and
financial   control   systems  or  the   occurrence  of   unexpected   expansion
difficulties,  including the recruitment and retention of experienced  managers,
geoscientists  and  engineers,  could  have a  material  adverse  effect  on our
business,  financial  condition  and  results of  operations  and our ability to
timely execute our business plan.

We compete with larger  companies  in acquiring  properties  and  operating  and
drilling services.

Our  natural gas and  petroleum  exploration  activities  take place in a highly
competitive and speculative business atmosphere. In seeking suitable natural gas
and  petroleum  properties  for  acquisition,  we compete with a number of other
companies  operating  in our  areas of  interest,  including  large  oil and gas
companies  and other  independent  operators  with greater  financial  and other
resources.  We do not believe that our competitive position in the petroleum and
natural gas industry is significant.

We anticipate a competitive market for obtaining drilling rigs and services, and
the manpower to operate them. The current high level of drilling activity in our
areas of  exploration  may have a significant  adverse  impact on the timing and
profitability of our operations. In addition, we are required to obtain drilling
and right of way  permits  for our wells,  and there is no  assurance  that such
permits will be available on a timely basis or at all.

We may suffer losses or incur  liability for events that we or the operator of a
property have chosen not to insure against.

Insurance  against every operational risk is not available at economic rates. We
may suffer  losses from  uninsurable  hazards or from  hazards,  which we or the
operator  have chosen not to insure  against  because of high  premium  costs or
other  reasons.  We  may  become  subject  to  liability  for  pollution,  fire,
explosion,  blowouts, cratering and oil spills against which we cannot insure or
against  which  we  may  elect  not to  insure.  Such  events  could  result  in
substantial damage to oil and gas wells, producing facilities and other property
and personal  injury.  The payment of any such  liabilities  may have a material
adverse effect on our business, financial condition and results of operations.

We may incur losses as a result of title deficiencies in the properties in which
we invest.

If an  examination  of the title  history of a property  that we have  purchased
reveals a petroleum and natural gas lease that has been  purchased in error from
a person who is not the owner of the  mineral  interest  desired,  our  interest
would be worthless.  In such an instance, the amount paid for such petroleum and
natural gas lease or leases would be lost.

It is our practice,  in acquiring petroleum and natural gas leases, or undivided
interests  in  petroleum  and natural gas leases,  not to undergo the expense of
retaining  lawyers to examine  the title to the  mineral  interest  to be placed


                                       14
<PAGE>

under  lease or  already  placed  under  lease.  Rather,  we will  rely upon the
judgment of petroleum  and natural gas lease  brokers or landmen who perform the
fieldwork in examining  records in the  appropriate  governmental  office before
attempting to acquire a lease in a specific mineral interest.

If there are any title  defects in the  properties in which we hold an interest,
we may suffer a monetary loss, including as a result of performing any necessary
curative work prior to the drilling of a petroleum and natural gas well.

Our  ability  to market  the oil and gas that we  produce  is  essential  to our
business.

Several  factors  beyond our control may adversely  affect our ability to market
the oil and gas that we discover. These factors include the proximity,  capacity
and  availability  of oil and gas pipelines  and  processing  equipment,  market
fluctuations of prices, taxes, royalties,  land tenure, allowable production and
environmental  protection.  The  extent of these  factors  cannot be  accurately
predicted,  but any one or a  combination  of these  factors  may  result in our
inability  to sell our oil and gas at prices  that would  result in an  adequate
return on our invested  capital.  For example,  we currently  distribute the gas
that we  produce  through a single  pipeline.  If this  pipeline  were to become
unavailable,  we would incur additional costs to secure a substitute facility in
order to deliver the gas that we produce.  In  addition,  although we  currently
have  access  to  firm  transportation  for  the  majority  of our  current  gas
production,  there is no  assurance  that we will be able to procure  additional
transportation  on terms  satisfactory  to us,  or at all,  as we  increase  our
production through our drilling program or acquisitions.

We could become subject to certain  Questar  Pipeline  Company Gas  requirements
which, if such requirements are too strict, could result in our production being
severely curtailed or shut-in.

We currently  deliver all of our gathered  gas into a Questar  Pipeline  Company
("Questar") main line  transportation  system.  Questar is currently  evaluating
their  gas  quality  requirements  to  transport  gas  on  their  system.  These
requirements could and most likely, would be imposed on all companies delivering
gas into their  main line.  If Questar  should  require  companies  to meet more
strict  quality  requirements,  there is no assurance that we could meet the new
requirements in the short term future. It is possible that we would need to make
significant  capital  expenditures to retain these short term  arrangements that
allow a majority of our current gas production to access firm  transportation or
meet the new gas quality  requirements  and/or to transport our gas. During this
process and/or adding new  transportation  facilities,  our production  could be
severely curtailed or even shut -in completely.

Environmental costs and liabilities and changing environmental  regulation could
materially affect our cash flow.

Our  operations  are  subject  to  stringent  federal,  state and local laws and
regulations relating to environmental protection. These laws and regulations may
require the  acquisition of permits or other  governmental  approvals,  limit or
prohibit our operations on environmentally sensitive lands, and place burdensome
restrictions  on the management  and disposal of wastes.  Failure to comply with
these laws may result in the  assessment of  administrative,  civil and criminal


                                       15
<PAGE>

penalties,  the  imposition  of  remedial  obligations,   and  the  issuance  of
injunctions that may delay or prevent our operations.  Any stringent  changes to
these  environmental  laws and  regulations  may result in increased costs to us
with respect to the disposal of wastes, the performance of remedial  activities,
and the  incurrence  of capital  expenditures.  Please  read "Item 1 -Business -
Governmental Regulations and Environmental Laws," above.

We are subject to complex  governmental  regulations  which may adversely affect
the cost of our business.

Petroleum and natural gas exploration, development and production are subject to
various  types of  regulation by local,  state and federal  agencies.  We may be
required  to  make  large   expenditures   to  comply   with  these   regulatory
requirements.  Legislation  affecting  the petroleum and natural gas industry is
under constant review for amendment and expansion.  Also,  numerous  departments
and  agencies,  both federal and state,  are  authorized by statute to issue and
have  issued  rules and  regulations  binding on the  petroleum  and natural gas
industry and its individual members,  some of which carry substantial  penalties
for failure to comply.  Any increases in the regulatory  burden on the petroleum
and natural gas industry  created by new legislation  would increase our cost of
doing business and,  consequently,  adversely affect our profitability.  A major
risk  inherent  in  drilling  is the need to  obtain  drilling  and right of way
permits from local authorities. Delays in obtaining drilling and/or right of way
permits,  the failure to obtain a drilling and/or right of way permit for a well
or a permit  with  unreasonable  conditions  or costs  could  have a  materially
adverse effect on our ability to effectively develop our properties.

Our  competitors  may have  greater  resources  which could enable them to pay a
higher price for properties and to better withstand periods of low market prices
for hydrocarbons.

The petroleum and natural gas industry is intensely competitive,  and we compete
with other companies,  which have greater resources. Many of these companies not
only explore for and produce  crude  petroleum and natural gas but also carry on
refining  operations  and market  petroleum  and other  products  on a regional,
national  or  worldwide  basis.  Such  companies  may be  able to pay  more  for
productive  petroleum and natural gas  properties and  exploratory  prospects or
define,  evaluate,  bid for and  purchase  a greater  number of  properties  and
prospects  than our  financial or human  resources  permit.  In  addition,  such
companies may have a greater ability to continue  exploration  activities during
periods of low  hydrocarbon  market  prices.  Our ability to acquire  additional
properties  and to discover  reserves in the future will be  dependent  upon our
ability  to  evaluate  and  select   suitable   properties   and  to  consummate
transactions in a highly competitive environment.

Because our  reserves  and  production  are  concentrated  in a small  number of
properties,  production  problems or  significant  changes in reserve  estimates
related to any property could have a material impact on our business.

Our  current  reserves  and  production  primarily  come from a small  number of
producing  properties  in  Utah.  If  mechanical  problems  with  the  wells  or
production facilities including salt water disposal, pipelines,  compressors and
processing plants,  depletion or other events including weather adversely affect
any  particular  property,  we could  experience  a  significant  decline in our
production,  which  could  have a  material  adverse  effect on our cash  flows,
financial  condition  and  results of  operations.  In  addition,  if the actual
reserves associated with any one of our properties are less than estimated,  our
overall reserve estimates could be materially and adversely affected.

                                       16
<PAGE>

Financial  difficulties  encountered  by our partners or  third-party  operators
could adversely affect the exploration and development of our prospects.

Liquidity and cash flow problems encountered by our partners or the co-owners of
our properties may prevent or delay the drilling of a well or the development of
a project.  Our  partners  and working  interest  co-owners  may be unwilling or
unable to pay their  share of the costs of  projects  as they become due. In the
case of a  farm-out  partner,  we would have to find a new  farm-out  partner or
obtain alternative  funding in order to complete the exploration and development
of the  prospects  subject to the farm-out  agreement.  In the case of a working
interest owner, we could be required to pay the working  interest  owner's share
of the project  costs.  We cannot assure you that we would be able to obtain the
capital necessary to fund either of these contingencies or that we would be able
to find a new farm-out partner. If any of these circumstances were to occur, our
ability to explore and develop our prospects  could be adversely  affected which
could have a material  adverse effect on our business,  financial  condition and
results of operations.

Shortages  of  supplies,  equipment  and  personnel  may  adversely  affect  our
operations.

The natural gas and oil industry is cyclical and,  from time to time,  there are
shortages of drilling rigs, equipment,  supplies or qualified personnel.  During
these periods,  the costs of rigs,  equipment and supplies may be  substantially
increased and their  availability may be limited.  In addition,  the demand for,
and wage rates of, qualified  personnel,  including drilling rig crews, may rise
as the  number  of rigs in  service  increases.  If  drilling  rigs,  equipment,
supplies or qualified  personnel are unavailable to us due to excessive costs or
demand or  otherwise,  our ability to execute our  exploration  and  development
plans could be materially and adversely affected and, as a result, our business,
financial  condition and results of operations could be materially and adversely
affected.

Hedging our production may result in losses.

We currently have no hedging agreements in place.  However, we may in the future
enter into  arrangements  to reduce our exposure to  fluctuations  in the market
prices of oil and natural  gas. We may enter into oil and gas hedging  contracts
in order to  increase  credit  availability.  Hedging  will expose us to risk of
financial loss in some circumstances, including if:

     -    production is less than expected;

     -    the other party to the contract defaults on its obligations; or

     -    there is a change in the expected  differential between the underlying
          price in the hedging agreement and actual prices received.

In  addition,  hedging may limit the  benefit we would  otherwise  receive  from
increases in the prices of oil and gas. Further, if we do not engage in hedging,
we may be more  adversely  affected  by changes  in oil and gas prices  than our
competitors who engage in hedging.




                                       17
<PAGE>



Our credit  facility  imposes  restrictions on us that may affect our ability to
successfully operate our business.

Our credit facility imposes certain operational and financial restrictions on
us. These restrictions, among other things, limit our ability to:

     -    incur additional indebtedness;

     -    create liens;

     -    sell our assets or consolidate or merge with or into other companies;

     -    make investments and other restricted payments, including dividends;

     -    and engage in transactions with affiliates.

These  limitations  are  subject  to a number of  important  qualifications  and
exceptions.  In addition,  our credit facility  requires us to maintain  certain
financial ratios to satisfy certain  financial  conditions.  These  restrictions
could also limit our ability to obtain future  financings,  make needed  capital
expenditures, withstand a downturn in our business or the economy in general, or
otherwise  conduct  necessary  corporate  activities.  Our credit  facility  and
restrictions  there  under  are  described  in  greater  detail  in  "Item  7  -
Management's  Discussion  and  Analysis of  Financial  Condition  and Results of
Operations - Credit Facility."

Our success  depends on our key  management  personnel,  the loss of any of whom
could disrupt our business.

The success of our  operations  and  activities  is dependent  to a  significant
extent on the efforts and abilities of our  management.  The loss of services of
any of our key managers could have a material adverse effect on our business. We
have not obtained "key man" insurance for any of our management. Mr. Erickson is
the Chief Executive Officer, Mr. Decker is an Executive Vice President and Chief
Operating  Officer  and Mr.  Grant is an  Executive  Vice  President  and  Chief
Financial Officer.  The loss of their services may adversely affect our business
and prospects.

Our officers and directors are engaged in other  businesses  which may result in
conflicts of interest.

Certain of our officers and directors also serve as directors of other companies
or have  significant  shareholdings in other  companies.  Our chairman,  Marc A.
Bruner, is the largest  shareholder of Galaxy Energy Corporation  ("Galaxy") and
Exxcel  Energy.  Mr.  Bruner also  serves as the  Chairman  and Chief  Operating
Officer  of Falcon  Oil and Gas,  Ltd.  ("Falcon").  Falcon's  current  drilling
activities include projects in Romania and Hungary. Carl Stadelhofer, one of our
directors is a director of Falcon.  In addition,  another of our  directors,  C.
Tony Lotito,  currently serves as the Executive Vice President,  Chief Financial
Officer,  Secretary-Treasurer  and  a  member  of  the  Board  of  Directors  of
PetroHunter Corporation ("PetroHunter"),  which is majority owned by Mr. Bruner.
Charles Crowell, one of our directors also serves on the Boards' of Directors of
PetroHunter and of Providence Resources, Inc. Richard S. Langdon, another one of
our directors,  is President and Chief Executive  Officer of Matris  Exploration
Company,  L.P., a private E&P company active in onshore California.  Mr. Langdon


                                       18
<PAGE>

is also a member of the Board of Directors of Constellation  Energy Partners LLC
("CEP"),  a  public  limited  liability  company  focused  on  the  acquisition,
development  and  exploitation  of oil and  natural gas  properties  and related
midstream  assets.  CEP's activities are currently  focused in the Black Warrior
Basin of Alabama. Another one of our directors, Richard Burgess is a director of
ROC Oil  Company  ("ROC"),  a  Limited  Liability  Corporation  incorporated  in
Australia. ROC has oil and gas activities in China, Australia, UK North Sea, and
West Africa. ROC has no activities in North or South America. Mark Erickson, our
CEO,  President  and director has direct  private  investments  in certain Rocky
Mountain oil and gas leases and has a majority interest in a private oil and gas
company with core assets in Oklahoma and additional  lease holdings in Colorado,
Wyoming and Utah.

To the extent that such other companies  participate in ventures in which we may
participate,  or compete for  prospects  or financial  resources  with us, these
officers  and  directors  will have a conflict of interest  in  negotiating  and
concluding terms relating to the extent of such participation. In the event that
such a conflict of  interest  arises at a meeting of the board of  directors,  a
director  who has such a  conflict  must  disclose  the nature and extent of his
interest to the board of  directors  and abstain  from voting for or against the
approval of such participation or such terms.

In accordance  with the laws of the State of Nevada,  our directors are required
to act honestly and in good faith with a view to the best interests of Gasco. In
determining  whether or not we will participate in a particular  program and the
interest therein to be acquired by it, the directors will primarily consider the
degree of risk to which we may be exposed  and our  financial  position  at that
time.

It may be difficult to enforce  judgments  predicated on the federal  securities
laws on some of our board members who are not U.S. residents.

Two of our directors reside outside the United States and maintain a substantial
portion  of their  assets  outside  the  United  States.  As a result  it may be
difficult or  impossible to effect  service of process  within the United States
upon such persons, to bring suit in the United States or to enforce, in the U.S.
courts,  any judgment  obtained there against such persons  predicated  upon any
civil liability provisions of the U.S. federal securities laws.

Foreign  courts may not  entertain  original  actions  against our  directors or
officers  predicated  solely upon U.S.  federal  securities  laws.  Furthermore,
judgments  predicated  upon any civil liability  provisions of the U.S.  federal
securities laws may not be directly enforceable in foreign countries.

Risks Related to Our Capital Stock

Our  common  stock  has  experienced,  and may  continue  to  experience,  price
volatility and a low trading volume.

The trading price of our common stock has been and may continue to be subject to
large fluctuations, which may result in losses to investors. Our stock price may
increase or decrease in response to a number of events and factors, including:

                                       19
<PAGE>

     o    the results of our exploratory drilling;

     o    trends in our industry and the markets in which we operate;

     o    changes in the market price of the commodities we sell;

     o    changes in  financial  estimates  and  recommendations  by  securities
          analysts;

     o    acquisitions and financings;

     o    quarterly variations in operating results;

     o    the  operating and stock price  performance  of other  companies  that
          investors may deem comparable; and

     o    purchases or sales of blocks of our common stock.

This volatility may adversely affect the price of our common stock regardless of
our operating performance.  See "Item 5 - Market for Registrant's Common Equity,
Related  Stockholder  Matters and Issuer  Purchases  of Equity  Securities"  for
further discussion.

Shares  eligible for future sale may cause the market price for our common stock
to drop significantly, even if our business is doing well.

If our existing shareholders sell our common stock in the market, or if there is
a perception that  significant  sales may occur,  the market price of our common
stock could drop  significantly.  In such case, our ability to raise  additional
capital in the  financial  markets at a time and price  favorable to us might be
impaired.  In  addition,  our  board of  directors  has the  authority  to issue
additional  shares of our  authorized  but  unissued  common  stock  without the
approval of our  shareholders.  Additional  issuances  of our common stock would
dilute the  ownership  percentage  of existing  shareholders  and may dilute the
earnings  per  share  of our  common  stock.  As of  December  31,  2006  we had
86,100,015 shares of common stock issued and outstanding. Additional options may
be granted to purchase  1,895,000  shares of common stock under our stock option
plan and an  additional  474,200  shares of common stock are issuable  under our
restricted  stock plan. As of December 31 of each year,  the number of shares of
common stock  issuable  under our stock option plan  automatically  increases so
that the total  number of shares of common  stock  issuable  under  such plan is
equal to 10% of the total number of shares of common stock  outstanding  on such
date.

Assuming  all of our  outstanding  5.50%  Convertible  Senior Notes due 2011 are
converted  at the  applicable  conversion  prices,  the  number of shares of our
common stock  outstanding  would increase by approximately  16,250,000 shares to
approximately 101,217,792 shares (this number assumes no exercise of the options
or rights  described  above).  In  addition,  we  expect to issue an  additional
11,000,000  shares of our common stock to former holders of Brek common stock in
connection with the Brek Acquisition as well as additional  shares of our common
stock upon  exercise  of certain  Brek  options and  warrants  that we intend to
assume in connection with the Brek Acquisition.

                                       20
<PAGE>

We  have  not  previously  paid  dividends  on our  common  stock  and we do not
anticipate doing so in the foreseeable future.

We have not in the past paid,  and do not anticipate  paying in the  foreseeable
future,  cash  dividends  on our common  stock  because our  outstanding  credit
agreement  contains  covenants that restrict our ability to pay dividends on our
common stock. Additionally, any future decision to pay a dividend and the amount
of any dividend paid, if permitted,  will be made at the discretion of our board
of directors.

We have anti-takeover provisions in our certificate of incorporation and by-laws
that may discourage a change of control.

Our articles of incorporation  and bylaws contain several  provisions that could
delay or make more  difficult  the  acquisition  of us through a hostile  tender
offer,  open market purchases,  proxy contest,  merger or other takeover attempt
that a stockholder  might consider in his or her best interest,  including those
attempts  that might  result in a premium  over the  market  price of our common
stock.

Under the terms of our articles of  incorporation  and as permitted under Nevada
law, we have elected not to be subject to Nevada's  anti-takeover  law. This law
provides that specified  persons who,  together with  affiliates and associates,
own, or within three years did own, 15% or more of the outstanding  voting stock
of a corporation  could not engage in specified  business  combinations with the
corporation  for a period of three  years  after  the date on which  the  person
became an interested stockholder.  With the approval of our stockholders, we may
amend our  articles  of  incorporation  in the future to become  governed by the
anti-takeover  law. This provision would then have an  anti-takeover  effect for
transactions  not  approved  in  advance  by our board of  directors,  including
discouraging  takeover  attempts  that might result in a premium over the market
price for the shares of our common stock.

ITEM 1 B. UNRESOLVED STAFF COMMENTS

None.





                                       21
<PAGE>




ITEM 2 - PROPERTIES

Petroleum and Natural Gas Properties

Gasco is a natural gas and petroleum  exploitation,  development  and production
company engaged in locating and developing  hydrocarbon  resources  primarily in
the Rocky Mountain Region.  Gasco's  principal  business  strategy is to enhance
stockholder  value by using  technologies new to a specific area to generate and
develop  high-potential  exploitation  prospects  in this  area.  Our  principal
business is the acquisition of leasehold  interests in petroleum and natural gas
rights,  either directly or indirectly,  and the exploitation and development of
the properties subject to these leases.

The Company's  corporate strategy is to grow through drilling projects.  We have
been focusing our drilling efforts in the Riverbend Project located in the Uinta
Basin of  northeastern  Utah. The increased  drilling  activity in the Company's
areas of operations resulting from the higher oil and gas prices during 2005 and
through  the  first  quarter  of 2006 has also  decreased  the  availability  of
drilling rigs and experienced  personnel in this area and may continue to do so.
The  Company  also  continues  to incur  higher  drilling  and  operating  costs
resulting  from  the  increased  fuel and  steel  costs  and from the  increased
drilling activity in this area.

         Riverbend Project

The Riverbend Project comprises  approximately  124,041 gross acres in the Uinta
Basin of northeastern  Utah, of which we hold interests in approximately  74,657
net acres as of  December  31,  2006.  Our  engineering  and  geologic  focus is
concentrated  on three  tight-sand  formations in the Uinta basin:  the Wasatch,
Mesaverde  and  Blackhawk  formations.  A typical  well may  encounter  multiple
distinct natural gas sands located between  approximately  6,000 and 13,000 feet
in depth that are completed using up to ten staged fracs.

During 2006 we spudded 30 gross  wells (18.5 net) and reached  total depth on 29
gross wells (18.0 net). Initial completion operations were conducted on 26 wells
and 16 well bores were  re-entered to complete  behind-pipe  pay. As of December
31,  2006,  Gasco had 81 gross  wells on  production.  We  currently  have three
drilling rigs operating in the Uinta Basin Riverbend project,  and are expecting
delivery of our fourth rig at the end of March 2007.

During  August 2006,  Gasco  acquired  certain  gathering  assets and  producing
properties  associated with the Riverbend Project in the Uinta Basin of Utah for
a cash  purchase  price of  $4,875,000,  plus  settlement  for  production  from
effective date. The gathering  assets and properties are located entirely within
Gasco's existing Riverbend  leasehold allowing the Company to further capitalize
on economies of scale and  operating  efficiencies.  The  transaction  closed on
August 14, 2006, with an effective date of July 1, 2006.

During 2006, Gasco linked the Wilkin Ridge and West Desert gathering  systems to
its existing 50 MMcfd gas  processing  facility  which began  operations in June
2006.  Now, up to 95% of produced  volumes are processed in the plant,  ensuring
that production will meet pipeline specifications reducing the likelihood of any


                                       22
<PAGE>

future  curtailments due to gas quality.  The Company currently  operates nearly
100 miles of gathering system along with the processing facility.

Gasco recently received approval of its Riverbend Environmental Assessment (EA).
The approved EA includes 45 proposed wells within the Spring Canyon marine trend
of the Blackhawk  Formation.  The EA should provide for  accelerated  permitting
approvals from the Bureau of Land Management as the  environmental  and cultural
studies of the 45 proposed well sites have already been completed.

During 2004 we entered  into an  agreement  with a group of  industry  providers
(together,  the "Service  Parties") to accelerate the development of Gasco's oil
and gas  properties by drilling up to 50 wells in Gasco's  Riverbend  Project in
Utah's Uinta  Basin.  The  development  of this  project  typically  occurred in
increments of 10-well bundles. Under this agreement,  we drilled 12 wells during
2004,  10 wells  during 2005 and 10 wells  during 2006.  In February  2007,  the
Service  Parties did not approve  the fourth  bundle as proposed by Gasco.  As a
result,  Gasco and the Service  Parties are currently in discussions on a fourth
bundle.

We utilize the full cost method of accounting,  under which  capitalized oil and
gas property  costs less  accumulated  depletion,  net of deferred  income taxes
(full cost pool) may not exceed an amount equal to the present value, discounted
at 10%, of estimated  future net revenues  from proved oil and gas reserves less
the future cash outflows  associated with the asset retirement  obligations that
have been accrued in the balance sheet plus the cost,  or estimated  fair value,
if lower of  unproved  properties  and the  costs of any  properties  not  being
amortized,  if any. Should the full cost pool exceed this ceiling, an impairment
is  recognized.  This  impairment  is recorded  as  non-cash  expense and is not
permitted to be reversed in future  periods in the event that oil and gas prices
subsequently  increase  resulting  in a higher  ceiling.  The  present  value of
estimated  future net revenues is computed by applying current prices of oil and
gas to  estimated  future  production  of  proved  oil  and gas  reserves  as of
period-end,  less estimated future expenditures to be incurred in developing and
producing the proved reserves  assuming the  continuation  of existing  economic
conditions.  However,  subsequent  commodity  price increases may be utilized to
calculate the ceiling value.

As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53
per barrel,  the full cost pool would have exceeded the above described  ceiling
by $28,500,000.  However,  subsequent to year end, oil and gas prices increased;
and using these prices, the Company's full cost pool would not have exceeded the
ceiling  limitation.  As a result of the  increase in the ceiling  amount  using
subsequent prices, the Company has not recorded an impairment of its oil and gas
prices at December 31, 2006. As of June 30, 2006,  the Company's  full cost pool
exceeded the ceiling limitation based on oil and gas prices of $59.87 per barrel
and $5.42 per mcf.  Subsequent  commodity price increases were not sufficient to
eliminate  the need for the  impairment  and  therefore,  impairment  expense of
$51,000,000 was recorded during the quarter ended June 30, 2006.

         Greater Green River Basin Project

As of December 31, 2006, the Company has a leasehold  interest in  approximately
64,683 gross acres and 29,380 net acres in the Greater Green River Basin area of


                                       23
<PAGE>

Wyoming.  The acreage  covers two prospects  identified  by Gasco.  During 2006,
Gasco entered into a farmout  agreement with an industry partner that drilled to
earn acreage in our Daniel Anticline  Prospect in Wyoming.  The agreement allows
our industry partner to earn 50% of our Daniel Anticline Prospect to all depths.
We will retain operations of the wells in the project.  We have also established
an area of mutual interest (AMI) covering this prospect. The AMI will allow both
parties to jointly test the  productive  potential in the core area and to later
implement a plan of development.  Under the terms of the farmout  agreement,  we
paid 25% of the well costs and earned 25% of the first well which was a Hilliard
Shale test. The well was drilled to  approximately  16,600 feet and was intended
to test the natural gas potential in five  formations.  Although gas  quantities
were present,  the well was  determined to be uneconomic  and was plugged during
January  2007.  The total  costs for this  well  were  approximately  $8,300,000
($2,075,000 net to Gasco).

Gasco is also  currently  drilling a well in the Muddy Creek Prospect in Wyoming
to test natural gas potential in five formations to a revised  proposed depth of
14,400 feet.  Intermediate  casing was set at approximately  9,600 feet, and the
rig was released and drilling operations have been suspended due to winter lease
stipulations.  Drilling  operations  on this well are expected to resume in July
2007.   The  costs  to  drill  and  complete  this  well  are  estimated  to  be
approximately $7,800,000 and Gasco has a 100% working interest.

During 2006, approximately $3,786,000 of unproved lease costs related primarily
to expiring acreage in Wyoming were reclassified to proved property.

On September  20, 2006,  Gasco entered into an agreement to purchase Brek Energy
Corporation  ("Brek")  for  equity  consideration  of  11,000,000  shares of the
Company common stock valued at  approximately  $30,000,000  based on the closing
price of Gasco's stock on September  20, 2006.  As a result of this  acquisition
("Brek  Acquisition"),  Gasco will acquire approximately 17,095 net acres in the
Uinta Basin of Utah and approximately  12,495 net acres in the Green River Basin
of Wyoming. The acquisition is expected to simplify Gasco's acreage portfolio by
absorbing a working interest partner that previously owned  approximately 14% of
Gasco's undeveloped acreage in Utah and Wyoming.  Gasco does not expect to incur
any additional  overhead expenses as a result of the acquisition.  The boards of
directors  of  both  Brek  and  Gasco  have  each  approved  the  terms  of  the
transaction,  which is expected to close during the second  quarter of 2007. The
completion of the transaction is subject to the approval of the  stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.

Under the terms of the  transaction,  a  wholly-owned  subsidiary  of Gasco will
merge  with and into  Brek.  As a  result  of the  merger,  Brek  will  become a
wholly-owned  subsidiary of Gasco and stockholders of Brek in the aggregate will
receive a number of shares of common stock of Gasco equal to 11,000,000  divided
by the total number of shares of common stock of Brek outstanding on the date of
the merger,  calculated on a fully  diluted  basis.  Gasco may issue  additional
shares of our common  stock upon  exercise of certain  Brek options and warrants
that we intend to assume in connection with the Brek acquisition. As part of the
transaction,  the directors of Brek, who collectively own  approximately  24% of
Brek's outstanding stock, have entered into an agreement to vote their shares in
favor of the  transaction.  In  addition,  Brek's  President  and CEO,  who owns
approximately 18% of the outstanding common stock of Brek, has agreed to deposit


                                       24
<PAGE>

550,000  shares of Gasco common stock  acquired in the  transaction in escrow to
satisfy any claims with respect to breaches of representations and warranties of
Brek.

         Southern California Project

The Company has a leasehold interest in approximately  10,403 gross acres (6,171
net acres) in Kern and San Luis Obispo Counties of Southern  California.  During
2006,  the Company  entered into a farm-out  agreement  under which an unrelated
entity has  committed  to drill one well on our  acreage in San Luis  Obispo and
Kern Counties,  California.  Under this agreement, Gasco contributed the acreage
and the unrelated  entity  drilled one well which was  temporarily  abandoned in
July 2006.  Gasco is also  continuing  to pay leasehold  rentals and  geological
expenses to preserve its acreage positions and develop its remaining  California
prospects.

         Nevada Project

The Company has a leasehold  interest in approximately  57,302 gross (11,232 net
acres) in six prospects within White Pine County Nevada.  We have farmed out our
acreage to an industry partner for the development of these prospects. Under the
terms of the agreement,  the industry partner has the right to earn up to 80% of
the Company's  interest in these  properties.  The drilling of the first well is
anticipated to begin during the second quarter of 2007.

Company Reserve Estimates

The following table summarizes the Company's estimated proved reserve data as of
December  31,  2006,  as estimated by  Netherland,  Sewell &  Associates,  Inc.,
independent petroleum engineers. The present value of discounted future net cash
flows is based on prices at December 31, 2006 of $4.47 per Mcf of gas and $45.53
per bbl of oil. All of the  Company's  proved  reserves  are located  within the
state of Utah.
<TABLE>
<CAPTION>

                    Proved Reserve Quantities         Present Value of Discounted Future Net Cash Flows
                                                           Proved                Proved
                   Mcf of Gas       Bbls of Oil          Undeveloped            Developed            Total

<S>                <C>                <C>                 <C>              <C>                 <C>
 Total             39,975,964         370,581             $    569,500     $ 62,597,700        $63,167,200
                  ===========         ========             =============    =============      ===========
</TABLE>


                                       25
<PAGE>

Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of any estimate. An increase/decrease in price of $0.10
per Mcf for natural gas and $1.00 per barrel of oil from the actual December 31,
2006 prices would result in an  increase/decrease  in the Company's December 31,
2006  present  value  of  discounted  future  net cash  flows  of  approximately
$2,180,900.

No estimates of proved  reserves  comparable to those included  herein have been
included in reports to any federal agency other than the Securities and Exchange
Commission.

Volumes, Prices and Operating Expenses

The following  table  presents  information  regarding the  production  volumes,
average sales prices received and average  production  costs associated with the
Company's sales of natural gas and oil for the periods indicated.
<TABLE>
<CAPTION>

                                                          For the Years Ended December 31,
                                                     ----------------------------------------------
                                                        2006               2005              2004
                                                     -----------    ----------------    -----------

<S>                                                   <C>                 <C>              <C>
  Natural gas production (Mcf)                        3,686,638           1,648,870        505,967
  Average sales price per Mcf                             $5.38               $8.16          $5.79
  Oil production (Bbl)                                   21,646              10,636          5,080
  Average sales price per Bbl                            $54.86              $56.91         $38.43
  Expenses per Mcfe:
     Lease operating                                      $0.92               $0.51          $1.19
     General and administrative                           $2.47               $3.50          $7.81
     Depreciation, depletion and amortization             $2.85               $2.83          $2.06
     Impairment                                         $ 13.36                $  -           $  -
</TABLE>


Development, Exploration and Acquisition Capital Expenditures

During the years ended  December  31, 2006 and 2005,  we spent  $87,270,883  and
$50,069,968 in development  and  exploration  activities,  respectively.  During
2006, the Company completed a property  acquisition of approximately 21 miles of
mainline  gathering  pipelines and working  interests in 24 oil and gas wells in
the Uinta Basin of Utah for $4,875,000.  Additionally during 2005 we purchased a
drilling rig for approximately  $5,000,000. As of December 31, 2006, the Company
held an interest in 81 gross (50.8 net to Gasco's interest)  producing gas wells
and 16 gross (15.4 net) shut-in gas wells located on these properties.

The  Company  believes  that its  drilling  activity  in the  Riverbend  area is
developmental.  The following table presents information regarding the Company's
net costs  incurred in the  purchase of proved and  unproved  properties  and in
exploration and development activities:




                                       26
<PAGE>


<TABLE>
<CAPTION>



                                                   For the Years Ended December 31,
                                        -----------------------------------------------------
                                              2006                 2005               2004
                                        -------------  ------------------- ------------------
       Property acquisition costs:
      <S>                               <C>                    <C>               <C>
          Unproved                       $ 1,285,289            $ 410,062         $5,021,126
          Proved                           2,563,862                   --           723,9012
       Exploration costs                   8,543,803            1,064,874            216,165
       Development costs                   74,877,929          48,595,0322        17,501,716
                                         -----------          ------------       -----------
            Total                        $87,270,883          $50,069,968        $23,462,908
                                         ===========          ===========        ===========
</TABLE>

Productive Gas Wells

The following  summarizes  the Company's  productive and shut-in gas wells as of
December 31, 2006.  Productive  wells are  producing  wells and wells capable of
production.  Shut-in  wells are wells  that are  capable of  production  but are
currently not producing.  Gross wells are the total number of wells in which the
Company  has an  interest.  Net  wells are the sum of the  Company's  fractional
interests owned in the gross wells.

                                   Productive Oil and Gas Wells
                                     Gross              Net

          Producing oil wells          4                3.9
          Shut-in oil wells            10              10.0
          Producing gas wells          77              46.9
          Shut-in gas wells             6               5.4
                                       --               ---
                                       97              66.2
                                       ==              ====

The  Company  operates  77 of the above  producing  wells and all but one of the
shut-in wells.

Oil and Gas Acreage

The following table sets forth the undeveloped and developed  leasehold acreage,
by area,  held by the Company as of December  31,  2006.  Undeveloped  acres are
acres on which wells have not been  drilled or  completed  to a point that would
permit the  production  of commercial  quantities of oil and gas,  regardless of
whether or not such acreage contains proved reserves. Developed acres are acres,
which are spaced or assignable to  productive  wells.  Gross acres are the total
number of acres in which Gasco has a working interest.  Net acres are the sum of
Gasco's  fractional  interests  owned in the gross  acres.  The  table  does not
include  acreage that the Company has a contractual  right to acquire or to earn
through  drilling  projects,  or any other acreage for which the Company has not
yet received leasehold  assignments.  In certain leases, the Company's ownership
is not the same for all  depths;  therefore,  the net acres in these  leases are
calculated using the greatest  ownership  interest at any depth.  Generally this
greater  interest   represents   Gasco's  ownership  in  the  primary  objective
formation.





                                       27
<PAGE>

<TABLE>
<CAPTION>


                                    Undeveloped Acres                                Developed Acres
                             --------------------------------                --------------------------------
                                 Gross               Net                            Gross                Net

<S>                                <C>                <C>                            <C>               <C>
     Utah                          120,881            72,657                         3,160             2,000
     Wyoming                        64,603            29,320                            80                60
     Nevada                         57,302            11,232                             -                 -
     California                     10,403             6,171                             -                 -
                             --------------      ------------                --------------     -------------

         Total acres               253,189           119,380                         3,240             2,060
                             ==============      ============                ==============     =============
</TABLE>

The following table summarizes the gross and net undeveloped  acres by area that
will expire in each of the next three years. The Company's acreage positions are
maintained  by the payment of delay  rentals or by the  existence of a producing
well on the acreage.
<TABLE>
<CAPTION>

                        Expiring in 2007         Expiring in 2008            Expiring in 2009
                        Gross        Net         Gross      Net            Gross             Net

<S>                     <C>        <C>              <C>         <C>          <C>           <C>
   Utah                 4,199      1,378            640         120          3,713         1,527
   Wyoming              1,720      1,161            939         202          1,280           960
   California             360         67            440         166          3,201         2,756
                        -----      -----           ----         ---          -----         -----

   Total                6,279      2,606          2,019         488          8,195         5,244
                        =====      =====          =====         ===          =====         =====
</TABLE>


As of December 31, 2006, approximately 82% of the gross acreage that Gasco holds
is located on federal lands and  approximately  17% of the acreage is located on
state lands. It has been Gasco's  experience that the permitting process related
to the  development  of  acreage  on federal  lands is more time  consuming  and
expensive than the  permitting  process  related to acreage on state lands.  The
Company has generally  been able to obtain state permits  within 60 days,  while
obtaining federal permits has taken approximately 14 months or longer. If we are
delayed in procuring sufficient drilling permits for our federal properties,  we
will shift more of our drilling in Utah to our state leases.  While such a shift
in resources would not  necessarily  affect the rate of growth of our cash flow,
it would result in a slower growth rate of our total proved reserves,  because a
higher  percentage  of the wells  drilled on the state leases will be drilled on
leases to which proved  undeveloped  reserves may already have been  attributed.
Additionally,  if the  development of the Company's  acreage  located on federal
lands is delayed  significantly by the permitting process,  the Company may have
to operate at a loss for an extended period of time.

Drilling Activity

The following table sets forth the Company's  drilling activity during the years
ended  December 31, 2006,  2005 and 2004.  In the table,  "gross"  refers to the
total wells in which we have a working interest, and "net" refers to gross wells
multiplied by the Company's working interest.



                                       28
<PAGE>

<TABLE>
<CAPTION>



                                                             For the Year Ended December 31,
                                      -------------------------------------------------------------------------------
                                            2006                      2005                          2004
                                      ------------------     ------------------------    ----------------------------
                                        Gross     Net          Gross          Net          Gross             Net
     Exploratory Wells:
       <S>                               <C>       <C>         <C>            <C>           <C>             <C>
       Productive                          -        -             -             -             -               -
       Dry                                 1       .25            -             -             -               -
                                           -       ---           --            --            --              --
         Total wells                       1       .25            -             -             -               -
                                           =       ===           ==            ==            ==              ==

     Development Wells:
       Productive                         26      16.5           21           14.9           11               3.0
       Dry                                 -         -            -             -             -                -
                                          --     -----           --           ---            --               --
         Total wells                      26      16.5           21           14.9           11               3.0
                                          ==     =====           ==           ====           ==               ===
</TABLE>

Office Space

The Company leases approximately 8,776 square feet of office space in Englewood,
Colorado, under a lease, which terminates on May 31, 2010. The average rent for
this space over the life of the lease is approximately $129,300 per year. The
Company is currently in negotiations to lease additional space in its current
location.

ITEM 3 - LEGAL PROCEEDINGS

None.

ITEM 4 - SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.




                                       29
<PAGE>



PART II

ITEM 5 - MARKET FOR REGISTRANT'S COMMON EQUITY,  RELATED STOCKHOLDER MATTERS AND
     ISSUER PURCHASES OF EQUITY SECURITIES

The Company's common stock commenced  trading on the OTC bulletin board on March
30, 2001, under the symbol "GASE.OB." On December 6, 2004,  Gasco's common stock
commenced  trading as a listed security on the American Stock Exchange under the
symbol "GSX." As of February 27, 2007,  the Company had 110 record  shareholders
of its common stock.  During the last two fiscal years,  no cash  dividends were
declared on Gasco's common stock.  The Company's  management does not anticipate
that  dividends  will be paid on its common  stock in the near future as Gasco's
credit facility further discussed Item 7 Management's Discussion and Analysis of
Financial  Condition and Results of Operation,  contains covenants that restrict
the payment of dividends.

The  following  table sets forth,  for the periods  indicated,  the high and low
sales prices per share of the Company's common stock as reported on the American
Stock Exchange for the periods reflected.

                               High            Low
2005
         First Quarter          $4.25          $2.95
         Second Quarter          3.88           2.85
         Third Quarter           6.91           3.57
         Fourth Quarter          7.95           5.60

2006
         First Quarter           7.49           4.23
         Second Quarter          6.18           3.55
         Third Quarter           4.74           2.35
         Fourth Quarter          3.44           2.10


Securities Transactions

The Company's  securities  transactions  during the year ended December 31, 2006
that were not  registered  under the  Securities  Act of 1933 are  described  as
follows:

During 2006,  certain  holders of the Company's  Series B Convertible  Preferred
Stock  ("Preferred  Stock") converted 763 shares of Preferred Stock into 479,599
shares of common stock in accordance with the terms of such Preferred Stock. The
issuance of these shares of common stock was exempt from registration  under the
Securities Act of 1933 pursuant to Section 3(a)(9) thereof.

See Item 12 - Security Ownership of Certain Beneficial Owners and Management and
Related  Stockholder  Matters  regarding  information about the Company's equity
compensation plans.

                                       30
<PAGE>

ITEM 6 - SELECTED FINANCIAL DATA

The  following  table sets  forth  selected  financial  data,  derived  from our
historical  consolidated  financial  statements  and  related  notes,  regarding
Gasco's financial position and results of operations as the dates indicated. The
financial  information is an integral part of, and should be read in conjunction
with, the  consolidated  financial  statements  and notes  thereto.  Information
concerning  significant trends in financial  condition and results of operations
is  contained  in "Item 7 -  Management's  Discussion  and Analysis of Financial
Condition and Results of Operation."
<TABLE>
<CAPTION>

                                                                        For the Year Ended December 31,
                                                   2006             2005              2004              2003             2002
                                                   ----             ----              ----              ----             ----
Summary of Operations
<S>                                               <C>              <C>                <C>               <C>               <C>
      Oil, gas and gathering revenue              $22,980,231      $15,479,566        $3,267,214        $1,263,443        $ 164,508
      General & administrative expense              9,415,787        5,987,019         4,191,978         2,819,675        5,080,287
      Net loss                                   (55,817,767)         (37,635)       (4,205,830)       (2,526,525)      (5,649,682)
      Net loss per share                               (0.65)           (0.00)            (0.07)            (0.07)           (0.16)

                                                                               As of December 31,
                                                   2006             2005              2004              2003             2002
                                                   ----             ----              ----              ----             ----
Balance Sheet
      Working capital (deficit)                   $11,129,942      $86,078,958       $52,719,245        $1,192,246     $(2,857,539)
      Cash and cash equivalents                    12,876,879       62,661,368        25,717,081         3,081,109        2,089,062
      Oil and gas properties, net                 109,281,419      100,334,852        50,820,383        28,470,917       24,760,149
      Total assets                                165,454,418      201,199,972       117,368,168        33,059,179       27,505,501
      Long-term obligations                        65,981,536       65,302,674        65,108,566         2,483,084                -
      Stockholders' equity                         77,171,921      127,440,160        46,213,198        27,382,083       22,014,265
</TABLE>

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
     OF OPERATION

Forward Looking Statements

Please refer to the section entitled  "Cautionary  Statement  Regarding  Forward
Looking  Statements" under Item 1 for a discussion of factors which could affect
the outcome of forward looking statements used by the Company.

Overview

Gasco is a natural gas and petroleum  exploitation,  development  and production
company engaged in locating and developing hydrocarbon  prospects,  primarily in
the Rocky  Mountain  region.  The  Company's  business  strategy  is to  enhance
shareholder  value by using  technologies new to a specific area to generate and
develop  high-potential  exploitation  resources  in this  area.  The  Company's
principal  business is the  acquisition of leasehold  interests in petroleum and
natural gas rights,  either  directly or indirectly,  and the  exploitation  and
development of properties subject to those leases.

                                       31
<PAGE>

The  Company's  corporate  strategy is to grow through  drilling  projects.  The
Company has been focusing its drilling efforts in the Riverbend  Project located
in the Uinta Basin of  northeastern  Utah.  The higher oil and gas prices during
2005 and  through  the first  quarter of 2006 due to factors  such as  inventory
levels of gas in storage, extreme weather in parts of the country and increasing
demand in the United  States,  combined  with the continued  instability  in the
Middle East resulted in increased  drilling  activity in the Riverbend area. The
increased  drilling  activity in the area decreased the availability of drilling
rigs and  experienced  personnel  in this area and may  continue to do so in the
future.  The Company also continues to incur higher drilling and operating costs
resulting  from  the  increased  fuel and  steel  costs  and from the  increased
drilling activity in this area.

Recent Developments

Drilling Activity

During the year ended  December  31,  2006,  the Company  spudded 30 gross wells
(approximately  18.5 net  wells)  and  reached  total  depth  on 29 gross  wells
(approximately  18.0 net wells) in the Riverbend area. We also conducted initial
completion  operations on 26 wells (16.5 net wells) and re-entered 16 wells (8.0
net wells) to complete pay zones that were behind pipe. As of December 31, 2006,
we  operated  77 gross  wells  with two  additional  wells  awaiting  completion
activities.  We currently  have three drilling rigs operating in the Uinta Basin
Riverbend  project,  and are expecting  delivery of our fourth rig at the end of
March 2007.

During 2006,  Gasco entered into a farmout  agreement  with an industry  partner
that drilled to earn acreage in our Daniel  Anticline  Prospect in Wyoming.  The
agreement  allows  our  industry  partner  to earn 50% of our  Daniel  Anticline
Prospect to all depths.  We will retain  operations of the wells in the project.
We have  also  established  an area  of  mutual  interest  (AMI)  covering  this
prospect.  The AMI will  allow  both  parties  to  jointly  test the  productive
potential in the core area and to later implement a plan of  development.  Under
the terms of the farmout agreement,  we paid 25% of the well costs and earned 25
% of the first well which was a Hilliard  Shale  test.  The well was  drilled to
approximately  16,600 feet and was intended to test the natural gas potential in
five formations.  Although gas quantities were present,  the well was determined
to be uneconomic and was plugged during January 2007.

Gasco is also  currently  drilling a well in the Muddy Creek Prospect in Wyoming
to test natural gas potential in five formations to a revised  proposed depth of
14,400 feet.  Intermediate  casing was set at approximately  9,600 feet, and the
rig has been released and drilling  operations have been suspended due to winter
lease  stipulations.  Drilling operations on this well are expected to resume in
July  2007.  The  costs to drill and  complete  this  well are  estimated  to be
approximately $7,800,000 and Gasco has a 100% working interest.

During 2004 we entered  into an  agreement  with a group of  industry  providers
(together,  the "Service  Parties") to accelerate the development of Gasco's oil
and gas  properties by drilling up to 50 wells in Gasco's  Riverbend  Project in
Utah's Uinta  Basin.  The  development  of this  project  typically  occurred in
increments of 10-well bundles. Under this agreement,  we drilled 12 wells during
2004,  10 wells  during 2005 and 10 wells  during 2006.  In February  2007,  the


                                       32
<PAGE>

Service  Parties did not approve  the fourth  bundle as proposed by Gasco.  As a
result,  Gasco and the Service  Parties are currently in discussions on a fourth
bundle.

Property Impairment

During 2006,  approximately $3,786,000 of unproved lease costs related primarily
to expiring acreage in Wyoming were reclassified to proved property.

We utilize the full cost method of accounting,  under which  capitalized oil and
gas property  costs less  accumulated  depletion,  net of deferred  income taxes
(full cost pool) may not exceed an amount equal to the present value, discounted
at 10%, of estimated  future net revenues  from proved oil and gas reserves less
the future cash outflows  associated with the asset retirement  obligations that
have been accrued in the balance sheet plus the cost,  or estimated  fair value,
if lower of  unproved  properties  and the  costs of any  properties  not  being
amortized,  if any. Should the full cost pool exceed this ceiling, an impairment
is  recognized.  This  impairment  is recorded  as  non-cash  expense and is not
permitted to be reversed in future  periods in the event that oil and gas prices
subsequently  increase  resulting  in a higher  ceiling.  The  present  value of
estimated  future net revenues is computed by applying current prices of oil and
gas to  estimated  future  production  of  proved  oil  and gas  reserves  as of
period-end,  less estimated future expenditures to be incurred in developing and
producing the proved reserves  assuming the  continuation  of existing  economic
conditions.  However,  subsequent  commodity  price increases may be utilized to
calculate the ceiling value.

As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53
per barrel,  the full cost pool would have exceeded the above described  ceiling
by $28,400,000.  However,  subsequent to year end, oil and gas prices increased;
and using these prices, the Company's full cost pool would not have exceeded the
ceiling  limitation.  As a result of the  increase in the ceiling  amount  using
subsequent prices, the Company has not recorded an impairment of its oil and gas
prices at December 31, 2006. As of June 30, 2006,  the Company's  full cost pool
exceeded the ceiling limitation based on oil and gas prices of $59.87 per barrel
and $5.42 per mcf.  Subsequent  commodity price increases were not sufficient to
eliminate  the need for the  impairment  and  therefore,  impairment  expense of
$51,000,000 was recorded during the quarter ended June 30, 2006.

Acquisition

Gasco acquired certain gathering assets and producing properties associated with
the Riverbend  Project in the Uinta Basin of Utah for a cash  purchase  price of
$4,875,000,  plus  settlement for production  from effective date. The gathering
assets and properties are located  entirely  within Gasco's  existing  Riverbend
leasehold  allowing the Company to further  capitalize on economies of scale and
operating  efficiencies.  The  transaction  closed on August 14,  2006,  with an
effective  date of July 1, 2006. The Company  assigned a value of  approximately
$2,500,000 to the gathering assets,  which include 21 miles of 4" to 8" mainline
gathering  pipelines.  The acquired  gathering assets should provide more timely
and  cost-effective  tie-in of the existing Wilkin Ridge and West Desert systems
to Gasco's  Riverbend gas  processing  facility.  Gasco now controls  nearly 100
miles of  mainline  gathering  and a 50 MMcf/d gas  processing  facility  in the
Riverbend Project.

                                       33
<PAGE>

This  acquisition  enabled  Gasco to connect  its Wilkin  Ridge and West  Desert
gathering  systems to its Riverbend gas processing  plant.  The gathering  lines
acquired in this transaction may be tied into these systems at an estimated cost
of $1.5  million,  allowing the Company to  potentially  realize a savings of $1
million versus amounts previously budgeted.

Also included in the acquisition are 24 oil and gas wells producing 400 thousand
cubic  feet  equivalent  per  day  (Mcfe/d)  gross  (320  Mcfe/d  net).  In  the
transaction,  Gasco acquired  approximately 1.6 billion cubic feet equivalent of
proved  reserves.  The  acquisition  has no  effect on gross  acreage  leasehold
positions and a negligible  effect on net acreage  leasehold totals. A number of
the wells are  producing  oil and  associated  gas from the shallow  Green River
Formation.  Some of the existing well pads will lend  themselves to also be used
as  locations  for deeper  Spring  Canyon  (Blackhawk)  wells which should yield
savings on  building a new  drilling  pad and access road of $50,000 to $100,000
per location.

Other Operations

During  2006,  Gasco  completed  the linking of the Wilkin Ridge and West Desert
gathering  systems to its existing 50 MMcfd gas processing  facility which began
operations in June 2006. Now, up to 95% of produced volumes are processed in the
facility,  ensuring that production will meet pipeline  specifications  reducing
the likelihood of any future curtailments. The Company currently operates nearly
100 miles of gathering system along with the processing facility.

Gasco recently received approval of its Riverbend Environmental Assessment (EA).
The approved EA includes 45 proposed wells within the Spring Canyon marine trend
of the Blackhawk  Formation.  The EA should provide for  accelerated  permitting
approvals from the Bureau of Land Management as the  environmental  and cultural
studies of the 45 proposed well sites have already been completed.

Proposed Acquisition

On September  20, 2006,  Gasco entered into an agreement to purchase Brek Energy
Corporation  ("Brek")  for  equity  consideration  of  11,000,000  shares of the
Company common stock valued at  approximately  $30,000,000  based on the closing
price of Gasco's stock on September  20, 2006.  As a result of the  acquisition,
Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and
approximately  12,495  net  acres  in the  Green  River  Basin of  Wyoming.  The
acquisition  is expected to simplify  Gasco's  acreage  portfolio by absorbing a
working  interest  partner that previously  owned  approximately  14% of Gasco's
undeveloped  acreage  in Utah and  Wyoming.  Gasco  does not expect to incur any
additional  overhead  expenses  as a result of the  acquisition.  The  boards of
directors  of  both  Brek  and  Gasco  have  each  approved  the  terms  of  the
transaction,  which is expected to close during the second  quarter of 2007. The
completion of the transaction is subject to the approval of the  stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.

Under the terms of the  transaction,  a  wholly-owned  subsidiary  of Gasco will
merge  with and into  Brek.  As a  result  of the  merger,  Brek  will  become a
wholly-owned  subsidiary of Gasco and stockholders of Brek in the aggregate will


                                       34
<PAGE>

receive a number of shares of common stock of Gasco equal to 11,000,000  divided
by the total number of shares of common stock of Brek outstanding on the date of
the merger,  calculated on a fully  diluted  basis.  Gasco may issue  additional
shares of our common  stock upon  exercise of certain  Brek options and warrants
that we intend to assume in connection with the Brek acquisition. As part of the
transaction,  the directors of Brek, who collectively own  approximately  24% of
Brek's outstanding stock, have entered into an agreement to vote their shares in
favor of the  transaction.  In  addition,  Brek's  President  and CEO,  who owns
approximately 18% of the outstanding common stock of Brek, has agreed to deposit
550,000  shares of Gasco common stock  acquired in the  transaction in escrow to
satisfy any claims with respect to breaches of representations and warranties of
Brek.

Credit Facility

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered
into a $250 million  Credit  Agreement  (the "Credit  Agreement")  with JPMorgan
Chase Bank, N.A., as  Administrative  Agent and the other lenders named therein.
Borrowings  made under the Credit  Agreement are guaranteed by our  subsidiaries
and secured by a pledge of the capital stock of our  subsidiaries  and mortgages
on  substantially  all of our oil and gas  properties.  We have not borrowed any
funds under the Credit Agreement since the time of its execution.

The initial  aggregate  commitment of the lenders under the Credit Agreement was
$250,000,000,   subject  to  a  borrowing   base  which  has  initially  set  at
$17,000,000. The borrowing base was subsequently increased to $25,000,000 during
October 2006. The Credit Agreement also provides for a $10,000,000  sublimit for
letters  of  credit  which  we may use for  general  corporate  purposes.  As of
December 31, 2006 there were no loans outstanding,  however; a $6,564,000 letter
of credit is considered  usage,  for purposes of  calculating  availability  and
commitment  fees.  Our aggregate  borrowings and  outstanding  letters of credit
under the  Credit  Agreement  may not at any time  exceed  the  borrowing  base.
Interest on  borrowings  is payable  monthly and principal is due at maturity on
March 29, 2010.

Interest on borrowings under the Credit Agreement  accrues at variable  interest
rates at either,  at our election,  a Eurodollar rate or an alternate base rate.
The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies
from 1.25% (for periods in which we have utilized less than 50% of the borrowing
base) to 2.00% (for  periods in which we have  utilized  greater than 90% of the
borrowing base). The alternate base rate is calculated as (1) the greater of (a)
the Prime Rate or (b) the Federal Funds  Effective  Rate plus 1/2%,  plus (2) an
applicable  margin that varies  from 0% (for  periods in which we have  utilized
less than 50% of the  borrowing  base) to 0.75%  (for  periods  in which we have
utilized  greater  than 90% of the  borrowing  base).  We elect the basis of the
interest rate at the time of each  borrowing.  In addition,  we are obligated to
pay a commitment fee under the Credit Agreement  quarterly in arrears based on a
percentage  multiplied by the daily amount that the aggregate commitments exceed
borrowings under the agreement.  The commitment fee percentage varies from 0.30%
to 0.50% based on the percentage of the borrowing base utilized.

The Credit Agreement requires us to comply with financial covenants that require
us to  maintain  (1) a Current  Ratio  (defined  as current  assets  plus unused
availability under the Credit Facility divided by current liabilities  excluding
the  current  portion of the  Credit  Facility),  determined  at the end of each


                                       35
<PAGE>

quarter,  of not less than 1.0:1;  and (2) a ratio of Senior Debt to EBITDAX (as
such terms are  defined in the Credit  Agreement)  for the most  recent  quarter
multiplied  by four not to be greater  than 3.5:1 for each  fiscal  quarter.  In
addition,  the Credit Agreement  contains covenants that restrict our ability to
incur other indebtedness,  create liens or sell our assets, pay dividends on our
common stock and make certain  investments.  As of December 31, 2006, we were in
compliance with each of the covenants contained in the Credit Facility.

The  Company  incurred  $240,262 in debt  issuance  costs  associated  with this
facility.  These costs have been  recorded as  deferred  financing  costs in the
accompanying  financial  statements  and are being  amortized over the four year
term of the credit  facility.  The credit facility is available to provide funds
for the exploration,  development  and/or acquisition of oil and gas properties,
to refinance  existing  indebtedness  and for working  capital and other general
corporate purposes.  The Credit Agreement provides for semi-annual evaluation of
the borrowing  base,  which will be determined as a percentage of the discounted
present value of the Company's oil and natural gas reserves.

The following table presents certain of the Company's production information for
each of the  three  years  ended  December  31,  2006 and our  estimated  proved
reserves as of December 31 of each year presented.  The Mcfe calculations assume
a conversion of 6 Mcf's for each Bbl of oil.
<TABLE>
<CAPTION>

                                                                         For the Years Ended December 31,
                                                               -----------------------------------------------------
                                                                     2006               2005               2004
                                                               ---------------     --------------    ---------------

<S>                                                                 <C>                <C>                  <C>
  Natural gas production (Mcf)                                      3,686,638          1,648,870            505,967
  Average sales price per Mcf                                           $5.36              $8.16              $5.79
  Year-end estimated proved gas reserves (Mcf)                     39,975,964         74,455,128         39,700,156

  Oil production (Bbl)                                                 21,646             10,636              5,080
  Average sales price per Bbl                                          $54.86             $56.91             $38.43
  Year-end estimated proved oil reserves (Bbl)                        370,581            377,288            274,074

  Production (Mcfe)                                                 3,816,514          1,712,686            536,447
  Year-end estimated proved reserves (Mcfe)                        42,199,450         76,718,856         41,344,600
</TABLE>

The Company's oil and gas production increased by approximately 124% during 2006
as compared with 2005 primarily due to the Company's  drilling and completion of
26 gross (16.5 net) wells during 2006.  During 2006,  the  developed oil and gas
reserve quantities increased by 109% to 41.0 Bcfe from 19.6 Bcfe in 2005. During
2006,  on a combined  basis,  the oil and gas reserve  quantities  decreased  by
approximately  45%  primarily  due to  negative  reserve  revisions  of previous
estimates  of 63%  primarily  related to the decrease in oil and gas prices from
$59.87  per  barrel and $8.01 per mcf to $45.53 per barrel and $4.47 per mcf and
production  of 5%. The decrease in reserve  quantities  is  partially  offset by
reserve  additions of 22% and reserve purchases of 1%. The Company's oil and gas
reserves are 95% natural gas of which 97% are developed.



                                       36
<PAGE>




The  majority  of the  revisions  of  previous  estimates  were a result  of the
following:

     -    Fifty gross locations previously classified as proved undeveloped were
          omitted from the 2006 reserve report  because these  locations did not
          yield a positive  net present  value at a discount  rate of 10% at the
          current estimated  capital  investment based on recent historical data
          to drill and complete wells in this area.

     -    Four gross locations previously  classified as proved undeveloped were
          developed  in 2006 and two gross  proved  undeveloped  locations  were
          added.

The Company's oil and gas production increased by approximately 219% during 2005
as compared with 2004 primarily due to the Company's  drilling of 21 gross (14.9
net) wells  during  2005.  During  2005,  on a combined  basis,  the oil and gas
reserve  quantities  increased by  approximately  86%  primarily  due to reserve
additions of 122% which were  partially  offset by annual  production  of 4% and
revisions  of  previous  estimates  of 32%.  The  majority of the  revisions  of
previous estimates were a result of the following:

     -    Four  locations  previously  classified  as  proved  undeveloped  were
          omitted from the 2005 reserve report because these locations  required
          a higher capital investment than originally  estimated due to drilling
          and completion problems and due to the lack of historical data related
          to recent completions and recompletions in this area.

     -    Six locations previously classified as proved undeveloped were omitted
          from  the  2005  reserve  report  because  recent  drilling   activity
          indicates  that these  locations may be outside of or on the edge of a
          previously  identified  zone.

     -    Two   proved   developed   non-producing   completions   significantly
          underperformed previous forecasts.

Liquidity and Capital Resources

The following table  summarizes the Company's  sources and uses of cash for each
of the three years ended December 31, 2006, 2005 and 2004.
<TABLE>
<CAPTION>

                                                    For the Year Ended December 31,
                                            ------------------------------------------------------
                                              2006                 2005               2004
                                              ----                 ----               ----

<S>                                            <C>                 <C>                <C>
Net cash provided by (used in) operations      $ 9,362,251         $ 2,135,032        $ (905,369)
Net cash used in investing activities          (60,496,759)        (45,851,527)       (58,400,053)
Net cash provided by financing activities        1,350,019          80,660,782         81,941,394
Net cash flow                                 (49,784,489)          36,944,287         22,635,972
</TABLE>

The increase in cash provided by  operations  from 2005 to 2006 is primarily due
to a 52% increase in gross revenue  during 2006.  The increase is comprised of a
124% increase in oil and gas  production  and a 94% increase in interest  income
due to a higher outstanding  average balance in cash and short term investments,
partially  offset by a 34% decrease in gas prices  during 2006.  The increase in
cash provided by  operations  during 2005 compared to 2004 is primarily due to a


                                       37
<PAGE>

219% increase in oil and gas production,  a 41% increase in gas prices and a 48%
increase in oil prices. The production increases in 2006 and 2005 were primarily
due to drilling activity.

The Company's  investing  activities  during the three years ended  December 31,
2006 related primarily to the Company's  development and exploration  activities
and the purchase of a drilling rig. During 2004, we also completed  acquisitions
of acreage and additional working interests in producing wells for approximately
$5,800,000.  We had sales proceeds of $828,102 during 2005 which represented the
sale  of  acreage  to an  unrelated  entity.  Our  sales  proceeds  during  2004
represented a disposition  of net profits  interests in 8 wells in the Riverbend
area for  $4,463,161.  We also invested  $27,000,000  in short-term  investments
during 2004 and sold $9,000,000 and $12,000,000 of these investments during 2006
and 2005,  respectively.  The remaining investing activity during 2006, 2005 and
2004 consisted primarily of changes in our restricted investments.

The Company's financing  activities during 2006 are comprised mainly of proceeds
from the  exercise of common  stock  options  partially  offset by cash paid for
offering  costs and preferred  dividends.  The financing  activities in 2005 and
2004 are  primarily  comprised of the net  proceeds  from the sale of equity and
convertible notes in the Company, as further described below.

On November 23, 2005, we closed a public offering of 12,500,000 shares of common
stock  at a price  to the  public  of  $6.50  per  share.  We also  granted  the
underwriters  a 30-day option to purchase up to 1,875,000  additional  shares of
our common stock solely to cover  over-allotments.  Pursuant to this option, the
underwriters  purchased an additional 439,400 shares of common stock on December
6, 2005. The net proceeds from this offering,  after  underwriting  discount and
offering costs, were $79,418,386.

During 2005,  583,240  options to purchase Gasco common stock were exercised for
proceeds of $1,275,743.

During  2004,  the Company  completed  the sale  through a private  placement of
14,333,334  shares of its common stock to a group of  accredited  investors at a
price of $1.50 per share,  receiving net proceeds of $20,070,000  and closed the
private  placement of  $65,000,000  in aggregate  principal  amount of its 5.50%
Convertible Senior Notes due 2011, receiving net proceeds of $61,793,000.

During 2004,  33,336  options to purchase  Gasco common stock were exercised for
proceeds of $33,336.

Capital Budget

The preliminary budget for our 2007 capital  expenditure program is $40 million,
pending final board of director  approval.  The program will primarily cover the
drilling and  completion of at least 10 net wells on our  Riverbend  Project and
the  completion  of the  drilling  of one in Wyoming.  The budget also  includes
expenditures  for  the  installation  of  associated  pipeline   infrastructure,
distribution facilities and geophysical operations.

This  budget  will be  funded  primarily  from  cash on  hand,  cash  flow  from
operations and borrowings under our line of credit.

                                       38
<PAGE>

Management  believes it has sufficient capital for its 2007 operational  budget,
but may need to raise  additional  capital for its capital  budget in 2008.  The
Company  may  consider  several  options for  raising  additional  funds such as
selling  securities,  selling assets or farm-outs or similar type  arrangements.
Any  financing  obtained  through the sale of Gasco equity will likely result in
substantial dilution to the Company's stockholders.

Schedule of Contractual Obligations

The following table summarizes the Company's obligations and commitments to make
future payments under its notes payable, operating leases, employment contracts,
consulting  agreements  and service  contracts  for the periods  specified as of
December 31, 2006.
<TABLE>
<CAPTION>

                                                                         Payments due by Period
                                                              Less than 1                                        More than
Contractual Obligations                         Total             year          1-3 years       3-5 years          5 years
-----------------------                         -----             ----          ---------       ---------          -------

Convertible Notes
<S>                                            <C>             <C>              <C>             <C>              <C>
    Principal                                  $65,000,000     $    -           $    -          $65,000,000            -
    Interest                                    17,030,903       3,575,000        7,150,000       6,305,903            -
Drilling Rig Contracts *                        38,182,875      21,613,875       15,330,000       1,239,000            -
Operating Leases                                 1,298,171         478,385          756,740          63,046            -
Employment Contracts                               509,167         470,000           39,167               -            -
Consulting Agreements                              145,200         145,200                -               -            -
                                                 ----------      ----------      -----------     ----------      --------
Total Contractual Cash Obligations            $122,166,316     $26,282,460      $23,275,907     $72,607,949            -
                                               ============     ===========      ===========     ===========     =========
</TABLE>

     *    The three year  drilling  contract  for the  new-build  rig contains a
          provision  for the Company to terminate  the  contract  prior to lease
          expiration  for  payments  of  $12,000  per day for  the  number  days
          remaining in the original contract.

The above table does not include asset  retirement  obligations  as discussed in
Note 2 of the accompanying  consolidated  financial  statements,  as the Company
cannot determine with accuracy the timing of such payments.

Critical Accounting Policies and Estimates

The preparation of the Company's consolidated financial statements in conformity
with  generally  accepted  accounting  principles in the United States  requires
management to make assumptions and estimates that affect the reported amounts of
assets,  liabilities,  revenues  and  expenses  as  well  as the  disclosure  of
contingent  assets and  liabilities at the date of the financial  statements and
the reported amounts of revenues and expenses during the reporting  period.  The
following  is a summary  of the  significant  accounting  policies  and  related
estimates that affect the Company's financial disclosures.



                                       39
<PAGE>




         Oil and Gas Reserves

Gasco  follows the full cost method of  accounting  whereby all costs related to
the acquisition and development of oil and gas properties are capitalized into a
single cost center referred to as a full cost pool. Depletion of exploration and
development costs and depreciation of production equipment is computed using the
units-of-production  method based upon  estimated  proved oil and gas  reserves.
Under the full cost method of accounting, capitalized oil and gas property costs
less  accumulated  depletion and net of deferred  income taxes may not exceed an
amount equal to the present  value,  discounted at 10%, of estimated  future net
revenues  from  proved  oil and gas  reserves  less  the  future  cash  outflows
associated with the asset  retirement  obligations that have been accrued on the
balance  sheet plus the cost,  or  estimated  fair value if lower,  of  unproved
properties. Should capitalized costs exceed this ceiling, an impairment would be
recognized.

As of December 31, 2006, based on oil and gas prices of $4.47 per mcf and $45.53
per barrel,  the full cost pool would have exceeded the above described  ceiling
by $28,400,000.  However,  subsequent to year end, oil and gas prices increased;
and using these prices, the Company's full cost pool would not have exceeded the
ceiling  limitation.  As a result of the  increase in the ceiling  amount  using
subsequent prices, the Company has not recorded an impairment of its oil and gas
prices at December 31, 2006. As of June 30, 2006,  the Company's  full cost pool
exceeded the ceiling limitation based on oil and gas prices of $59.87 per barrel
and $5.42 per mcf.  Subsequent  commodity price increases were not sufficient to
eliminate  the need for the  impairment  and  therefore,  impairment  expense of
$51,000,000 was recorded during the quarter ended June 30, 2006. A change in the
estimated  value of the full  cost  ceiling  as  describe  above,  could  have a
material impact on the total of the impairment recorded by the Company.

Estimated reserve quantities and future net cash flows have the most significant
impact on the Company  because these  reserve  estimates are used in providing a
measure of the Company's  overall  value.  These  estimates are also used in the
quarterly  calculations  of  depletion,   depreciation  and  impairment  of  the
Company's proved properties.

Estimating  accumulations  of gas and oil is complex and is not exact because of
the  numerous  uncertainties  inherent in the  process.  The  process  relies on
interpretations of available geological, geophysical, engineering and production
data. The extent,  quality and  reliability of this technical data can vary. The
process also requires certain economic  assumptions,  some of which are mandated
by the Securities and Exchange Commission  ("SEC"),  such as gas and oil prices,
drilling and operating expenses, capital expenditures, taxes and availability of
funds.  The  accuracy  of a reserve  estimate  is a function  of the quality and
quantity of available  data;  the  interpretation  of that data; the accuracy of
various mandated economic assumptions; and the judgment of the persons preparing
the estimate.


The most accurate method of determining proved reserve estimates is based upon a
decline  analysis  method,  which  consists of  extrapolating  future  reservoir
pressure and production from historical  pressure  decline and production  data.
The accuracy of the decline analysis method generally  increases with the length
of the production history. Since most of the Company's wells have been producing
less than six years,  their  production  history is relatively  short,  so other
(generally less accurate) methods such as volumetric analysis and analogy to the


                                       40
<PAGE>

production  history of wells of other  operators in the same reservoir were used
in  conjunction  with the decline  analysis  method to determine  the  Company's
estimates  of  proved  reserves   including   developed   producing,   developed
non-producing and undeveloped. As the Company's wells are produced over time and
more data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data.


Actual  future  production,  gas and oil prices,  revenues,  taxes,  development
expenditures,  operating  expenses and  quantities  of  recoverable  gas and oil
reserves most likely will vary from the  Company's  estimates.  Any  significant
variance  could  materially  affect  the  quantities  and  present  value of the
Company's reserves. For example a decrease in price of $0.10 per Mcf for natural
gas and $1.00 per  barrel of oil would  result in a  decrease  in the  Company's
December  31,  2006  present  value of future  net cash  flows of  approximately
$2,180,900.  In addition, the Company may adjust estimates of proved reserves to
reflect  production  history,  acquisitions,  divestitures,  ownership  interest
revisions,  results of exploration  and  development  and prevailing gas and oil
prices.  The Company's reserves may also be susceptible to drainage by operators
on adjacent properties.


         Impairment of Long-lived Assets

The cost of the  Company's  unproved  properties  is withheld from the depletion
base  as  described  above,  until  such a time  as the  properties  are  either
developed or abandoned.  These properties are reviewed periodically for possible
impairment. Each quarter the Company's management reviews all unproved property.
If a  determination  is made that  acreage  will be expiring or that the Company
does not plan to develop some of the acreage that is no longer  considered to be
prospective,  the Company records an impairment of the acreage and  reclassifies
the costs to the full cost pool. The Company  estimates the value of these acres
for the purpose of recording the related  impairment.  The impairments that have
been recorded by the Company were estimated by calculating a per acre value from
the total  unproved costs  incurred for the  applicable  acreage  divided by the
total net acres owned by the Company.  This per acre estimate is then applied to
the acres that the Company  does not plan to develop in order to  calculate  the
impairment.  As a result of this process the Company has recorded impairments of
$3,786,000  and  $5,300,000  during the years ended  December 31, 2006 and 2005,
respectively.  These  impairments  related  primarily  to the costs of  expiring
acreage in Wyoming.  A change in the estimated value of the acreage could have a
material impact on the total of the impairment recorded by the Company.

         Stock Based Compensation

Effective January 1, 2006, the Company adopted Statement of Financial Accounting
Standards  "SFAS" No. 123(R),  "Accounting for Stock-Based  Compensation"  which
requires  companies to recognize  compensation cost for stock-based awards based
on the estimated fair value of the award.  Compensation  cost is measured at the
grant date based on the fair value of the award and is  recognized as an expense
over the service  period,  which generally  represents the vesting  period.  The
Company uses the  Black-Scholes  option  valuation  model to calculate  the fair
value disclosures under SFAS 123(R). This model requires the Company to estimate
a risk free  interest  rate and the  volatility  of the  Company's  common stock
price.  The use of a different  estimate for any one of these  components  could
have a material impact on the amount of calculated compensation expense.

                                       41
<PAGE>

Prior  to the  adoption  of SFAS  No.  123(R),  Gasco  had  followed  Accounting
Principles  Board  ("APB")  Opinion  No.  25,  "Accounting  for Stock  Issued to
Employees",   and  related  interpretations,   through  December  31,  2005  for
accounting for stock option awards to employees and directors  which resulted in
the  accounting  for  grants of  awards  to  employees  and  directors  at their
intrinsic value in the consolidated financial statements. Accordingly, Gasco has
recognized  compensation  expense in the financial statements for awards granted
to consultants  which must be re-measured  each period under the  mark-to-market
accounting  method.  Gasco had previously adopted the provisions of FAS No. 123,
"Accounting  for  Stock-Based   Compensation",   as  amended  by  FAS  No.  148,
"Accounting for Stock-Based Compensation -- Transition and Disclosure",  through
disclosure only.

On January 1, 2006,  Gasco adopted SFAS No. 123(R),  "Accounting for Stock-Based
Compensation,"  using  the  modified  prospective  method.  Under  the  modified
prospective method, the adoption of SFAS No. 123(R) applies to new awards and to
awards modified,  repurchased,  or cancelled after December 31, 2005, as well as
to the  unvested  portion  of awards  outstanding  as of  January  1,  2006.  In
accordance  with the  modified  prospective  method,  we have not  adjusted  the
financial statements for periods ended prior to January 1, 2006. The Company did
not  recognize any one time effects of the adoption and continued to use similar
option  valuation  models and assumptions as were used prior to January 1, 2006.
The total  fair-value-based  compensation  expense  associated with prior awards
that  was  not  vested  on the  date of the  adoption  of SFAS  No.  123(R)  was
approximately  $4,800,000  which was expected to be recognized over the weighted
average remaining life of the options of approximately one year.

Results of Operations

The following table presents information regarding the production volumes and
average sales prices received from the Company's sales of natural gas and oil
for the periods indicated.

                                        For the Year Ended December 31,
                                    --------------------------------------------
                                          2006             2005            2004
                                          ----             ----            ----

    Natural gas production (Mcf)       3,686,638      1,648,870          505,967
    Average sales price per Mcf           $ 5.38         $ 8.16           $ 5.79
    Oil production (Bbl)                  21,646         10,636            5,080
    Average sales price per Bbl           $54.86         $56.91           $38.43

2006 Compared to 2005

The increase in oil and gas revenue of $6,970,865 during 2006 compared with 2005
is  comprised  of an  increase  in oil and gas  production  of  11,010  bbls and
2,037,768 Mcf  partially  offset by a decrease in the average oil price of $2.05


                                       42
<PAGE>

per bbl and a decrease in the  average  gas price of $2.78 per Mcf during  2006.
The  $6,970,865  increase  in oil and gas  revenue  during  2006  represents  an
increase of $11,583,247 related to the production increase partially offset by a
decrease of $4,612,382 related to the oil and gas price decline.  The production
increase is due to the Company's drilling,  completion and recompletion activity
during 2005 and 2006 and is partially  offset by normal  production  declines on
all wells.

Gathering  revenue and expense from gathering  operations  represents the income
earned  and  expenses  incurred  from  the  Riverbend  area  pipeline  that  was
constructed by the Company during 2004 and 2005. The gathering revenue increased
by $529,800  during 2006 as compared with 2005 due to the  increased  production
attributable  to  the  outside  working  interest  owners,  resulting  from  the
Company's  drilling  activity  in  this  area.  Approximately  $500,000  of  the
$1,551,516  increase  in  expense  from  gathering  operations  is  due  to  the
installation of additional  compression to the system and approximately $594,000
of  the  increase  is the  result  of  the  Company's  decision  to  revise  its
methodology for calculating  charges related to compressor  fuel. The additional
expense resulting from this change  represents  amounts that will be refunded to
the outside  working  interest  and royalty  owners in the  Company's  producing
wells. The remaining  increase is related to increase operating costs related to
the increased production in the area.

Interest income  increased  $1,310,860  during 2006 compared with 2005 primarily
due to higher  interest  rates and higher  average cash and cash  equivalent and
short-term  investment  balances  during  2006  relating  primarily  to the  net
proceeds of  approximately  $79,000,000 from the Company's common stock offering
during November 2005.

Lease operating expense increased $2,642,975 during 2006 compared with 2005. The
increase is primarily  due to the increased  operational  costs such as pumping,
swabbing,  chemicals,  electricity,  allocated  overhead,  etc. of approximately
$1,200,000 due to the increase in the number of producing wells from 45 wells at
December  31, 2005 to 81 wells at December 31, 2006.  Also  contributing  to the
higher  lease  operating  expenses  during 2006 is increased  water  hauling and
disposal costs of approximately  $420,000 and increased  production and property
taxes of $620,000.  Additionally,  lease operating  expense during 2006 includes
approximately  $400,000 of costs  related to  workovers  performed on ten of our
wells in the Riverbend area in order to restore efficient  operating  conditions
on these wells.

Depletion,  depreciation  and  amortization  expense during 2006 is comprised of
depletion expense related to the Company's oil and gas properties,  depreciation
expense of furniture,  fixtures and equipment and accretion  expense  related to
the asset retirement obligation.  The increase of $6,042,258 is due primarily to
the increase in oil and gas production and related  capital costs resulting from
the  Company's  increased  drilling and  completion  activity  discussed  above,
partially  offset by the $51,000,000  reduction in the full cost pool due to the
impairment recorded during the second quarter of 2006, as described below.

Impairment expense during 2006 represents the impairment recorded as of June 30,
2006 because the present value of Gasco's  future net revenue  discounted at 10%
exceeded  the  Company's  full cost pool based on current  oil and gas prices of
$59.87 per barrel and $5.42 per mcf.

General  and  administrative  expense  increased  by  $3,428,768  during 2006 as
compared with 2005.  The increase is primarily due to an increase in stock-based


                                       43
<PAGE>

compensation expense of $4,151,509 due to the adoption of SFAS 123(R) on January
1, 2006 as further discussed in Note 3 of the accompanying  financial statements
and  increased  consulting  expenses of  approximately  $141,000  related to the
maintenance and testing of our internal  controls.  The increased  expenses were
partially  offset  by a  decrease  of  approximately  $860,000  related  to  the
capitalization of certain drilling and completion overhead and the allocation of
internal  administrative  costs  related to the  operations  of our wells during
2006.

Interest  expense  during 2006 and 2005 consists  primarily of interest  expense
related to the Company's outstanding  Convertible Senior Notes which were issued
on October 20, 2004.

2005 Compared to 2004

Oil and gas revenue increased  $10,944,419 during 2005 compared with 2004 due to
an increase in oil and gas  production  of 5,556 bbls and 1,142,903 Mcf combined
with an  increase  in the average oil and gas prices of $18.48 per bbl and $2.37
per Mcf during 2005. The $10,944,419 increase in oil and gas revenue during 2005
is comprised of $9,650,353  related to the  production  increase and  $1,294,066
related to the price increase.  The production  increase is due to the Company's
drilling,  completion  and  recompletion  activity  during  2004 and 2005 and is
partially  offset  by the  production  decrease  resulting  from  the  Company's
disposition of approximately 50% of its revenue interest in two wells during the
first quarter of 2004 and by normal production declines on all wells.

The  Company  recognized  gathering  revenue of  $1,411,259  and  expenses  from
gathering  operations of  $1,166,841  during 2005 which  represents  the revenue
earned and expenses  incurred from the Riverbend area pipeline.  The increase in
this  revenue and expense  from 2004 is due to the full year of activity  during
2005 as well as the increased production as described above.

Interest income increased  $1,058,858 during 2005 compared 2004 primarily due to
higher  average cash and cash  equivalent  and  short-term  investment  balances
during 2005  relating  primarily  to  proceeds  from the  Company's  $65,000,000
Convertible  Senior Note issuance  during October 2004 and the proceeds from the
common stock offering during November 2005.

Lease  operating  expense  increased  $232,326  during 2005  compared  with 2004
primarily due to the increased number of producing wells during 2005.

Depletion,  depreciation  and  amortization  expense  during 2005  increased  as
compared with 2004 due primarily to the increase in production and related costs
resulting  from  the  Company's   increased  drilling  and  completion  activity
discussed above.

General  and  administrative  expense  increased  by  $1,795,041  during 2005 as
compared  with  2004,  primarily  due to  the  Company's  increased  operational
activity.  The increase in these expenses is comprised of approximately $855,000


                                       44
<PAGE>

in salary expense and consulting fees associated with our increased  operational
activity,  $355,000  in fees  associated  with the  Company's  audit of internal
controls  as  required  under the  Sarbanes  Oxley Act of 2002 and  $525,000  in
stock-based  compensation  primarily  related to the Company's  restricted stock
issuance  and the  issuance  of stock  options  to  consultants.  The  remaining
increase in general and  administrative  expenses is due to the  fluctuation  in
numerous other expenses, none of which are individually significant.

Interest  expense  during  2005  consists  of  interest  expense  related to the
Company's outstanding  Convertible Senior Notes which were issued on October 20,
2004.  Interest  expense  during 2004  consists of the interest on the Company's
outstanding  Convertible  Debentures  issued in October 2003 that were converted
into common stock during  October  2004 and interest on the  Convertible  Senior
Notes for approximately two months.

Recent Accounting Pronouncements

On June 1, 2005, the Financial  Accounting  Standards Board ("FASB") issued SFAS
No. 154,  "Accounting Changes and Error Corrections",  which replaced Accounting
Principles  Board  Opinion No. 20,  Accounting  Changes and SFAS No. 3. SFAS 154
provided guidance on the accounting for and reporting of accounting  changes and
error  corrections.  It  established  retrospective  application,  or the latest
practicable  date,  as the required  method for reporting a change in accounting
principle and the reporting of a correction of an error.  SFAS 154 was effective
for  accounting  changes and  corrections  of errors made  January 1, 2006.  The
adoption of SFAS No. 154 had no impact on the Company's financial statements.

In February 2006, the FASB issued SFAS No. 155,  "Accounting  for Certain Hybrid
Financial Instruments-an amendment of FASB Statements No. 133 and 140." SFAS No.
155 amends SFAS No. 133,  "Accounting  for  Derivative  Instruments  and Hedging
Activities"  and SFAS No.  140,  "Accounting  for  Transfers  and  Servicing  of
Financial Assets and  Extinguishments  of Liabilities," and also resolves issues
addressed in SFAS No. 133 Implementation Issue No. D1, "Application of Statement
133 to Beneficial  Interests in Securitized  Financial Assets." SFAS No. 155 was
issued to eliminate  the  exemption  from  applying SFAS No. 133 to interests in
securitized  financial assets so that similar instruments are accounted for in a
similar  fashion,  regardless  of the  instrument's  form.  The Company does not
believe that its financial position, results of operations or cash flows will be
impacted  by SFAS No.  155 as the  Company  does not  currently  hold any hybrid
financial instruments.

In June 2006,  the FASB  issued  FASB  Interpretation  No. 48,  "Accounting  for
Uncertainty  in Income  Taxes"  ("FIN 48").  The  interpretation  clarifies  the
accounting for uncertainty in income taxes  recognized in a company's  financial
statements  in  accordance  with  SFAS  109,   "Accounting  for  Income  Taxes".
Specifically,  the  pronouncement  prescribes  a  recognition  threshold  and  a
measurement attribute for the financial statement recognition and measurement of
a tax position taken or expected to be taken in a tax return. The interpretation
also provides guidance on the related  derecognition,  classification,  interest
and  penalties,  accounting  for interim  periods,  disclosure and transition of
uncertain tax positions. The interpretation is effective January 1, 2006 for the
Company.  The adoption of FIN 48 is expected to have an immaterial impact on the
Company's consolidated financial position, results of operations and cash flows.

                                       45
<PAGE>

In September  2006,  the FASB issued SFAS 157, "Fair Value  Measurements".  This
Statement  defines  fair value as used in  numerous  accounting  pronouncements,
establishes  a  framework  for  measuring  fair  value  in  generally   accepted
accounting  principles and expands  disclosure  related to the use of fair value
measures in financial  statements.  The  Statement  is to be  effective  for the
Company's financial  statements issued in 2008; however,  earlier application is
encouraged.  The Company is currently  evaluating the timing of adoption and the
impact  that  adoption  might  have on its  financial  position  or  results  of
operations.

In September 2006, the Securities and Exchange  Commission  ("SEC") issued Staff
Accounting  Bulletin  No. 108 ("SAB 108").  Due to  diversity in practice  among
registrants,  SAB 108 expresses  SEC staff views  regarding the process by which
misstatements in financial  statements are evaluated for purposes of determining
whether financial statement  restatement is necessary.  SAB 108 is effective for
the Company on January 1, 2007. The Company does not believe SAB 108 will have a
material impact on its financial position or results from operations.

In December  2006,  the FASB issued FASB Staff  Position  ("FSP") EITF  00-19-2,
"Accounting for Registration Payment  Arrangements." This FSP specifies that the
contingent   obligation   to  make  future   payments  or   otherwise   transfer
consideration  under a  registration  payment  arrangement  should be separately
recognized and measured in accordance with FASB Statement No. 5, "Accounting for
Contingencies".  This FSP is  effective  immediately  for  registration  payment
arrangements and the financial  instruments  subject to those  arrangements that
are entered into or modified  subsequent to December 21, 2006. For  registration
payment  arrangements and financial  instruments  subject to those  arrangements
that were entered  into prior to December  21, 2006,  the guidance in the FSP is
effective  January 1, 2006 for the  Company.  The Company  does not believe that
this FSP will have a material  impact on its financial  position or results from
operations.

On February  15,  2007,  the FASB issued SFAS No. 159 "The Fair Value Option for
Financial  Assets  and  Financial   Liabilities."  This  Statement   establishes
presentation  and  disclosure  requirements  designed to facilitate  comparisons
between companies that choose different measurement attributes for similar types
of assets and liabilities. SFAS No. 159 is effective for the Company's financial
statements  issued in 2008. The Company is currently  evaluating the impact that
the adoption of SFAS No. 159 might have on its financial  position or results of
operations.

Off Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions
that can give rise to off-balance  sheet  obligations.  As of December 31, 2006,
the off-balance  sheet  arrangements and transactions  that we have entered into
include  undrawn  letters  of  credit,   operating  lease   agreements  and  gas
transportation commitments. The Company does not believe that these arrangements
are reasonably  likely to materially affect its liquidity or availability of, or
requirements for, capital resources.

                                       46
<PAGE>

ITEM 7A - QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company's  primary market risk relates to changes in the pricing  applicable
to the sales of gas production in the Uinta Basin of  northeastern  Utah and the
Greater  Green River Basin of west central  Wyoming.  This risk will become more
significant  to the  Company as more wells are drilled  and begin  producing  in
these  areas.  Although  the  Company is not using  derivatives  at this time to
mitigate the risk of adverse changes in commodity  prices, it may consider using
them in the future.  The Company does not have any obligations,  including under
its credit facility, that are subject to variable rates of interest.




                                       47
<PAGE>



ITEM 8 - FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          INDEX TO FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm                       49

Consolidated Balance Sheets at December 31, 2006 and 2005                  50-51

Consolidated Statements of Operations for the Years Ended
    December 31, 2006, 2005 and 2004                                          52

Consolidated Statements of Stockholders' Equity for the Years
    Ended December 31, 2006, 2005 and 2004                                    53

Consolidated Statements of Cash Flows for the Years Ended
    December 31, 2006, 2005 and 2004                                          54

Notes to Consolidated Financial Statements                                 55-90




                                       48
<PAGE>




REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of Gasco Energy, Inc.:

We have  audited the  consolidated  balance  sheets of Gasco  Energy,  Inc.  and
subsidiaries  (the  "Company") 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.  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.  An audit also includes assessing the accounting principles used and
significant  estimates  made by  management,  as well as evaluating  the overall
financial  statement  presentation.  We  believe  that  our  audits  provided  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 the Company as of
December 31, 2006 and 2005,  and the results of their  operations and their cash
flows for each of the three years in the period  ended  December  31,  2006,  in
conformity with U.S. generally accepted accounting principles.

We also have  audited,  in accordance  with the standards of the Public  Company
Accounting  Oversight Board (United States),  the effectiveness of the Company'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 February 27, 2007 expressed an unqualified  opinion on management's
assessment of the effectiveness of the Company's internal control over financial
reporting  and an  unqualified  opinion on the  effectiveness  of the  Company's
internal control over financial reporting.



/s/ Hein & Associates LLP
Denver, Colorado
February 27, 2007







                                       49
<PAGE>

<TABLE>
<CAPTION>




                                                             GASCO ENERGY, INC.
                                                        CONSOLIDATED BALANCE SHEETS


                                                                                      December 31,
                                                                            -------------------------------------
                                                                            --------------- -- ------------------
                                                                               2006                  2005
ASSETS

CURRENT ASSETS
<S>                                                                            <C>                   <C>
  Cash and cash equivalents                                                    $12,876,879           $62,661,368
  Restricted investment                                                          3,575,000            10,139,000
  Short-term investments                                                         6,000,000            15,000,000
  Accounts receivable
    Joint interest billings                                                      5,955,186             1,792,038
    Revenue                                                                      3,081,850             3,115,154
  Inventory                                                                      1,297,498             1,182,982
  Prepaid expenses                                                                 644,490               645,554
                                                                               -----------           -----------
          Total                                                                33,430,903            94,536,096
                                                                               -----------           ----------

PROPERTY, PLANT AND EQUIPMENT, at cost
  Oil and gas properties (full cost method)
      Proved properties                                                        159,407,481            83,972,300
      Unproved properties                                                       12,538,067            13,323,712
  Wells in progress                                                              5,215,252                     -
  Gathering assets                                                              12,703,346             4,831,050
  Facilities and equipment                                                       8,492,632             5,148,388
  Furniture, fixtures and other                                                    241,009               175,607
                                                                               -----------           -----------
           Total                                                               198,597,787           107,451,057
  Less accumulated depletion, depreciation, amortization and impairment       (68,945,779)           (6,986,662)
                                                                              ------------           -----------
           Total                                                              129,652,008           100,464,395
                                                                              ------------          -----------

NON-CURRENT ASSETS
  Restricted investment                                                                  -             3,565,020
  Deferred financing costs                                                       2,371,507             2,634,461
                                                                                 ---------             ---------
                                                                                 2,371,507             6,199,481
                                                                                 ---------             ---------

TOTAL ASSETS                                                                 $ 165,454,418         $ 201,199,972
                                                                             =============         =============



</TABLE>









               The accompanying notes are an integral part of the
                       consolidated financial statements.





                                       50
<PAGE>

<TABLE>
<CAPTION>




                                                             GASCO ENERGY, INC.
                                                  CONSOLIDATED BALANCE SHEETS (continued)


                                                                                          December 31,
                                                                                 ---------------------------------------
                                                                                         2006                    2005

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
<S>                                                                                 <C>                     <C>
  Accounts payable                                                                  $ 16,228,056            $ 3,095,819
  Revenue payable                                                                      1,678,427              1,658,141
  Advances from joint interest owners                                                  2,955,376              2,476,080
  Accrued interest                                                                       844,102                844,098
  Accrued expenses                                                                       595,000                383,000
                                                                                     -----------             ----------
           Total                                                                     22,300,961              8,457,138
                                                                                     -----------             ---------

NONCURRENT LIABILITIES
   5.5% Convertible Senior Notes                                                      65,000,000             65,000,000
   Asset retirement obligation                                                           908,543                223,947
   Deferred rent expense                                                                  72,993                 78,727
                                                                                      ----------             ----------
       Total                                                                          65,981,536             65,302,674
                                                                                      ----------             ----------

COMMITMENTS AND CONTINGENCIES (NOTES 5, 12, 13)

STOCKHOLDERS' EQUITY
  Series B Convertible Preferred stock - $.001 par value; 20,000 shares
     authorized; 763 shares issued and outstanding with a liquidation
     preference of $335,720 as of December 31, 2005                                            -                      1
  Common stock - $.0001 par value; 300,000,000 shares authorized;
     86,173,715 shares issued and 86,100,015 outstanding as of
      December 31, 2006; 85,041,492 shares issued and 84,967,792 shares
      outstanding as of December 31, 2005                                                  8,617                  8,504
  Additional paid-in-capital                                                         162,646,592            157,540,755
  Deferred compensation                                                                        -              (443,579)
  Accumulated deficit                                                               (85,352,993)           (29,535,226)
  Less cost of treasury stock of 73,700 common shares                                  (130,295)              (130,295)
                                                                                    ------------           ------------
           Total                                                                     77,171,921            127,440,160
                                                                                     -----------           -----------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                        $ 165,454,418          $ 201,199,972
                                                                                  =============-         =============


</TABLE>






               The accompanying notes are an integral part of the
                       consolidated financial statements.






                                       51
<PAGE>

<TABLE>
<CAPTION>



                                                         GASCO ENERGY, INC.
                                               CONSOLIDATED STATEMENTS OF OPERATIONS



                                                              For the Year Ended December 31,
                                                     ---------------------------------------------------
                                                                2006             2005             2004
REVENUES
<S>                                                     <C>               <C>              <C>
  Gas                                                   $ 19,851,663      $ 13,462,977     $  2,928,689
  Oil                                                      1,187,509           605,330          195,199
  Gathering                                                1,941,059         1,411,259          143,326
  Interest income                                          2,694,719         1,383,859          325,001
                                                           ---------         ---------        ---------
          Total                                           25,674,950        16,863,425        3,592,215
                                                          ----------        ----------        ---------

OPERATING EXPENSES
  Lease operating                                          3,513,568           870,593          638,267
  Gathering operations                                     2,718,357         1,166,841          267,450
  Depletion, depreciation and amortization                10,885,697         4,843,439        1,102,575
  Impairment                                              51,000,000                 -                -
  General and administrative                               9,415,787         5,987,019        4,191,978
  Interest expense                                         3,959,308         4,033,168        1,597,775
                                                          ----------        ----------        ---------
           Total                                          81,492,717        16,901,060        7,798,045
                                                          ----------        ----------        ---------

NET LOSS                                                (55,817,767)          (37,635)      (4,205,830)

Preferred stock dividends                                    (1,393)          (33,347)        (140,853)
                                                         -----------          --------      -----------
NET LOSS ATTRIBUTABLE TO COMMON
   STOCKHOLDERS                                       $ (55,819,160)         $(70,982)    $ (4,346,683)
                                                      ==============         =========    =============

NET LOSS PER COMMON SHARE - BASIC AND DILUTED             $   (0.65)         $  (0.00)   $       (0.07)
                                                          ==========         =========   ==============

WEIGHTED AVERAGE COMMON SHARES
  OUTSTANDING - BASIC AND DILUTED                         85,383,306         72,152,977     63,194,223
                                                         ===========         ==========     ==========
</TABLE>

















               The accompanying notes are an integral part of the
                       consolidated financial statements.



                                       52
<PAGE>
<TABLE>
<CAPTION>

                                                       GASCO ENERGY, INC.
                                         CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

                                                               Additional
                            Preferred Stock   Common Stock        Paid-in      Deferred   Accumulated  Treasury
                           Shares   Value    Shares     Value    Capital    Compensation    Deficit      Stock           Total

<S>              <C> <C>     <C>      <C>   <C>         <C>     <C>           <C>        <C>            <C>            <C>
Balance December 31, 2003    11,734   $ 12  45,675,936  $4,568  $52,979,325   $(179,766) $ (25,291,761) $(130,295)     $ 27,382,083
Conversion of preferred
 shares to common shares    (9,479)    (10)  5,958,226    596        (586)                                                         -
Issuance of common stock                    14,714,787  1,472   20,786,130    (748,157)                                   20,039,445
Conversion of Convertible
 Debentures                                  4,166,665    416    2,503,376                                                 2,503,792
Exercise of common stock
 options                                        33,336      3       33,333                                                    33,336
Stock compensation                                                             415,483                                       415,483
Proceeds from 16b violation                                        106,858                                                   106,858
Dividends                                       41,959      4     (61,973)                                                  (61,969)
Net loss                          -       -           -     -            -           -   (4,205,830)                     (4,205,830)
                             ------     ---  ----------   -----   ----------  ---------  -----------      ---------       ---------
Balance December 31, 2004     2,255       2  70,590,909  7,059   76,346,463   (512,440)  (29,497,591)      (130,295)     46,213,198
Issuance of common stock                     12,929,516  1,293   79,449,446   (172,773)                                  79,277,966
Conversion of preferred
 shares to common shares     (1,492)     (1)    937,827     94         (93)                                                        -
Exercise of common stock
 options                                        583,240     58    1,275,685                                                1,275,743
Stock compensation                                                  502,601     241,634                                      744,235
Dividends                                                           (33,347)                                                (33,347)
Net loss                                                                                     (37,635)                       (37,635)
                             ------     ----   -------- -------   ----------   ---------  ----------                   -   ---------
Balance December 31, 2005       763       1  85,041,492  8,504  157,540,755    (443,579) (29,535,226)      (130,295)     127,440,160
Adoption of SFAS 123(R)                                            (443,579)    443,579                                            -
Conversion of preferred
shares to common shares        (763)     (1)     479,599    48         (47)                                                        -
Exercise of common stock
 options                                         604,161    60    1,591,614                                                1,591,674
Cancellation of common
 stock                                          (82,787)    (8)    (199,278)                                               (199,286)
Stock compensation                              131,250     13    4,158,520                                                4,158,533
Dividends                                                            (1,393)                                                 (1,393)
Net loss                                                                                 (55,817,767)                   (55,817,767)
                               ----  ---   ----------   -----  ----------       --------  -----------   ----------    --------------

Balance December 31, 2006      -   $ -     86,173,715  $8,617 $162,646,592     $     -   $(85,352,993)   $(130,295)     $77,171,921
                               ==  ======  ==========  ====== ============     ==========  ============= ==========     ===========
</TABLE>





         The accompanying notes are an integral part of the consolidated
                             financial statements.





                                       53
<PAGE>
<TABLE>
<CAPTION>



                                                             GASCO ENERGY, INC.
                                                    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                                   For the Years Ended December 31,
                                                                           ----------------------------------------------------
                                                                                   2006             2005                2004
CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                        <C>                  <C>               <C>
  Net loss                                                                 $ (55,817,767)       $ (37,635)        $(4,205,830)
  Adjustment to reconcile net loss to net cash provided by (used in)
   Operating activities
     Depletion, depreciation, amortization and impairment expense              61,816,513        4,829,403           1,085,912
     Accretion of asset retirement obligation                                      69,184           14,036              16,663
     Stock compensation                                                         4,151,509          744,235             415,483
    Amortization of deferred rent expense                                         (5,734)           48,727                   -
    Landlord incentive payment                                                          -           30,000                   -
     Amortization of beneficial conversion feature                                      -                -             161,514
     Amortization of deferred financing costs                                     503,216          458,167             294,993
     Changes in operating assets and liabilities:
      Accounts receivable                                                     (4,129,844)      (3,862,148)           (545,681)
      Inventory                                                                 (114,516)        (173,068)         (1,009,914)
         Prepaid expenses                                                           1,064        (186,999)              59,992
         Accounts payable                                                       2,376,327      (3,109,102)           1,113,109
         Revenue payable                                                           20,286        1,323,376              91,252
         Advances from joint interest owners                                      479,296        1,584,081             891,999
         Accrued interest                                                               4          148,959             695,139
         Accrued expenses                                                          12,713          323,000              30,000
                                                                                ---------        ---------            --------
                  Net cash provided by (used in) operating activities           9,362,251        2,135,032            (905,369)
                                                                                ---------        ---------            ---------
CASH FLOWS FROM INVESTING ACTIVITIES
  Cash paid for acquisitions, development and exploration                    (79,557,785)     (55,181,914)        (25,736,066)
  Cash paid for furniture, fixtures and other                                    (67,994)        (106,790)            (64,053)
  Proceeds from property sales                                                          -          828,102           4,463,161
  Investment in short-term investments                                                  -                -        (27,000,000)
  Proceeds from the sale of short-term investments                              9,000,000       12,000,000                   -
  Cash designated as restricted                                                   (9,980)      (6,816,967)        (10,313,095)
  Cash undesignated as restricted                                              10,139,000       3,426,042             250,000
                                                                               ----------       ---------          -----------
                 Net cash used in investing activities                       (60,496,759)     (45,851,527)        (58,400,053)
                                                                             ------------     ------------      --------------

CASH FLOWS FROM FINANCING ACTIVITIES
  Exercise of options to purchase common stock                                  1,591,674        1,275,743              33,336
  Cash paid for debt issuance costs                                             (240,262)        (275,378)         (4,636,828)
  Preferred dividends                                                             (1,393)         (33,347)            (61,793)
  Proceeds from sale of common stock                                                    -       79,693,764          21,500,001
  Issuance of convertible notes                                                         -                -          65,000,000
  Proceeds from 16b violation                                                                                          106,858
                                                                               ----------       ----------         -----------
                Net cash provided by financing activities                       1,350,019        80,660,782         81,941,394
                                                                               ----------       -----------     --------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                          (49,784,489)       36,944,287          22,635,972

CASH AND CASH EQUIVALENTS:

    BEGINNING OF PERIOD                                                        62,661,368       25,717,081           3,081,109
                                                                               ----------       ----------          ----------

    END OF PERIOD                                                             $12,876,879      $62,661,368         $25,717,081
                                                                              ===========      ===========         ===========
</TABLE>


               The accompanying notes are an integral part of the
                       consolidated financial statements.

                                       54
<PAGE>

                                GASCO ENERGY INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
              FOR THE YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004

NOTE 1 - ORGANIZATION

Gasco Energy,  Inc. ("Gasco" or the "Company") is an independent  energy company
engaged in the exploration, development, and acquisition and production of crude
oil and natural gas in the western United States.  "Our", "we", and "us" as used
herein also refer to Gasco Energy, Inc.

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The  accompanying  consolidated  financial  statements  include  Gasco  and  its
wholly-owned  subsidiaries.  All significant intercompany transactions have been
eliminated.

Cash and Cash Equivalents

All highly liquid investments purchased with an initial maturity of three months
or less are considered to be cash equivalents.

Restricted Investment

The  restricted  investment  balance as of  December  31, 2006 is  comprised  of
$3,575,000  invested in U.S.  government  securities in an amount  sufficient to
provide for the payment of two semi-annual  scheduled  interest  payments on the
Company's  outstanding  5.5%  Convertible  Senior  Notes  ("Notes"),  as further
described in Note 7. This investment will be held until maturity and the cost of
the investment  approximates its market value. The restricted investment balance
at December 31, 2005 was  comprised of  $7,140,020  invested in U.S.  government
securities  in  an  amount  sufficient  to  provide  for  the  payment  of  four
semi-annual  scheduled interest payments on the Company's outstanding Notes, and
$6,564,000 of cash  invested in cash  equivalents  as collateral  for a one year
letter of credit.  The letter of credit was obtained in  connection  with one of
the Company's long-term rig contracts.  The collateral for this letter of credit
was released  during the first quarter of 2006 in connection  with the Company's
credit facility further described in Note 6. The non-current portion at December
31, 2005 represented the interest payments that were due after one year.

Short-term Investments

The Company's short-term investments consist primarily of preferred auction rate
securities,  which are classified as available-for-sale.  Preferred auction rate
securities  represent  preferred  shares  issued  by  closed  end  funds and are
typically traded at auctions that are held periodically  where the dividend rate
for the next  period is set.  The  Company  invests in AAA/Aaa  rated  preferred
auctions that have a dividend rate period of 28 days or less.  These  securities


                                       55
<PAGE>

are stated at fair value based on quoted  market  prices.  The income  earned on
these   investments  is  included  in  interest   income  in  the   accompanying
consolidated financial statements.

Concentration of Credit Risk

The  Company's  cash  equivalents  and  short-term  investments  are  exposed to
concentrations  of credit risk.  The Company  manages and controls  this risk by
investing these funds with major financial institutions.

The Company's  receivables are comprised of oil and gas revenue  receivables and
joint interest billings receivable. The amounts are due from a limited number of
entities.  Therefore,  the collectability is dependent upon the general economic
conditions of the few purchasers and joint interest owners.  The receivables are
not collateralized. However, to date the Company has had minimal bad debts.

Significant Customers

During  the years  ended  December  31,  2006,  2005 and  2004,  over 90% of the
Company's production was sold to one customer,  ConocoPhillips Company. However,
Gasco  does  not  believe  that  the  loss  of  a  single  purchaser,  including
ConocoPhillips  Company,  would materially affect the Company's business because
there  are  numerous  other  purchasers  in the areas in which  Gasco  sells its
production.  For the years ended December 31, 2006, 2005 and 2004,  purchases by
the  following  company  exceeded  10% of the total oil and gas  revenues of the
Company.

                                            For the Year Ended December 31,
                                    --------------------------------------------
                                     2006            2005            2004
                                     ----            ----            ----

      ConocoPhillips Company         94%              96%            93%


Inventory

Inventory  consists  of  pipe  and  tubular  goods  intended  to be  used in the
Company's oil and gas  operations,  and is stated at the lower of cost or market
using the average cost valuation method.

Oil and Gas Properties

The Company follows the full cost method of accounting whereby all costs related
to the  acquisition  and  development of oil and gas properties are  capitalized
into a  single  cost  center  ("full  cost  pool").  Such  costs  include  lease
acquisition  costs,  geological  and  geophysical  expenses,  overhead  directly
related to  exploration  and  development  activities and costs of drilling both
productive and non-productive wells. The Company capitalized $353,190,  $260,227
and $69,238 of internal costs during the years ended December 31, 2006, 2005 and
2004,  respectively.  Costs  associated  with  production and general  corporate
activities are expensed in the period incurred. Proceeds from property sales are
generally credited to the full cost pool without gain or loss recognition unless
such a sale would significantly alter the relationship between capitalized costs
and the proved reserves  attributable  to these costs. A significant  alteration
would typically  involve a sale of 25% or more of the proved reserves related to
a single full cost pool.

                                       56
<PAGE>

Depletion of exploration  and development  costs and  depreciation of production
equipment is computed using the units-of-production  method based upon estimated
proved oil and gas reserves.  The costs of unproved properties are withheld from
the  depletion  base until such time as they are either  developed or abandoned.
The properties are reviewed quarterly for impairment. During 2006, approximately
$3,786,000 of unproved  lease costs  related to expiring  acreage in Wyoming was
reclassified  to  proved  property  and was  included  in the  ceiling  test and
depletion calculations.

Total well  costs are  transferred  to the  depletable  pool even when  multiple
targeted  zones have not been fully  evaluated.  For depletion and  depreciation
purposes,  relative volumes of oil and gas production and reserves are converted
at the energy  equivalent  rate of six thousand cubic feet of natural gas to one
barrel of crude oil.

Under the full cost method of accounting, capitalized oil and gas property costs
less accumulated depletion and net of deferred income taxes (full cost pool) may
not exceed an amount equal to the present value, discounted at 10%, of estimated
future net  revenues  from  proved  oil and gas  reserves  less the future  cash
outflows associated with the asset retirement obligations that have been accrued
in the  balance  sheet  plus the cost,  or  estimated  fair  value,  if lower of
unproved properties and the costs of any properties not being amortized, if any.
Should the full cost pool exceed this ceiling, an impairment is recognized.  The
present value of estimated  future net revenues is computed by applying  current
oil and gas prices to estimated future production of proved oil and gas reserves
as  of  period-end,  less  estimated  future  expenditures  to  be  incurred  in
developing  and  producing  the proved  reserves  assuming the  continuation  of
existing economic conditions.  However, subsequent commodity price increases may
be utilized to calculate the ceiling value.

As of December  31,  2006,  based on oil and gas prices of $45.53 per barrel and
$4.47 per mcf,  the full cost  pool  would  have  exceeded  the above  described
ceiling by  $28,500,000.  However,  subsequent  to year end,  oil and gas prices
increased;  and using these prices,  the Company's full cost pool would not have
exceeded  the  ceiling  limitation.  As a result of the  increase in the ceiling
amount using  subsequent  prices,  the Company has not recorded an impairment of
its oil and gas prices at December 31, 2006. As of June 30, 2006,  the Company's
full cost pool  exceeded the ceiling  limitation  based on oil and gas prices of
$59.87 per barrel and $5.42 per mcf.  Subsequent  commodity price increases were
not  sufficient  to  eliminate  the  need  for  the  impairment  and  therefore,
impairment expense of $51,000,000 was recorded during the quarter ended June 30,
2006.

 Capitalized Interest


The Company capitalizes interest costs to oil and gas properties on expenditures
made in  connection  with  exploration  and  development  projects  that are not
subject to current  depletion.  Interest is capitalized only for the period that
activities  are in  progress  to bring these  projects  to their  intended  use.
Interest costs  capitalized in 2006 were $231,500.  No interest was  capitalized
during 2005 or 2004.

                                       57
<PAGE>

Wells in Progress

Wells in progress at December 31, 2006 represent the costs  associated  with the
drilling of two wells in the Riverbend  area of Utah and one well in the Greater
Green River Basin in Wyoming.  Since the wells had not reached total depth as of
December 31, 2006,  they were  classified as wells in progress and were withheld
from the depletion  calculation  and the ceiling test. The costs for these wells
will be  transferred  into proved  property when the wells reach total depth and
are cased and will become subject to depletion and the ceiling test  calculation
in future periods.

Gathering Assets

Gathering  assets are comprised of the costs associated with the construction of
the Company's  pipeline and gathering  system  located in the Riverbend  area of
Utah. These assets are being depreciated on a  units-of-production  method based
upon  estimated  proved oil and gas  reserves of the wells that are  expected to
flow through the gathering system.

Facilities and Equipment

During 2006, the Company  constructed two evaporation pits in the Riverbend area
of Utah to be used for the disposal of produced  water from the wells that Gasco
operates in the area.  The pits are being  depreciated  using the  straight-line
method over their estimated useful life of twenty-five years. The costs of water
disposal  into the  evaporation  pits is charged to wells  operated by Gasco and
therefore,  net revenue attributable to the outside working interest owners from
the evaporation  pits of $179,766 was recorded as a credit to proved  properties
during 2006.

During  December  2005,  Gasco  purchased  a  drilling  rig  for   approximately
$5,000,000.  The rig and the other oil and gas equipment owned by the Company is
depreciated using the straight-line method over the estimated useful life of the
equipment  of five to ten years.  The rental of the rig and  equipment  owned by
Gasco is charged  to the wells that are  operated  by Gasco and  therefore,  net
revenue  attributable  to the outside  working  interest owners from the rig and
equipment  rental of  $748,690  was  recorded  as a credit to proved  properties
during 2006.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated quarterly for the possibility of
potential  impairment.  During the year ended  December  31, 2006  approximately
$3,786,000  of unproved  lease costs  related  primarily to expiring  acreage in
Wyoming was reclassified to proved property.  Other than oil and gas properties,
the Company has no other  long-lived  assets and to date has not  recognized any
impairment losses.

Deferred Financing Costs

Deferred  financing  costs  include  the  costs  associated  with the  Company's
issuance of  $65,000,000 of  Convertible  Notes during  October 2004,  which are
being  amortized  over the seven year life of the notes;  and the debt  issuance
costs incurred in connection with the Company's credit facility, which are being
amortized  over the four  year term of the  credit  facility  (see Note 6).  The
Company recorded  amortization expense of $503,216 and $458,167 related to these
costs during the years ended December 31, 2006 and 2005, respectively.

                                       58
<PAGE>

Financial Instruments

The  Company's  financial  instruments  including  cash  and  cash  equivalents,
restricted  cash,  short-term  investments,  accounts  receivable  and  accounts
payable are carried at cost, which approximates fair value due to the short-term
maturity of these instruments. The Company's Notes are recorded at cost, and the
fair value is  disclosed in Note 7. Since  considerable  judgment is required to
develop  estimates of fair value,  the  estimates  provided are not  necessarily
indicative  of the  amounts  the  Company  could  realize  upon the  purchase or
refinancing of such instruments.

Asset Retirement Obligation

The Company follows SFAS No. 143, "Accounting for Asset Retirement  Obligations,
" which  requires  that the fair value of a  liability  for an asset  retirement
obligation  be recognized in the period in which it was incurred if a reasonable
estimate of fair value could be made. The associated  asset retirement costs are
capitalized as part of the carrying amount of the long-lived asset. The increase
in carrying value of a property  associated with the  capitalization of an asset
retirement cost is included in proved oil and gas properties in the consolidated
balance  sheets.  The Company  depletes  the amount  added to proved oil and gas
property costs.  The future cash outflows for oil and gas properties  associated
with  settling the asset  retirement  obligations  that have been accrued in the
accompanying balance sheets are excluded from the ceiling test calculations. The
Company also depletes the estimated  dismantlement and abandonment costs, net of
salvage values,  associated with future development activities that have not yet
been capitalized as asset retirement obligations.  These costs are also included
in the ceiling test calculation. Gasco's asset retirement obligation consists of
costs related to the plugging of wells,  removal of facilities and equipment and
site restoration on its oil and gas properties and gathering  assets.  The asset
retirement  liability is allocated to operating  expense using a systematic  and
rational  method.  The  information  below  reconciles  the  value of the  asset
retirement obligation for the periods presented.
<TABLE>
<CAPTION>

                                                                Year Ended December 31,

                                                        2006            2005               2004

<S>                                                  <C>              <C>                <C>
        Balance beginning of period                  $223,947         $108,566           $142,806
          Liabilities incurred                        545,879          123,190             29,394
          Liabilities settled                               -         (21,845)           (25,188)
          Revisions in estimated cash flows (a)        69,533                -           (55,109)
          Accretion expense                            69,184           14,036             16,663
                                                      --------         --------           --------
        Balance end of period                       $ 908,543        $ 223,947          $ 108,566
                                                    ==========       ==========         =========
</TABLE>


     (a)  Revisions represent our annual reassessment of the expected cash flows
          and assumptions  inherent in the  calculation of the asset  retirement
          liability.

                                       59
<PAGE>

Off Balance Sheet Arrangements

From time-to-time, we enter into off-balance sheet arrangements and transactions
that can give rise to off-balance  sheet  obligations.  As of December 31, 2006,
the off-balance  sheet  arrangements and transactions  that we have entered into
include  undrawn  letters  of  credit,   operating  lease   agreements  and  gas
transportation commitments. The Company does not believe that these arrangements
are reasonably  likely to materially affect its liquidity or availability of, or
requirements for, capital resources.

Revenue Recognition

The Company  records  revenues  from the sales of natural gas and crude oil when
the production is produced and sold. The Company may have an interest with other
producers in certain properties, in which case the Company uses the sales method
to account for gas  imbalances.  Under this  method,  revenue is recorded on the
basis of gas actually  sold by the Company.  In  addition,  the Company  records
revenue for its share of gas sold by other owners that cannot be  volumetrically
balanced in the future due to insufficient  remaining reserves. The Company also
reduces  revenue  for  other  owners'  gas sold by the  Company  that  cannot be
volumetrically  balanced in the future due to insufficient  remaining  reserves.
The Company's  remaining over- and  under-produced  gas balancing  positions are
considered  in the  Company's  proved oil and gas  reserves.  Gas  imbalances at
December 31, 2006 and 2005 were not significant.

Computation of Net Loss per Share

Basic net loss per share is computed by dividing  net loss  attributable  to the
common  stockholders by the weighted average number of common shares outstanding
during the reporting  period.  The shares of restricted  common stock granted to
certain  officers,  directors  and  employees of the Company are included in the
computation  only after the shares become fully  vested.  Diluted net income per
common share  includes the potential  dilution that could occur upon exercise of
the options to acquire  common  stock.  The Notes,  which are  convertible  into
16,250,000 shares of common stock and the outstanding common stock options, have
not been  included in the  computation  of diluted net loss per share during all
periods because their inclusion would have been anti-dilutive.

As of December 31, 2006, we had 86,100,015  shares of common stock  outstanding.
As of such date,  there were  9,878,502  shares of common  stock  issuable  upon
exercise of outstanding  options.  Additional options may be granted to purchase
1,895,000  shares of common stock under our stock option plan and an  additional
474,200 shares of common stock are issuable under our restricted  stock plan. As
of December 31, 2006, and as of December 31 of each succeeding  year, the number
of shares of common stock  issuable  under our stock  option plan  automatically
increases so that the total number of shares of common stock issuable under such
plan is equal to 10% of the total number of shares of common  stock  outstanding
on such date.

                                       60
<PAGE>

Assuming all of the Notes are converted at the applicable conversion prices, the
number of shares of our common stock outstanding would increase by approximately
16,250,000  shares to approximately  102,350,015  shares (this number assumes no
exercise of the options or rights described above).

Use of Estimates

The  preparation of the financial  statements for the Company in conformity with
generally accepted  accounting  principles 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 financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from these estimates.

The  Company's  financial  statements  are  based  on a  number  of  significant
estimates,  including oil and gas reserve quantities which are the basis for the
calculation of depreciation, depletion and impairment of oil and gas properties,
and timing and costs associated with its retirement obligations.

Other Comprehensive Income

The Company's short-term investments are classified as  available-for-sale,  and
are carried on the balance sheet at market value.  Unrealized  gains and losses,
net of deferred  income  taxes,  are generally  reported as other  comprehensive
income and as an  adjustment  to  stockholders'  equity.  If a decline in market
value below cost is assessed as being other than  temporary,  such impairment is
included in the  determination of net income.  The Company's  available-for-sale
securities are readily marketable and available for use in its operations should
the need arise. Therefore, the Company has classified such securities as current
assets.  As of December  31, 2006 and 2005,  the market  value of the  Company's
short-term investments approximates its cost basis and therefore,  there were no
unrealized gains and losses included in other  comprehensive  income during 2006
or 2005.

The Company does not have any other items of other comprehensive  income for the
years ended December 31, 2006,  2005 and 2004.  Therefore,  total  comprehensive
income (loss) is the same as net income (loss) for these periods.

Income Taxes

The Company uses the liability method of accounting for income taxes under which
deferred  tax  assets  and   liabilities  are  recognized  for  the  future  tax
consequences of temporary  differences  between the accounting bases and the tax
bases of the  Company's  assets and  liabilities.  The  deferred  tax assets and
liabilities are computed using enacted tax rates in effect for the year in which
the temporary differences are expected to reverse.

Stock Compensation

The Company adopted SFAS No. 123(R),  "Accounting for Stock-Based  Compensation"
which requires  companies to recognize  compensation cost for stock-based awards
based on estimated fair value of the award,  effective January 1, 2006. See Note
3 for further discussion.

                                       61
<PAGE>

Recent Accounting Pronouncements

On June 1, 2005, the Financial  Accounting  Standards Board ("FASB") issued SFAS
No. 154,  "Accounting Changes and Error Corrections",  which replaced Accounting
Principles  Board  Opinion No. 20,  Accounting  Changes and SFAS No. 3. SFAS 154
provided guidance on the accounting for and reporting of accounting  changes and
error  corrections.  It  established  retrospective  application,  or the latest
practicable  date,  as the required  method for reporting a change in accounting
principle and the reporting of a correction of an error.  SFAS 154 was effective
for  accounting  changes and  corrections  of errors made  January 1, 2006.  The
adoption of SFAS No. 154 had no impact on the Company's financial statements.

In February 2006, the FASB issued SFAS No. 155,  "Accounting  for Certain Hybrid
Financial Instruments-an amendment of FASB Statements No. 133 and 140." SFAS No.
155 amends SFAS No. 133,  "Accounting  for  Derivative  Instruments  and Hedging
Activities"  and SFAS No.  140,  "Accounting  for  Transfers  and  Servicing  of
Financial Assets and  Extinguishments  of Liabilities," and also resolves issues
addressed in SFAS No. 133 Implementation Issue No. D1, "Application of Statement
133 to Beneficial  Interests in Securitized  Financial Assets." SFAS No. 155 was
issued to eliminate  the  exemption  from  applying SFAS No. 133 to interests in
securitized  financial assets so that similar instruments are accounted for in a
similar  fashion,  regardless  of the  instrument's  form.  The Company does not
believe that its financial position, results of operations or cash flows will be
impacted  by SFAS No.  155 as the  Company  does not  currently  hold any hybrid
financial instruments.

In June 2006,  the FASB  issued  FASB  Interpretation  No. 48,  "Accounting  for
Uncertainty  in Income  Taxes"  ("FIN 48").  The  interpretation  clarifies  the
accounting for uncertainty in income taxes  recognized in a company's  financial
statements  in  accordance  with  SFAS  109,   "Accounting  for  Income  Taxes".
Specifically,  the  pronouncement  prescribes  a  recognition  threshold  and  a
measurement attribute for the financial statement recognition and measurement of
a tax position taken or expected to be taken in a tax return. The interpretation
also provides guidance on the related  derecognition,  classification,  interest
and  penalties,  accounting  for interim  periods,  disclosure and transition of
uncertain tax positions. The interpretation is effective January 1, 2006 for the
Company.  The adoption of FIN 48 is expected to have an immaterial impact on the
Company's consolidated financial position, results of operations and cash flows.

In September  2006,  the FASB issued SFAS 157, "Fair Value  Measurements".  This
Statement  defines  fair value as used in  numerous  accounting  pronouncements,
establishes  a  framework  for  measuring  fair  value  in  generally   accepted
accounting  principles and expands  disclosure  related to the use of fair value
measures in financial  statements.  The  Statement  is to be  effective  for the
Company's financial  statements issued in 2008; however,  earlier application is
encouraged.  The Company is currently  evaluating the timing of adoption and the
impact  that  adoption  might  have on its  financial  position  or  results  of
operations.

                                       62
<PAGE>

In September 2006, the Securities and Exchange  Commission  ("SEC") issued Staff
Accounting  Bulletin  No. 108 ("SAB 108").  Due to  diversity in practice  among
registrants,  SAB 108 expresses  SEC staff views  regarding the process by which
misstatements in financial  statements are evaluated for purposes of determining
whether financial statement  restatement is necessary.  SAB 108 is effective for
the Company on January 1, 2007. The Company does not believe SAB 108 will have a
material impact on its financial position or results from operations.

In December  2006,  the FASB issued FASB Staff  Position  ("FSP") EITF  00-19-2,
"Accounting for Registration Payment  Arrangements." This FSP specifies that the
contingent   obligation   to  make  future   payments  or   otherwise   transfer
consideration  under a  registration  payment  arrangement  should be separately
recognized and measured in accordance with FASB Statement No. 5, "Accounting for
Contingencies".  This FSP is  effective  immediately  for  registration  payment
arrangements and the financial  instruments  subject to those  arrangements that
are entered into or modified  subsequent to December 21, 2006. For  registration
payment  arrangements and financial  instruments  subject to those  arrangements
that were entered  into prior to December  21, 2006,  the guidance in the FSP is
effective  January 1, 2006 for the  Company.  The Company  does not believe that
this FSP will have a material  impact on its financial  position or results from
operations.

On February  15,  2007,  the FASB issued SFAS No. 159 "The Fair Value Option for
Financial  Assets  and  Financial   Liabilities."  This  Statement   establishes
presentation  and  disclosure  requirements  designed to facilitate  comparisons
between companies that choose different measurement attributes for similar types
of assets and liabilities. SFAS No. 159 is effective for the Company's financial
statements  issued in 2008. The Company is currently  evaluating the impact that
the adoption of SFAS No. 159 might have on its financial  position or results of
operations.

Reclassifications

Certain  reclassifications  have been made to prior years' amounts to conform to
the  classifications  used in the current year.  Such  reclassifications  had no
effect on the Company's net loss in any of the periods presented.

NOTE 3 - STOCK-BASED COMPENSATION

Gasco  had  followed  Accounting   Principles  Board  ("APB")  Opinion  No.  25,
"Accounting for Stock Issued to Employees", and related interpretations, through
December  31, 2005 for  accounting  for stock  option  awards to  employees  and
directors which resulted in the accounting for grants of awards to employees and
directors at their intrinsic  value in the  consolidated  financial  statements.
Accordingly,   Gasco  has  recognized  compensation  expense  in  the  financial
statement  for awards  granted to  consultants  which must be  re-measured  each
period under the mark-to-market  accounting method. Gasco had previously adopted
the provisions of FAS No. 123,  "Accounting  for Stock-Based  Compensation",  as
amended by FAS No. 148,  "Accounting for Stock-Based  Compensation -- Transition
and Disclosure", through disclosure only.

                                       63
<PAGE>

On January 1, 2006,  Gasco adopted SFAS No. 123(R),  "Accounting for Stock-Based
Compensation,"  using  the  modified  prospective  method.  Under  the  modified
prospective method, the adoption of SFAS No. 123(R) applies to new awards and to
awards modified,  repurchased,  or cancelled after December 31, 2005, as well as
to the  unvested  portion  of awards  outstanding  as of  January  1,  2006.  In
accordance  with the  modified  prospective  method,  we have not  adjusted  the
financial  statements  for periods  ended prior to January 1, 2006.  SFAS 123(R)
requires   companies   to  recognize   share-based   payments  to  employees  as
compensation expense using a fair value method. Under the fair value recognition
provisions  of SFAS  123(R),  stock-based  compensation  cost is measured at the
grant date based on the fair value of the award and is  recognized as an expense
over the service period on a straight-line basis, which generally represents the
vesting  period.  The expense  recognized over the service period is required to
include an estimate of the awards that will be forfeited. Previously, Gasco only
recorded the impact of forfeitures as they occurred for employee options.  Gasco
is assuming no  forfeitures  for  employee  awards  going  forward  based on the
Company's historical  forfeiture  experience.  For non-employee awards, Gasco is
assuming a 3% forfeiture  rate for the year ending  December 31, 2006.  The fair
value of stock  options is  calculated  using the  Black-Scholes  option-pricing
model and the fair value of  restricted  stock is based on the fair market value
of the stock on the date of grant.

We account for stock compensation  arrangements with non-employees in accordance
with SFAS No.  123(R) and  Emerging  Issues  Task  Force,  or EITF,  No.  96-18,
"Accounting  of Equity  Instruments  That Are Issued to Other Than Employees for
Acquiring,  or in  Conjunction  with Selling,  Goods or Services,"  using a fair
value approach.

As of December 31, 2006, options to purchase an aggregate of 9,878,502 shares of
the  Company's  common  stock  and  365,920  shares  of  restricted  stock  were
outstanding.  These awards were granted  during the years from 2001 through 2006
to the Company's employees, directors and consultants. The options have exercise
prices  ranging  from  $1.00 to $6.69 per  share.  The  options  vest at varying
schedules within five years of their grant date and expire within ten years from
the grant  date.  Stock-based  employee  compensation  expense  was  $4,152,268,
$344,872,  and $312,243 and stock-based  non-employee  compensation  expense was
$6,264,  $399,364,  $103,240  before tax for the years ending December 31, 2006,
2005,  and 2004.  Of this $6,264 of total  calculated  compensation  expense for
non-employees for the year ending December 31, 2006, $(759) will be expensed and
$7,023 will be capitalized relating to drilling personnel.

The  Company  recognized  the full impact of its equity  incentive  plans in the
consolidated statements of operations for the year ended December 31, 2006 under
SFAS  No.  123(R)  and did not  capitalize  any such  costs on the  consolidated
balance  sheets,  as such  costs  that  qualified  for  capitalization  were not
significant.

The adoption of SFAS No. 123R increased the Company's basic and diluted net loss
attributable to common stockholders per share by $(.05) year ending December 31,
2006. The Company did not recognize a tax benefit from share-based  compensation
expense  because the Company  considers it more likely than not that the related
deferred tax assets, which have been reduced by a full valuation allowance, will
not be recognized.

                                       64
<PAGE>

The table below summarizes the effect on net loss and net loss per share for the
years ended December 31, 2005 and 2004 as if the Company has applied the fair
value recognition of SFAS No. 123(R) to the employee based stock awards.
<TABLE>
<CAPTION>

                                                             For the Year Ended December 31,
                                                                  2005               2004
                                                                  ----               ----
    Net loss attributable to common shareholders:
<S>                                                             <C>             <C>
        As reported                                             $ (70,982)      $ (4,346,683)
        Add: Stock-based employee compensation
           included in net loss (a)                                344,873            312,243
        Less: Stock based employee compensation
          determined under the fair value based method         (2,920,997)          (757,294)
                                                               -----------          ---------
        Pro forma                                             $(2,647,106)       $(4,791,734)
                                                              ============       ============

    Net loss per common share:
        As reported                                               $ (0.00)           $ (0.07)
                                                                  ========           ========
</TABLE>

        Pro forma $ (0.04) $ (0.08) The Company uses the Black-Scholes
option-pricing model to estimate the fair value of the options at the grant
date. The fair value of options granted to the Company's employees and directors
during 2006, 2005, and 2004 was calculated using the following assumptions:


                                            Employee Options
  ---------------------------------------------------------------------------
                                    2006          2005         2004
  ---------------------------------------------------------------------------
  Expected dividend yield            --            --           --
  ---------------------------------------------------------------------------
  Expected price volatility        85-88%        75-79%       79-87%
  ---------------------------------------------------------------------------
  Risk-free interest rate       4.64 - 5.08%    3.7-3.9%     3.2-3.9%
  ---------------------------------------------------------------------------
  Expected life of options         6 years       5 years      5 years
  ---------------------------------------------------------------------------

The  weighted  average  grant-date  fair value of options  granted to  employees
during 2006, 2005, and 2004 was $3.76, $2.25, and $1.28, respectively.

The  expected  stock  price  volatility  assumption  was  determined  using  the
historical  volatility of the  Company's  common stock over the expected life of
the option.

Stock Options

The following table summarizes the stock option activity in the equity incentive
plans during the years ended December 31, 2006, 2005 and 2004:



                                       65
<PAGE>

<TABLE>
<CAPTION>




                                                       2006                        2005                        2004
------------------------------------------ ----------------------------- -------------------------- ---------------------------
                                                            Weighted                    Weighted                    Weighted
                                                             Average                     Average                    Average
                                               Stock        Exercise        Stock       Exercise       Stock        Exercise
                                              Options         Price        Options        Price       Options        Price
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
<S>                                          <C>              <C>         <C>             <C>        <C>             <C>
Outstanding at beginning of year             8,812,667        $2.29       7,043,250       $1.85      5,666,586       $2.07
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Granted                                      1,925,000        $4.97       2,450,000       $3.53      1,410,000       $1.98
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Exercised                                    (604,161)        $2.63       (643,083)       $2.16       (33,336)       $1.00
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Forfeited                                    (186,671)        $4.63        (37,500)       $3.39          0            n/a
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Expired                                      (68,333)         $3.84           0            n/a           0            n/a
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Outstanding at the end of year               9,878,502        $2.74       8,812,667       $2.29      7,043,250       $1.85
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
Exercisable at December 31,                  7,543,463        $2.14       6,574,281       $1.97      5,624,417       $1.42
------------------------------------------ -------------- -------------- ------------- ------------ ------------- -------------
</TABLE>

The following table summarizes information related to the outstanding and vested
options as of December 31, 2006:
<TABLE>
<CAPTION>

                                                                 Outstanding Options          Vested options
        ----------------------------------------------------- -------------------------- -------------------------
<S>                                                                   <C>                       <C>
        Number of shares                                              9,878,502                 7,543,463
        ----------------------------------------------------- -------------------------- -------------------------
        Weighted Average Remaining Contractual Life
                                                                        6.70                       5.92
        ----------------------------------------------------- -------------------------- -------------------------
        Weighted Average Exercise Price                                 $2.74                     $2.14
        ----------------------------------------------------- -------------------------- -------------------------
        Aggregate intrinsic value                                    $4,666,252                 $4,666,252
        ----------------------------------------------------- -------------------------- -------------------------
</TABLE>

The aggregate  intrinsic  value in the table above  represents  the total pretax
intrinsic value,  based on the Company's  closing common stock price of $2.45 as
of December 31, 2006,  which would have been received by the option  holders had
all option holders exercised their options as of that date.

The total intrinsic value of options  exercised  during the year ending December
31, 2006, 2005, and 2004 was $1,256,450,  $2,023,726, and $26,335, respectively.
The total cash  received  from  employees  as a result of employee  stock option
exercises during the year ending December 31, 2006 was approximately $1,591,679.
In connection with these exercises,  the tax benefits potentially  realizable by
the Company for the year ending December 31, 2006 were $439,758. The Company has
accumulated  net  operating  losses  sufficient  to offset its  taxable  income,
therefore, the tax benefit associated with the exercise of these options has not
been recognized.

The Company  settles  employee  stock option  exercises with newly issued common
shares.

As of December 31, 2006, there was $7,943,846 of total unrecognized compensation
cost related to non-vested  options granted under the Company's equity incentive
plans. That cost is expected to be recognized over a weighted-average  period of
1.15 years.




                                       66
<PAGE>



Restricted Stock

The following table summarizes the restricted stock activity for the years
ending December 31, 2006, 2005 and 2004:
<TABLE>
<CAPTION>


                                                     2006                        2005                        2004
----------------------------------------- --------------------------- --------------------------- ---------------------------
                                                          Weighted                    Weighted                    Weighted
                                                          Average                     Average                     Average
                                           Restricted    Fair Value    Restricted       Fair       Restricted    Fair Value
                                             Stock                       Stock         Value         Stock
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
Outstanding at the beginning of the
<S>                                         <C>            <C>          <C>            <C>          <C>            <C>
year                                        565,380        $1.58        695,850        $1.33        375,000        $0.59
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
Granted                                     131,250        $3.02         23,700        $6.81        395,850        $1.89
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
Vested                                     (305,710)       $0.96       (154,170)       $1.26        (75,000)       $0.59
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
Forfeited                                   (25,000)       $2.59           0            n/a            0            n/a
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
Outstanding at the end of the year          365,920        $2.39        565,380        $1.58        695,850        $1.33
----------------------------------------- ------------- ------------- ------------- ------------- ------------- -------------
</TABLE>

The total fair value of the shares vested  during the years ending  December 31,
2006, 2005, and 2004 was $293,608, $193,881, and $44,250, respectively.

As of December 31, 2006, there was $465,398 of total  unrecognized  compensation
cost related to non-vested  restricted  stock granted under the Company's  stock
plans. That cost is expected to be recognized over a weighted-average  period of
3.12 years.

In  connection  with the  adoption  of SFAS No.  123(R),  $443,579  of  deferred
compensation   as  of  December  31,  2005  was   reclassified   to   additional
paid-in-capital.

The following  table  summarizes  the stock options  outstanding at December 31,
2006.

                                                             Weighted Average
                                                                Remaining
                          Number of       Number of Shares    Contractual Life
Range of exercise Prices    Shares          Exercisable         (years)
   per Share              Outstanding

       $1.00 - $1.99      3,130,004            3,130,004          5.5
       $2.00 - $2.99      2,001,000            1,876,000          6.0
       $3.00 - $3.99      3,267,498            2,464,962          7.1
       $4.00 - $4.99         50,000                8,333          9.5
       $5.00 - $5.99      1,430,000               64,164          9.3
                          ---------               ------          ---
     Total                9,878,502            7,543,463          6.7
                          =========            =========          ===





                                       67
<PAGE>



NOTE 4 - OIL AND GAS PROPERTY

The Company believes that its drilling activity in the Riverbend area is
developmental. The following table presents information regarding the Company's
net costs incurred in the purchase of proved and unproved properties and in
exploration and development activities:
<TABLE>
<CAPTION>

                                            For the Years Ended December 31,
                                      ---------------------------------------------------
                                       2006               2005               2004
                                      -------------- ---------------- -------------------
        Property acquisition costs:
<S>                                     <C>                <C>               <C>
           Unproved                     $ 1,285,289        $ 410,062         $ 5,021,126
           Proved                         2,563,862               --            723,9012
        Exploration costs                 8,543,803        1,064,874             216,165
        Development costs                74,877,929       48,595,032          17,501,716
                                       ------------     ------------        -----------
           Total                        $87,270,883      $50,069,968         $23,462,908
                                        ===========      ===========         ===========
</TABLE>

Depletion and impairment expense related to proved properties per equivalent Mcf
of production for the years ended  December 31, 2006,  2005 and 2004 was $16.22,
$2.83 and $2.06, respectively.

At  December  31,  the  Company's  unproved   properties  consist  of  leasehold
acquisition and exploration costs in the following areas:

                                       2006                  2005
                                       ----                  ----

               Utah                $ 5,325,051          $ 3,040,717
               Wyoming               6,210,382            9,779,223
               California            1,002,634              313,586
               Nevada                        -              190,186
                                   ------------          -----------
                                   $12,538,067          $13,323,712
                                   ===========          ===========

During the years ended December 31, 2006 and 2005,  approximately $3,786,000 and
$5,300,000,  respectively, of unproved lease costs related primarily to expiring
acreage in Wyoming was  reclassified  to proved property and was included in the
ceiling test and depletion calculations. During 2006, the Company farmed out its
acreage in Nevada to an industry partner for the  reimbursement of acreage costs
paid by the Company.

The following table sets forth a summary of oil and gas property costs not being
amortized as of December 31, 2006, by the year in which such costs were
incurred.
<TABLE>
<CAPTION>

                                         Balance                 Costs Incurred During Years Ended December 31,
                                                       -------------------------------------------------------------------
                                         12/31/06            2006              2005            2004            Prior
                                         --------            ----              ----            ----            -----

<S>                                       <C>                <C>               <C>            <C>             <C>
Acquisition costs                         $ 9,015,405        $ 1,178,073       $ 283,114      $ 5,400,264     $ 2,153,954
Exploration costs                           3,522,662          2,205,099         791,914          219,936         305,713
                                            ---------          ---------       ---------        ---------      ----------
        Total                            $ 12,538,067        $ 3,383,172     $ 1,075,028      $ 5,620,200     $ 2,459,667
                                         ============        ===========     ===========      ===========     ===========
</TABLE>


                                       68
<PAGE>

The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill  approximately  35 gross wells in this area
during 2007.  The Company  also plans to drill one well in Wyoming  during 2007.
The unproved  costs  associated  with the  Company's  drilling  projects will be
transferred  to proved  properties as the wells are drilled during the next five
to ten years.

NOTE 5 - PROPERTY ACQUISITIONS

In August 2006, Gasco acquired certain gathering assets and producing properties
associated  with the  Riverbend  Project  in the Uinta  Basin of Utah for a cash
purchase price of $4,875,000,  plus settlement for production from the effective
date.  The  acquisition  included  approximately  21 miles of 4" to 8"  mainline
gathering pipelines and 24 oil and gas wells. In the transaction, Gasco acquired
approximately  1.6  billion  cubic  feet  equivalent  of  proved  reserves.  The
acquisition has no effect on gross acreage leasehold  positions and a negligible
effect on net acreage  leasehold  totals.  The transaction  closed on August 14,
2006,  with an  effective  date of July 1, 2006.

During December 2005, Gasco purchased a rig for approximately $5,000,000.  Gasco
entered into a one-year drilling contract with an unrelated third party who will
operate  the rig.  The  operator  may buy the rig from Gasco at the fair  market
value of the rig within three years of when the rig is delivered. This rig began
drilling in our Riverbend Project during the third quarter of 2006. Also, during
December  2005, we entered into a three-year  contract for a new-build rig to be
delivered in March 2007.  In  connection  with this contract we provided the rig
owner a letter of credit from our bank for  $6,564,000.  The cash collateral for
this  letter of credit  is  considered  usage  under  our  letter of credit  for
purposes  of  calculating  availability  and  commitment  fees.  See  Note  13 -
Commitments for further discussion.

NOTE 6 - CREDIT FACILITY

On March 29, 2006, Gasco and certain of its subsidiaries, as guarantors, entered
into a  $250,000,000  Credit  Agreement (the "Credit  Agreement")  with JPMorgan
Chase Bank, N.A., as  Administrative  Agent and the other lenders named therein.
Borrowings  made under the Credit  Agreement are guaranteed by our  subsidiaries
and secured by a pledge of the capital stock of our  subsidiaries  and mortgages
on  substantially  all of our oil and gas  properties.  We have not borrowed any
funds under the Credit Agreement since the time of its execution.

The initial  aggregate  commitment of the lenders under the Credit  Agreement is
$250,000,000,   subject  to  a  borrowing   base  which  was  initially  set  at
$17,000,000. The borrowing base was subsequently increased to $25,000,000 during
October 2006. The Credit Agreement also provides for a $10,000,000  sublimit for
letters  of  credit  which  we may use for  general  corporate  purposes.  As of
December 31, 2006 there were no loans outstanding,  however, a $6,564,000 letter
of credit is  considered  usage for  purposes of  calculating  availability  and
commitment  fees.  Our aggregate  borrowings and  outstanding  letters of credit
under the  Credit  Agreement  may not at any time  exceed  the  borrowing  base.
Interest on  borrowings  is payable  monthly and principal is due at maturity on
March 29, 2010.

                                       69
<PAGE>

Interest on borrowings under the Credit Agreement  accrues at variable  interest
rates at either,  at our election,  a Eurodollar rate or an alternate base rate.
The Eurodollar rate is calculated as LIBOR plus an applicable margin that varies
from 1.25% (for periods in which we have utilized less than 50% of the borrowing
base) to 2.00% (for  periods in which we have  utilized  greater than 90% of the
borrowing base). The alternate base rate is calculated as (1) the greater of (a)
the Prime Rate or (b) the Federal Funds  Effective  Rate plus 1/2%,  plus (2) an
applicable  margin that varies  from 0% (for  periods in which we have  utilized
less than 50% of the  borrowing  base) to 0.75%  (for  periods  in which we have
utilized  greater  than 90% of the  borrowing  base).  We elect the basis of the
interest rate at the time of each  borrowing.  In addition,  we are obligated to
pay a commitment fee under the Credit Agreement  quarterly in arrears based on a
percentage  multiplied by the daily amount that the aggregate commitments exceed
borrowings under the agreement.  The commitment fee percentage varies from 0.30%
to 0.50% based on the percentage of the borrowing base utilized.

The Credit Agreement requires us to comply with financial covenants that require
us to  maintain  (1) a Current  Ratio  (defined  as current  assets  plus unused
availability under the Credit Facility divided by current liabilities  excluding
the  current  portion of the  Credit  Facility),  determined  at the end of each
quarter,  of not less than 1.0:1;  and (2) a ratio of Senior Debt to EBITDAX (as
such terms are  defined in the Credit  Agreement)  for the most  recent  quarter
multiplied  by four not to be greater  than 3.5:1 for each  fiscal  quarter.  In
addition,  the Credit Agreement  contains covenants that restrict our ability to
incur other indebtedness,  create liens or sell our assets, pay dividends on our
common stock and make certain investments.  The Company is currently,  and as of
December 31, 2006 was, in compliance with each of the covenants contained in the
credit agreement.

The  Company  incurred  $240,262 in debt  issuance  costs  associated  with this
facility.  These costs have been  recorded as  deferred  financing  costs in the
accompanying  financial  statements  and are being  amortized over the four year
term of the credit  facility.  The credit facility is available to provide funds
for the exploration,  development  and/or acquisition of oil and gas properties,
to refinance  existing  indebtedness  and for working  capital and other general
corporate purposes.  The Credit Agreement provides for semi-annual evaluation of
the borrowing  base,  which will be determined as a percentage of the discounted
present value of the Company's oil and natural gas reserves.

NOTE 7 - CONVERTIBLE SENIOR NOTES

On October 20, 2004 (the "Issue Date"), the Company closed the private placement
of $65,000,000 in aggregate  principal  amount of its 5.50%  Convertible  Senior
Notes due 2011 (the  "Notes")  pursuant to an Indenture  dated as of October 20,
2004 (the  "Indenture"),  between the  Company  and Wells  Fargo Bank,  National
Association,  as trustee.  The amount sold  consisted of  $45,000,000  principal
amount originally  offered plus the exercise by the initial  purchasers of their
option to purchase an additional  $20,000,000  principal amount.  The Notes were
sold only to qualified  institutional  buyers in reliance on Rule 144A under the
Securities Act of 1933.

The Notes are convertible into Company Common Stock,  $.0001 par value per share
("Common  Stock"),  at any time prior to  maturity at a  conversion  rate of 250


                                       70
<PAGE>

shares of Common Stock per $1,000  principal  amount of Notes  (equivalent  to a
conversion price of $4.00 per share), which is subject to certain  anti-dilution
adjustments.

Interest on the Notes accrues from the most recent interest payment date, and is
payable in cash  semi-annually  in arrears on April 5th and  October 5th of each
year,  and commenced on April 5, 2005.  Interest is payable to holders of record
on March 15th and September  15th  immediately  preceding  the related  interest
payment dates, and will be computed on the basis of a 360-day year consisting of
twelve 30-day months.

The Company,  at its option,  may at any time on or after  October 10, 2009,  in
whole,  and from time to time in part,  redeem the Notes on not less than 20 nor
more  than 60 days'  prior  notice  mailed to the  holders  of the  Notes,  at a
redemption  price equal to 100% of the principal  amount of Notes to be redeemed
plus any accrued and unpaid  interest to but not including the redemption  date,
if the closing  price of the Common  Stock has exceeded  130% of the  conversion
price for at least 20 trading days in any consecutive 30 trading-day period.

Upon a "change of control" (as defined in the  Indenture),  each holder of Notes
can require the Company to repurchase  all of that holder's  notes 45 days after
the Company gives notice of the change of control,  at a repurchase  price equal
to 100% of the  principal  amount of Notes to be  repurchased  plus  accrued and
unpaid  interest to, but not including,  the repurchase  date, plus a make-whole
premium under certain circumstances described in the Indenture.

Pursuant to a Collateral  Pledge and Security  Agreement dated October 20, 2004,
between the Company and Wells Fargo Bank, National  Association,  as Trustee and
Collateral  Agent, the Company pledged U. S. government  securities in an amount
sufficient  upon  receipt of scheduled  principal  and  interest  payments  with
respect to such securities to provide for the payment of the first six scheduled
interest payments on the Notes. The Company used $10,313,095 of the net proceeds
from the  offering of Notes to acquire  such U. S.  government  securities,  the
remaining  balance of  $3,575,000  is recorded as  restricted  investment in the
accompanying financial statements.

The  Notes  are  unsecured  (except  as  described  above)  and   unsubordinated
obligations of the Company and rank on a parity  (except as described  above) in
right of payment with all of the  Company's  existing and future  unsecured  and
unsubordinated  indebtedness.  The Notes  effectively  rank junior to any future
secured indebtedness and junior to the Company's subsidiaries' liabilities.  The
Indenture does not contain any financial  covenants or any  restrictions  on the
payment  of  dividends,  the  repurchase  of  the  Company's  securities  or the
incurrence of indebtedness.

Upon a continuing event of default,  the trustee or the holders of 25% principal
amount of a series of Notes may declare the Notes  immediately  due and payable,
except that a default  resulting  from the  Company's  entry into a  bankruptcy,
insolvency  or  reorganization  will  automatically  cause all  Notes  under the
Indenture to become due and payable.

The fair value of the Notes is $65,000,000 as of December 31, 2006.

                                       71
<PAGE>

The  Notes are due in 2011 and  therefore  the  entire  balance  of  $65,000,000
matures in five years.

NOTE 8 - STOCKHOLDERS' EQUITY

The  Company's  capital  stock as of  December  31,  2006 and 2005  consists  of
300,000,000  authorized shares of common stock, par value $0.0001 per share, and
20,000  authorized  shares of Series B Convertible  Preferred  stock,  par value
$0.001 per share.

Series B  Convertible  Preferred  Stock - As of December 31, 2006,  Gasco had no
shares of Series B Preferred Stock  ("Preferred  Stock") issued and outstanding.
All of the  Preferred  stock was  converted by the holders  thereof into 479,599
shares of common stock during January 2006. The Preferred  Stock was entitled to
receive  dividends at the rate of 7% per annum  payable  semi-annually  in cash,
additional  shares of Preferred Stock or shares of common stock at the Company's
option.  The conversion price of the Preferred Stock was $0.70 per common share,
and the shares of the Preferred Stock were  convertible into Gasco common shares
at any time at the holder's  election.  The Preferred  Stock voted as a class on
issues that affected the Preferred Stockholders' interests and voted with shares
of common stock on all other issues on an as-converted basis. Additionally,  the
holders of the  Preferred  Stock  exercised  their  right to elect one member to
Gasco's board of directors during March 2003.

During the year  ended  December  31,  2006,  the  Company  paid  $1,393 of cash
dividends to the holders of its Preferred Stock.

Common Stock - Gasco has  86,173,715  shares of Common Stock issued,  86,100,015
shares  outstanding  and 73,700 shares held in treasury as of December 31, 2006.
The common  shareholders are entitled to one vote per share on all matters to be
voted on by the  shareholders;  however,  there are no cumulative voting rights.
Additionally,  while the  Preferred  Stock was  outstanding,  the holders of the
Preferred  Stock  were  entitled  to vote  with  shares  of  common  stock on an
as-converted  basis. The common shareholders are entitled to dividends and other
distributions as may be declared by the board of directors.  Upon liquidation or
dissolution,  the common  shareholders  will be entitled to share ratably in the
distribution  of  all  assets  remaining   available  for   distribution   after
satisfaction of all liabilities and payment of the liquidation preference of any
outstanding preferred stock.

The  Company's  common  stock  equity  transactions  during  2006  and  2005 are
described as follows:

During the fourth quarter of 2006, the Company's Board of Directors approved the
issuance of 131,250 shares of common stock, under the Gasco Energy, Inc. Amended
and Restated 2003 Restricted Stock Plan ("Restricted Stock Plan"), to certain of
the Company's  officers and  employees.  The  restricted  shares vest 20% on the
first  anniversary,  20%  on  the  second  anniversary  and  60%  on  the  third
anniversary of the awards. The shares fully vest upon certain events,  such as a
change in control of the  Company,  expiration  of the  individual's  employment
agreement and termination by the Company of the individual's  employment without
cause.  Any unvested shares are forfeited upon termination of employment for any
other reason.

                                       72
<PAGE>

The  compensation  expense  related to the restricted  stock was measured on the
issuance date using the trading price of the Company's common stock on that date
and is amortized over the three-year  vesting  period.  The shares of restricted
stock  are  considered  issued  and  outstanding  at the date of  grant  and are
included in shares  outstanding for the purposes of computing  diluted  earnings
per  share.  The  Company  had  365,920  unvested  shares  of  restricted  stock
outstanding as of December 31, 2006.

During 2006, the Company granted  1,925,000 options to purchase shares of common
stock to its employees,  directors and outside  consultants  at exercise  prices
ranging  from $2.45 to $5.69 per share.  220,000 of the options  vest 16 2/3% at
the end of each  four-month  period after the  issuance  date and 250,000 of the
options  vest 25% on the  anniversary  date of the grant at the end of each year
after the grant  date.  The  remaining  options  vest 16 2/3% at the end of each
four-month  period  commencing on the one year anniversary of the date of grant.
All of the options issued expire within ten years from the grant date.

During 2006,  82,787  shares of the  Company's  common  stock were  cancelled in
satisfaction of the income tax liability of $199,286 associated with the vesting
of restricted stock.

During 2006,  the Company  issued  604,161  shares of common stock in connection
with the exercise of options to purchase shares of common stock at strike prices
ranging from $1.61 per common share to $3.70 per common share for total proceeds
of $1,591,674.

During January 2006, certain holders of the Company's  Preferred Stock converted
the remaining 763 shares of Preferred Stock  outstanding  into 479,599 shares of
common stock.

During 2005,  the Company's  Board of Directors  approved the issuance of 23,700
shares of common  stock,  under the  Restricted  Stock  Plan to  certain  of the
Company's  officers and employees.  The restricted  shares vest 20% on the first
anniversary,  20% on the second  anniversary and 60% on the third anniversary of
the  awards.  The shares  fully vest upon  certain  events,  such as a change in
control of the Company,  expiration of the individual's employment agreement and
termination by the Company of the  individual's  employment  without cause.  Any
unvested  shares are forfeited  upon  termination  of  employment  for any other
reason.

On November 23, 2005, we closed a public offering of 12,500,000 shares of common
stock  at a price  to the  public  of  $6.50  per  share.  We also  granted  the
underwriters  a 30-day option to purchase up to 1,875,000  additional  shares of
our common stock solely to cover  over-allotments.  The  underwriters  exercised
this  option  for  an  additional  429,400  shares  of  common  stock  and  this
transaction was closed on December 6, 2005. The net proceeds from this offering,
after underwriting discount and offering costs were $79,449,446.  These proceeds
were used to fund capital  expenditures  for the  development and exploration of
Gasco's  oil  and  natural  gas  properties  and  the   development   associated
infrastructure, working capital and general corporate purposes.

During 2005,  the Company  issued  583,240  shares of common stock in connection
with the exercise of options to purchase shares of common stock at strike prices
ranging from $1.00 per common share to $3.91 per common share for total proceeds
of $1,275,685.

                                       73
<PAGE>

During 2005, certain holders of the Company's Preferred Stock converted 1,492
shares of Preferred Stock into 937,827 shares of common stock in accordance with
the terms of such Preferred Stock.

NOTE 10 - STATEMENT OF CASH FLOWS

During the year ended  December 31, 2006, the Company's  non-cash  investing and
financing activities consisted of the following transactions:

     -    Recognition  of an asset  retirement  obligation  for the plugging and
          abandonment  costs  related to the  Company's  oil and gas  properties
          valued at $615,412.

     -    Stock based compensation of $7,023 capitalized as proved property.

     -    Additions to oil and gas  properties  included in accounts  payable of
          $10,755,910.

     -    Conversion  of 763 shares of Preferred  Stock into  479,599  shares of
          common stock.

     -    Cancellation  of 82,787 shares of common stock in  satisfaction of the
          income  tax  liability  of  $199,286  associated  with the  vesting of
          restricted stock.

     -    Write-off of fully depreciated furniture and fixtures of $2,592.

During the year ended  December 31, 2005, the Company's  non-cash  investing and
financing activities consisted of the following transactions:

     -    Recognition  of an asset  retirement  obligation  for the plugging and
          abandonment  costs  related to the  Company's  oil and gas  properties
          valued at $123,190.

     -    Additions to oil and gas  properties  included in accounts  payable of
          $2,007,522.

     -    Reduction in the asset retirement  obligation of $21,845  representing
          the plugging and abandonment activity during 2005.

     -    Conversion of 1,492 shares of Preferred  Stock into 937,827  shares of
          common stock.

     -    Write-off of fully depreciated furniture and fixtures of $89,773.

During the year ended  December 31, 2004, the Company's  non-cash  investing and
financing activities consisted of the following transactions:

     -    Conversion of $2,500,000 of Convertible  Debentures  issued in October
          2003 into 4,166,665 shares of common stock.

     -    Additions to oil and gas  properties  included in accounts  payable of
          $2,556,624.

                                       74
<PAGE>

     -    Recognition  of an asset  retirement  obligation  for the plugging and
          abandonment  costs  related to the  Company's  oil and gas  properties
          valued at $29,394.

     -    Reduction in the asset retirement  obligation of $25,188  representing
          the sale of certain property interests discussed above and a reduction
          of $55,109  representing a revision to the Company's asset  retirement
          obligation.

     -    Conversion of 9,479 shares of Preferred Stock into 5,958,226 shares of
          common stock.

     -    Issuance of 41,959  shares of common  stock in payment of the June 30,
          2004 Preferred Stock dividend.

     -    Issuance of 395,850  shares of  restricted  common stock to certain of
          the Company's employees.

     -    Write - off of fully depreciated furniture and fixtures of $71,514.

Cash paid for interest  was  $3,687,124,  $3,575,000  and $463,769 for the years
ended December 31, 2006, 2005 and 2004, respectively. There was no cash paid for
income taxes in any of the years ended December 31, 2006, 2005 and 2004.

NOTE 11 - INCOME TAXES

A provision  (benefit)  for income taxes for the years ended  December 31, 2006,
2005 and 2004 consists of the following:

                                      2006           2005              2004
                                      ----           ----              ----
Current taxes:
  Federal                         $         -       $       -      $         -
  State                                     -               -                -
Deferred taxes:
  Federal                         (18,026,132)       (189,075)      (1,371,000)
  State                           (2,655,462)           (783)        (157,580)
  Less: valuation allowance        20,681,594         189,858        1,528,580
                                   ----------         -------        ---------
Net income tax provision (benefit) $     -         $     -          $     -
                                    =========        ========         ========

A  reconciliation  of the provision  (benefit) for income taxes  computed at the
statutory  rate to the  provision  for  income  taxes as shown in the  financial
statements of operations for the years ended December 31, 2006, 2005 and 2004 is
summarized below:



                                       75
<PAGE>

<TABLE>
<CAPTION>
                                                        2006            2005            2004
                                                        ----            ----            ----
<S>                                                 <C>             <C>             <C>
Tax provision (benefit) at federal statutory rate   $(19,536,218)   $    (13,172)   $ (1,429,982)
State taxes, net of federal tax effects               (1,726,051)           (509)       (104,032)
Change in Tax Rate from Prior Year                            --        (182,551)             --
Other Permanent items                                    580,675           6,374           5,434
Valuation allowance                                   20,681,594         189,858       1,528,580
                                                    ------------    ------------    ------------
Net income tax provision (benefit)                  $         --    $         --    $         --
                                                    ============    ============    ============
</TABLE>

The  components  of the deferred tax assets and  liabilities  as of December 31,
2005 and 2004 are as follows:

                                                       2006            2005
                                                       ----            ----
Deferred tax assets:
Federal and state net operating loss carryovers    $ 20,236,268    $ 12,232,737
Oil and gas property impairment                      20,647,375              --
Deferred rent                                            29,241          30,727
Deferred compensation                                 1,420,625         589,306
                                                   ------------    ------------
    Total deferred tax assets                        42,333,509      12,852,770
  Less: valuation allowance                         (28,827,261)     (8,134,543)
                                                   ------------    ------------
                                                     13,506,248       4,718,227
Deferred tax liabilities:
Oil and gas property                                  7,178,935       2,177,627
Other property, plant & equipment                     5,211,582       2,327,118
Other                                                 1,151,731         213,482
                                                   ------------    ------------
     Total deferred tax liabilities                  13,506,248       4,718,227
                                                   ------------    ------------

Net deferred tax asset                             $         --    $         --
                                                   ============    ============

The Company has  approximately  $53,227,000  of net operating loss carryover for
federal income tax purposes as of December 31, 2006, of which  $1,821,166 is not
benefited for financial  statement purposes as it relates to tax deductions that
deviate from compensation expense for financial statement purposes.  The benefit
of these excess tax deductions  will not be recognized  for financial  statement
purposes  until the related  deductions  reduce taxes  payable.  The Company has
approximately  $44,722,000  of net operating loss carryover for state income tax
purposes as of December 31, 2006, of which the above excess tax deductions  have
similarly not been benefited for financial statement purposes. The net operating
losses may offset  against  taxable  income  through the year ended December 31,
2026. A portion of the net operating loss  carryovers  begins  expiring in 2019.
The Company provided a valuation allowance against its net deferred tax asset of
$28,827,261 and $8,134,543 as of December 31, 2006 and 2005 respectively,  since
it believes  that it is more likely  than not that the net  deferred  tax assets
will not be fully  utilized on future  income tax  returns.  The increase in the
valuation allowance for 2006 and 2005 is $20,681,594 and $189,858, respectively.


                                       76
<PAGE>

NOTE 12 - RELATED PARTY TRANSACTIONS

On October 11, 2004,  the Board of Directors of Gasco,  other than Mr.  Erickson
and Mr.  Bruner,  approved a  transaction  pursuant  to which Marc  Bruner,  the
chairman  of Gasco's  Board of  Directors,  and Mark  Erickson,  a director  and
President  and Chief  Executive  Officer of Gasco,  agreed to  transfer to Gasco
their rights to receive certain  overriding  royalty interests in its properties
in exchange for the grant to each of them of options to purchase  100,000 shares
of Gasco common stock at the market price on the date of grant.  Messrs.  Bruner
and Erickson  subsequently  agreed to transfer,  and transferred  such rights to
Gasco for no options or other consideration.

For each  individual,  these  interests  range  between .06% and 0.6% of Gasco's
working interest in certain of its Utah and Wyoming properties.  Gasco will also
agree to convey equivalent royalty interests to Mr. Bruner and Mr. Erickson,  or
either of them,  in the event that it sells any of the  property  subject to the
royalty interests, upon certain change of control events or upon the involuntary
termination of either  individual.  Mr. Bruner and Mr.  Erickson  acquired these
rights under a Trust Termination and Distribution Agreement,  dated December 31,
2002, with respect to the Pannonian  Employee  Royalty Trust ("Royalty  Trust").
The Royalty Trust had been established by Pannonian Energy,  Inc.  ("Pannonian")
prior to  Pannonian  becoming a wholly  owned  subsidiary  of Gasco,  to provide
additional  compensation  to the employees and founding  directors of Pannonian,
which  included  Mr.  Bruner  and  Mr.  Erickson,  in the  form  of oil  and gas
interests.  The  terms  of the  Trust  Termination  and  Distribution  Agreement
("Termination  Agreement")  required Gasco to assign to the  participants of the
Royalty Trust overriding  royalty  interests that arise out of the production of
oil and gas  from  certain  properties  as a  result  of  future  drilling.  The
transaction  was reviewed and approved by Gasco's Audit Committee and was signed
by Mr. Erickson and Mr. Bruner on December 23, 2004.

During May 2004,  the  Company's  Board of Directors  authorized  the payment of
approximately  $65,000  to the  chairman  of the  Gasco  Board of  Directors  as
reimbursement of legal fees paid by the chairman for legal services  provided to
the Company.

During the each of years ended  December  31, 2006,  2005 and 2004,  the Company
paid $120,000 in consulting fees to a company owned by a director of Gasco. This
consulting agreement was terminated effective January 1, 2007.

Certain of the Company's  directors and officers have working and/or  overriding
royalty  interests  in oil  and gas  properties  in  which  the  Company  has an
interest.  It is expected that the directors and officers may  participate  with
the Company in future projects. All participation by directors and officers will
continue to be approved by the  disinterested  members of the Company's Board of
Directors.

NOTE 13 - COMMITMENTS

The Company leases approximately 8,776 square feet of office space in Englewood,
Colorado,  under a lease, which terminates on May 31, 2010. The average rent for
this space over the life of the lease is  approximately  $129,300 per year.  The
Company is currently in  negotiations to lease  additional  space in its current
location.




                                       77
<PAGE>



The following table shows the annual rentals per year for the life of the lease.

                  Year Ending December 31,     Annual Rentals

                            2007                  $133,927
                            2008                   141,120
                            2009                   148,313
                            2010                    63,046
                            2011                         -
                         Thereafter                      -
                                                  --------
                                                  $486,406
                                                  ========

Rent expense for the years ending December 31, 2006, 2005 and 2004 was $126,352,
$121,648 and $52,822, respectively.

As is  customary  in the oil and gas  industry,  the  Company  may at times have
commitments in place to reserve or earn certain  acreage  positions or wells. If
the Company does not pay such commitments, the acreage positions or wells may be
lost.

The Company entered into employment  agreements with three key officers  through
January 31, 2008. Total minimum  compensation under these agreements is $470,000
per annum. The agreements contain clauses regarding  termination and demotion of
the  officer  that would  require  payment of an amount  ranging  from one times
annual compensation to up to approximately five times annual compensation plus a
cash payment from $250,000 to $500,000. Included in the employment agreements is
a bonus  calculation  for each of the  covered  officers  totaling  2.125%  of a
defined cash flow figure  based on net after tax  earnings  adjusted for certain
expenses.

During 2005,  the Company  converted  the  agreements  for two of the three rigs
drilling for us from  well-to-well  contracts to two-year  term  contracts.  The
drilling rate in each of the contracts is approximately  $18,500 per day for one
rig and $22,000 for the other rig and both  contracts  expire in December  2007.
During December 2005, Gasco purchased a rig for approximately $5,000,000.  Gasco
entered  into  a  one-year  drilling  contract  that  has  a  drilling  rate  of
approximately $18,500 per day with an unrelated third party who will operate the
rig. The operator may buy the rig from Gasco at the fair market value of the rig
within three years of when the rig is delivered.  This rig began drilling in our
Riverbend  Project in the third quarter of 2006.  Also,  during  December  2005,
Gasco entered into a three-year contract with a drilling rate of $21,000 per day
for a new-build  rig to be  delivered  at the end of March 2007.  The three year
drilling  contract for the new-build rig contains a provision for the Company to
terminate the contract for $12,000 per day for the number days  remaining in the
original contract. In connection with this contract Gasco provided the rig owner
a letter of credit for  $6,564,000.  The collateral for this letter of credit is
considered   usage  under  our  line  of  credit  for  purposes  of  calculating
availability and commitment fees.




                                       78
<PAGE>



The future contractual obligations under the rig contracts are summarized below:

                                                Annual Drilling Obligations
                  Year Ending December 31,

                            2007                        $21,613,875
                            2008                          7,665,000
                            2009                          7,665,000
                            2010                          1,239,000
                                                          ---------
                           Total                        $38,182,875
                                                        ===========

Gasco has entered into a contract with a gas purchaser to sell its production at
current  prices.  The  contract  requires  Gasco to deliver a minimum  amount of
production each month,  however, the Company has elected the normal purchase and
sale exemption  under paragraph 10(b) of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities," because the Company anticipates that (1) it
will  produce  the  volumes  required  to be  delivered  under  the terms of the
contacts, (2) it is probable the delivery will be made to the counterparties and
(3) the  counterparties  will fulfill their  contractual  obligations  under the
terms of the  contracts.  As such,  the  Company  is not  required  to treat the
contract as a derivative and the contract will not be marked to market under the
provisions of SFAS No. 133.

On September  20, 2006,  Gasco entered into an agreement to purchase Brek Energy
Corporation  ("Brek")  for  equity  consideration  of  11,000,000  shares of the
Company common stock valued at  approximately  $30,000,000  based on the closing
price of Gasco's stock on September  20, 2006.  As a result of the  acquisition,
Gasco will acquire approximately 17,095 net acres in the Uinta Basin of Utah and
approximately  12,495  net  acres  in the  Green  River  Basin of  Wyoming.  The
acquisition  is expected to simplify  Gasco's  acreage  portfolio by absorbing a
working  interest  partner that previously  owned  approximately  14% of Gasco's
undeveloped  acreage  in Utah and  Wyoming.  Gasco  does not expect to incur any
additional  overhead  expenses  as a result of the  acquisition.  The  boards of
directors  of  both  Brek  and  Gasco  have  each  approved  the  terms  of  the
transaction,  which is expected to close during the second  quarter of 2007. The
completion of the transaction is subject to the approval of the  stockholders of
Brek and the completion of a distribution of certain subsidiaries of Brek to its
stockholders.

Under the terms of the  transaction,  a  wholly-owned  subsidiary  of Gasco will
merge  with and into  Brek.  As a  result  of the  merger,  Brek  will  become a
wholly-owned  subsidiary  of Gasco and each  stockholder  of Brek will receive a
number of shares of common  stock of Gasco  equal to  11,000,000  divided by the
total  number of shares of common stock of Brek  outstanding  on the date of the
merger,  calculated on a fully diluted basis.  Gasco may issue additional shares
of our common stock upon  exercise of certain Brek options and warrants  that we
intend  to  assume  in  connection  with  the Brek  acquisition.  As part of the
transaction,  the directors of Brek, who collectively own  approximately  24% of
Brek's outstanding stock, have entered into an agreement to vote their shares in
favor of the  transaction.  In  addition,  Brek's  President  and CEO,  who owns
approximately 18% of the outstanding common stock of Brek, has agreed to deposit
550,000  shares of Gasco common stock  acquired in the  transaction in escrow to
satisfy any claims with respect to breaches of representations and warranties of
Brek.

                                       79
<PAGE>

NOTE 14 - EMPLOYEE BENEFIT PLANS

The Company  adopted a 401(k) profit  sharing plan (the "Plan") in October 2001,
available to employees who meet the Plan's eligibility requirements. The Plan is
a defined contribution plan. The Company may make discretionary contributions to
the Plan and is  required  to  contribute  3% of each  participating  employee's
compensation to the Plan. The contributions made by the Company totaled $76,685,
$58,110 and $36,225  during the years ended  December 31,  2006,  2005 and 2004,
respectively.

NOTE 15 - SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial information for the years
ended December 31, 2005 and 2006.
<TABLE>
<CAPTION>

             2005                                                 For the Quarter Ended
                                     ------------------- ------------------ --------------------- --------------------
                                         March 31,           June 30,          September 30,         December 31,

<S>                                       <C>              <C>              <C>                         <C>
Gross revenue                             $1,285,347       $2,548,900       $  4,696,727                $8,458,948
Net revenue from oil
  and gas operations                         544,115          1,796,945            3,927,771             7,173,301
Net income (loss)                        (1,700,128)          (998,867)              649,303             2,012,057
Net income (loss) per share
   basic and diluted                          (0.02)             (0.01)                 0.01                  0.02
</TABLE>

The increase in gross  revenue,  net revenue from oil and gas operations and net
income is due to the Company's  drilling  activity  during the year as described
above and the increase in average oil and gas prices during 2005.  The Company's
number of gross  producing  wells  increased  from 21 gross  producing  wells at
December  31,  2004  to  42  gross   producing   wells  at  December  31,  2005.
Additionally,  the average oil and gas prices  increased  from $5.79 per mcf and
$38.43 per bbl during 2004 to $8.16 per mcf and $56.91 per bbl during 2005.

<TABLE>
<CAPTION>

            2006                                                   For the Quarter Ended
                                  ------------------- --------------------- -------------------- -------------------------
                                      March 31,             June 30,           September 30,           December 31,

<S>                                    <C>                   <C>                    <C>                    <C>
Gross revenue                          $7,259,522            $5,784,328             $ 6,058,733            $6,572,367
Net revenue from oil and gas
operations                              5,495,008             3,740,996               3,597,027             3,915,275
Net loss                                (177,157)          (53,036,083)  a            (786,759)           (1,817,768)
Net loss per share
  basic and diluted                        (0.00)                (0.62)                  (0.01)                (0.02)
</TABLE>

     a    - The increase in the Company's net loss during the second  quarter as
          compared with the other  quarters is primarily due to the  $51,000,000
          impairment recorded at June 30, 2006 as further discussed in Note 2.





                                       80
<PAGE>


NOTE 16 - CONSOLIDATING FINANCIAL STATEMENTS

On September 23, 2005, Gasco filed a Form S-3 shelf registration  statement with
the Securities  Exchange  Commission  which was  subsequently  amended in a Form
S-3/A that was filed on October 27,  2005.  Under this  registration  statement,
which was declared effective on November 1, 2005, we may from time to time offer
and sell common stock,  preferred stock,  depositary  shares and debt securities
that may be fully,  irrevocably  and  unconditionally  guaranteed  by all of our
subsidiaries:  Gasco Production Company,  San Joaquin Oil & Gas, Ltd., Riverbend
Gas Gathering,  LLC and Myton Oilfield Rentals, LLC ("Guarantor  Subsidiaries").
Set forth below are the condensed  consolidating  financial statements of Gasco,
the parent, and the Guarantor Subsidiaries.



                                       81
<PAGE>

<TABLE>
<CAPTION>




                                                   Condensed Consolidating Balance Sheet
                                                          As of December 31, 2006
                                                                (Unaudited)
                                                                                           Guarantor
                                                                Parent          Subsidiaries      Eliminations     Consolidated
ASSETS
CURRENT ASSETS
<S>                                                            <C>                   <C>                <C>           <C>
  Cash and cash equivalents                                    $ 10,831,082          $2,045,797         $     -       $ 12,876,879
  Restricted investment                                           3,575,000                   -               -          3,575,000
  Short-term investments                                          6,000,000                   -               -          6,000,000
  Accounts receivable                                                     -           9,037,036               -          9,037,036
  Inventory                                                               -           1,297,498               -          1,297,498
  Prepaid expenses                                                  618,505              25,985                            644,490
                                                                 ----------          ----------            ------       ----------
          Total                                                  21,024,587          12,406,316               -         33,430,903
                                                                 ----------          ----------            -------      ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
  Oil and gas properties (full cost method)
    Proved mineral interests                                          7,024         159,400,457               -        159,407,481
    Unproved mineral interests                                      506,049          12,032,018               -         12,538,067
  Wells in progress                                                       -           5,215,252               -          5,215,252
  Gathering assets                                                        -          12,703,346               -         12,703,346
  Facilities and equipment                                                -           8,492,632               -          8,492,632
  Furniture, fixtures and other                                     241,009                  -                -            241,009
                                                                    -------          -----------           -------      ----------
           Total                                                    754,082         197,843,705               -        198,597,787
                                                                   --------         -----------            --------    -----------
  Less accumulated depreciation, depletion and amortization       (101,985)        (68,843,794)               -       (68,945,779)
                                                                  ---------        ------------            --------   ------------
           Total                                                    652,097         128,999,911               -        129,652,008
                                                                  ---------        ------------             -------    -----------
OTHER ASSETS
  Deferred financing costs                                        2,371,507                  -                -          2,371,507
  Intercompany                                                  154,960,689       (154,960,689)               -                  -
                                                                -----------       -------------             -------    -----------
           Total                                                157,332,196       (154,960,689)               -          2,371,507
                                                                -----------       -------------             -------     ----------
TOTAL ASSETS                                                  $ 179,008,880    $   (13,554,462)          $    -       $165,454,418
                                                              =============    ================           ========    ============

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
  Accounts payable                                                $ 218,366         $16,009,690          $    -       $ 16,228,056
  Revenue payable                                                         -           1,678,427               -          1,678,427
  Advances from joint interest owners                                     -           2,955,376               -          2,955,376
  Accrued interest                                                  844,102                   -               -            844,102
  Accrued expenses                                                  595,000                                                595,000
                                                                  ---------          -----------           -------      ----------
           Total                                                  1,657,468          20,643,493               -         22,300,961
                                                                  ---------          ----------            -------      ----------

NONCURRENT LIABILITES
   5.5% Convertible Senior Notes                                 65,000,000                   -               -         65,000,000
   Asset retirement obligation                                            -             908,543               -            908,543
   Deferred rent expense                                             72,993                   -                             72,993
                                                                 ----------           ---------             ------      ----------
       Total                                                     65,072,993             908,543               -         65,981,536
                                                                 ----------           ---------             -------     ----------
STOCKHOLDERS' EQUITY
  Common stock                                                        8,617                   -               -              8,617
  Other                                                         112,269,802        (35,106,498)                         77,163,304
                                                                -----------        ------------            -------     ----------
           Total                                                112,278,419        (35,106,498)               -         77,171,921
                                                                -----------       -------------            -------      ----------
TOTAL LIABILITIES AND STOCKHOLDERS'
   EQUITY                                                      $179,008,880      $ (13,554,462)           $    -      $ 165,454,418
                                                               ============      ==============            ======      =============

</TABLE>

                                       82
<PAGE>

<TABLE>
<CAPTION>





                                                   Condensed Consolidating Balance Sheet
                                                          As of December 31, 2005
                                                                (Unaudited)
                                                                                           Guarantor
                                                             Parent         Subsidiaries      Eliminations      Consolidated
ASSETS
CURRENT ASSETS
<S>                                                         <C>                  <C>                               <C>
  Cash and cash equivalents                                 $ 59,314,343         $3,347,025                -       $ 62,661,368
  Restricted investment                                       10,139,000                  -                -         10,139,000
  Short-term investments                                      15,000,000                  -                -         15,000,000
  Accounts receivable                                                  -          4,907,192                -          4,907,192
  Inventory                                                            -          1,182,982                -          1,182,982
  Prepaid expenses                                               645,229                325                -            645,554
                                                              ----------          ---------         ----------       ----------
          Total                                               85,098,572          9,437,524                -         94,536,096
                                                              ----------          ---------         ----------       ----------
PROPERTY, PLANT AND EQUIPMENT, at cost
  Oil and gas properties (full cost method)
    Proved mineral interests                                           -         83,972,300                -         83,972,300
    Unproved mineral interests                                   274,540         13,049,172                -         13,323,712
    Gathering assets                                                   -          4,831,050                -          4,831,050
    Equipment                                                          -          5,148,388                -          5,148,388
  Furniture, fixtures and other                                  175,607                 -                 -            175,607
                                                                 -------        -------------       ---------       -----------
           Total                                                 450,147        107,000,910                -        107,451,057
                                                                 -------        -----------         ---------       -----------
  Less accumulated depreciation, depletion and amortization     (46,064)        (6,940,598)                -        (6,986,662)
                                                                --------        -----------          --------       -----------
           Total                                                 404,083        100,060,312                -        100,464,395
                                                                 -------        -----------          --------       -----------
OTHER ASSETS
  Restricted investment                                        3,565,020                  -                -          3,565,020
  Deferred financing costs                                     2,634,461                                              2,634,461
  Intercompany                                               103,081,444      (103,081,444)                -                  -
                                                             -----------      -------------           --------       ----------
           Total                                             109,280,925      (103,081,444)                -          6,199,481
                                                             -----------      -------------           --------        ---------
TOTAL ASSETS                                               $ 194,783,580       $  6,416,392          $     -       $201,199,972
                                                           =============       ============          =========     ============

LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
  Accounts payable                                             $ 785,373        $ 2,310,446         $      -        $ 3,095,819
  Revenue payable                                                      -          1,658,141                -          1,658,141
  Advances from joint interest owners                                  -          2,476,080                -          2,476,080
  Accrued interest                                               844,098                  -                -            844,098
  Accrued expenses                                               383,000                  -                -            383,000
                                                               ---------          -----------         ---------       ---------
           Total                                               2,012,471          6,444,667                -          8,457,138
                                                               ---------          ---------           ---------       ---------
NONCURRENT LIABILITES
   5.5% Convertible Senior Notes                              65,000,000                  -                -         65,000,000
   Asset retirement obligation                                         -            223,947                             223,947
   Deferred rent expense                                          78,727                  -                -             78,727
                                                              ----------           --------            --------      ----------
       Total                                                  65,078,727            223,947                -         65,302,674
                                                              ----------            -------             --------     ----------
STOCKHOLDERS' EQUITY
  Series B Convertible Preferred stock                                 1                  -                -                  1
  Common stock                                                     8,504                  -                -              8,504
  Other                                                      127,683,877          (252,222)                -        127,431,655
                                                             -----------          ---------             ------      -----------
       Total                                                 127,692,382          (252,222)                -        127,440,160
                                                             -----------          ---------             -------     -----------
TOTAL LIABILITIES AND STOCKHOLDERS'
   EQUITY                                                   $194,783,580        $ 6,416,392          $     -      $ 201,199,972
                                                            ============        ===========          =======      =============

</TABLE>

                                       83
<PAGE>

<TABLE>
<CAPTION>





                                                  Consolidating Statements of Operations

For the Year Ended December 31, 2006                                        Guarantor
                                                           Parent         Subsidiaries      Eliminations     Consolidated
REVENUES
<S>                                                             <C>          <C>                        <C>
  Oil and gas                                                   $    -       $ 21,039,172   $                   $ 21,039,172
  Gathering                                                          -          4,344,616     (2,403,557)          1,941,059
  Interest income                                            2,693,955                764                          2,694,719
                                                             ---------         ----------      ----------         ----------
          Total                                              2,693,955         25,384,552     (2,403,557)         25,674,950
                                                             ---------         ----------     -----------         ----------
OPERATING EXPENSES
  Lease operating                                                    -          5,917,125     (2,403,557)          3,513,568
  Gathering operations                                               -          2,718,357               -          2,718,357
  Depletion, depreciation and amortization                      58,513         10,827,184               -         10,885,697
  Impairment                                                                   51,000,000                         51,000,000
  General and administrative                                 9,415,787                  -               -          9,415,787
  Interest expense                                           3,959,308                  -               -          3,959,308
                                                             ---------         -----------     -------------       ---------
           Total                                            13,433,608         70,462,666       (2,403,557)       81,492,717
                                                            ----------         ----------       -----------       ----------
NET LOSS                                                  (10,739,653)       (45,078,114)               -       (55,817,767)
Preferred stock dividends                                      (1,393)                                               (1,393)
                                                           -----------        -----------        --------        -----------
NET LOSS ATTRIBUTABLE TO
  COMMON STOCKHOLDERS                                   $ (10,741,046)      $(45,078,114)          $    -     $ (55,819,160)
                                                        ==============      =============          ======     ==============



For the Year Ended December 31, 2005                                        Guarantor
                                                           Parent         Subsidiaries      Eliminations     Consolidated
REVENUES
  Oil and gas                                                   $    -       $ 14,068,307      $     -          $ 14,068,307
  Gathering                                                          -          2,258,206       (846,947)          1,411,259
  Interest income                                            1,383,740                119                          1,383,859
                                                             ---------        -----------        ---------         ---------
          Total                                              1,383,740         16,326,632       (846,947)         16,863,425
                                                             ---------         ----------       ---------         ----------
OPERATING EXPENSES
  Lease operating                                                    -          1,717,540       (846,947)            870,593
  Gathering operations                                               -          1,166,841                          1,166,841
  Depletion, depreciation and amortization                      45,648          4,797,791                          4,843,439
  General and administrative                                 5,987,019                  -               -          5,987,019
  Interest expense                                           4,033,168                  -                          4,033,168
                                                             ---------          ---------        ----------        ---------
           Total                                            10,065,835          7,682,172        (846,947         16,901,060
                                                            ----------          ---------        ----------       ----------
NET INCOME (LOSS)                                          (8,682,095)          8,644,460               -           (37,635)
Preferred stock dividends                                     (33,347)                                              (33,347)
                                                            ----------          ----------        ---------         --------
NET INCOME (LOSS) ATTRIBUTABLE TO
   COMMON STOCKHOLDERS                                   $ (8,715,442)         $8,644,460         $     -         $ (70,982)
                                                         =============         ==========         =======         ==========

</TABLE>



                                       84
<PAGE>

<TABLE>
<CAPTION>





                                                  Consolidating Statements of Operations


For the Year Ended December 31, 2004                               Guarantor
                                                   Parent          Subsidiaries      Eliminations      Consolidated
REVENUES
<S>                                                 <C>             <C>                  <C>           <C>
  Oil and gas                                       $     -         $ 3,123,888          $     -       $ 3,123,888
  Interest income                                         -             143,326                            143,326
          Total                                     324,897                 104                            325,001
                                                    -------           ----------          --------       ---------
                                                    324,897           3,267,318               -          3,592,215
                                                    -------           ---------           --------       ---------
OPERATING EXPENSES
  Lease operating                                         -             638,267                -           638,267
  Gathering operations                                    -             267,450                -           267,450
  Depletion, depreciation and amortization           12,132           1,090,443                -         1,102,575
  General and administrative                      2,714,031           1,477,947                -         4,191,978
  Interest expense                                1,597,775                   -                -         1,597,775
                                                  ---------          ----------            ------        ---------
           Total                                  4,323,938           3,474,107                -         7,798,045
                                                  ---------           ---------            ------        ---------

NET LOSS                                        (3,999,041)           (206,789)                -       (4,205,830)
Preferred stock dividends                         (140,853)                 -                  -         (140,853)
                                                 ----------           ---------            ------       ----------
NET LOSS ATTRIBUTABLE TO
   COMMON STOCKHOLDERS                          $(4,139,894)     $     (206,789)         $      -      $(4,346,683)
                                               ============          ==========            ======     ============


</TABLE>




                                       85
<PAGE>
<TABLE>
<CAPTION>






                                                 Consolidating Statements of Cash Flows

For the Year Ended December 31, 2006                                                          Guarantor
                                                            Parent          Subsidiaries      Eliminations     Consolidated

<S>                                                        <C>                  <C>                 <C>            <C>
CASH FLOWS FROM OPERATING ACTIVITIES                       $ (7,015,061)        $16,377,312         $     -        $9,362,251

CASH FLOWS FROM INVESTING ACTIVITIES
  Cash paid for furniture, fixtures and other                   (67,994)                  -               -          (67,994)
  Cash paid for acquisitions, development and exploration              -       (79,557,785)               -      (79,557,785)
  Proceeds from sale of short-term investments                 9,000,000                  -               -         9,000,000
  Cash designated as restricted                                  (9,980)                  -               -           (9,980)
  Cash undesignated as restricted                             10,139,000                                           10,139,000
                                                              ----------       -------------          -------     -----------
  Net cash provided by (used) in investing activities         19,061,026       (79,557,785)                      (60,496,759)
                                                              ----------       ------------           -------    ------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Preferred dividends                                            (1,393)                  -               -           (1,393)
  Cash paid for offering costs                                 (240,262)                  -               -         (240,262)
  Exercise of options to purchase common stock                 1,591,674                                            1,591,674
  Intercompany                                              (61,879,245)         61,879,245               -                 -
                                                            ------------         ----------           -------      ----------
   Net cash provided by financing activities                 (60,529,226)         61,879,245              -         1,350,019
                                                            ------------         ----------           --------     ----------
NET DECREASE IN CASH AND CASH
    EQUIVALENTS                                             (48,483,261)        (1,301,228)                      (49,784,489)
CASH AND CASH EQUIVALENTS:

    BEGINNING OF PERIOD                                       59,314,343          3,347,025               -        62,661,368
                                                            ------------        -----------            ---------   ----------

    END OF PERIOD                                           $ 10,831,082        $ 2,045,797          $            $12,876,879
                                                            ============        ===========           ==========  ===========

For the Year Ended December 31, 2005                                            Guarantor
                                                              Parent          Subsidiaries      Eliminations     Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES                       $ (7,222,953)         $9,357,985         $     -        $2,135,032

CASH FLOWS FROM INVESTING ACTIVITIES
  Cash paid for furniture, fixtures and other                  (106,790)                  -               -         (106,790)
  Cash paid for acquisitions, development and exploration              -       (55,181,914)               -      (55,181,914)
  Proceeds from property sales                                         -            828,102               -           828,102
  Proceeds from sale of short-term investments                12,000,000                  -               -        12,000,000
  Cash designated as restricted                              (6,816,967)                  -               -       (6,816,967)
  Cash undesignated as restricted                              3,426,042                                            3,426,042
                                                               ---------       ------------          -------     ------------
  Net cash provided by (used) in investing activities          8,502,285       (54,353,812)              -       (45,851,527)
                                                               ---------       ------------          ---------  -------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from the sale of common stock                      79,693,764                                           79,693,764
  Preferred dividends                                           (33,347)                  -               -          (33,347)
  Cash paid for offering costs                                 (275,378)                  -               -         (275,378)
  Exercise of options to purchase common stock                 1,275,743                                            1,275,743
  Intercompany                                              (45,982,844)         45,982,844               -                 -
                                                            ------------         ----------          ---------   ------------
   Net cash provided by financing activities                  34,677,938         45,982,844              -         80,660,782
                                                              ----------         ----------           --------     ----------
NET INCREASE IN CASH AND CASH
    EQUIVALENTS                                               35,957,270            987,017                        36,944,287
CASH AND CASH EQUIVALENTS:

    BEGINNING OF PERIOD                                       23,357,073          2,360,008               -        25,717,081
                                                              ----------          ---------            --------    ----------
    END OF PERIOD                                           $ 59,314,343        $ 3,347,025          $    -       $62,661,368
                                                            ============        ===========            ========   ===========
</TABLE>

                                       86
<PAGE>

<TABLE>
<CAPTION>


                                                 Consolidating Statements of Cash Flows

For the Year Ended December 31, 2004                                            Guarantor
                                                              Parent          Subsidiaries      Eliminations     Consolidated
<S>                                                           <C>               <C>          <C>
CASH FLOWS FROM OPERATING ACTIVITIES                          $(456,645)        $ (448,724)       $      -        $ (905,369)

CASH FLOWS FROM INVESTING ACTIVITIES
  Cash paid for furniture, fixtures and other                   (64,053)                  -               -          (64,053)
  Cash paid for acquisitions, development and exploration              -       (25,736,066)               -      (25,736,066)
  Proceeds from property sales                                         -          4,463,161               -         4,463,161
  Investment in short-term investments                      (27,000,000)                  -               -      (27,000,000)
  Cash designated as restricted                             (10,313,095)                  -               -      (10,313,095)
  Cash undesignated as restricted                                250,000                                              250,000
                                                             -----------       ------------        -----------    -----------
               Net cash used in investing activities        (37,127,148)       (21,272,905)              -       (58,400,053)
                                                            ------------       ------------        ----------    ------------
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from the issuance of convertible notes             65,000,000                  -               -        65,000,000
  Preferred dividends                                           (61,973)                  -                          (61,973)
  Exercise of options to purchase common stock                    33,336                  -                            33,336
  Proceeds from sale of common stock                          21,500,001                  -                        21,500,001
  Cash paid for offering costs                               (4,636,828)                                          (4,636,828)
  Proceeds from 16b violation                                    106,858                                              106,858
                                                                                          -               -
  Intercompany                                              (23,700,657)         23,700,657               -                 -
                                                            ------------         ----------          ---------      ---------
  Net cash provided by financing activities                   58,240,737         23,700,657               -        81,941,394
                                                            ------------         ----------          ------------  ----------
NET INCREASE IN CASH AND CASH
  EQUIVALENTS                                                 20,656,944          1,979,028               -        22,635,972
CASH AND CASH EQUIVALENTS:

    BEGINNING OF PERIOD                                        2,700,129            380,980                         3,081,109
                                                               ---------         ----------          ----------     ---------
    END OF PERIOD                                            $23,357,073        $ 2,360,008         $     -      $ 25,717,081
                                                             ===========        ===========         ==========   ============

</TABLE>






                                       87
<PAGE>




NOTE 17 - SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (Unaudited)

The  following  reserve  quantity and future net cash flow  information  for the
Company  represents  estimated proved reserves located in the United States. The
reserves  as of  December  31,  2006,  2005  and 2004  have  been  estimated  by
Netherland,  Sewell and Associates,  Inc., independent petroleum engineers.  The
determination  of oil and gas reserves is based on  estimates,  which are highly
complex and  interpretive.  The estimates  are subject to  continuing  change as
additional information becomes available.

The standardized  measure of discounted  future net cash flows is prepared under
the guidelines set forth by the  Securities and Exchange  Commission  (SEC) that
require the calculation to be performed  using year-end oil and gas prices.  The
oil and gas prices used as of December 31,  2006,  2005 and 2004 were $45.53 per
bbl of oil and $4.47 per Mcf, $59.87 per bbl of oil and $8.01 per Mcf of gas and
$42.25 per bbl of oil and $5.56 per Mcf of gas, respectively.  Future production
costs are based on year-end  costs and include  severance  taxes.  Each property
that is operated by the Company is also charged with field-level overhead in the
reserve calculation.  The present value of future cash inflows is based on a 10%
discount rate.




                                       88
<PAGE>
<TABLE>
<CAPTION>



Reserve Quantities
                                                             Gas                         Oil
                                                             Mcf                         Bbls
Proved Reserves:
<S>                                                         <C>                          <C>
      Balance, December 31, 2003                             13,601,003                    100,987
       Extensions and discoveries                            26,788,308                    168,451
       Revisions of previous estimates (a)                  (4,940,340)                   (28,898)
       Sales of reserves in place                           (2,879,772)                   (23,712)
       Purchases of reserves in place                         7,636,924                     62,326
       Production                                             (505,967)                    (5,080)
                                                              ---------                    -------
      Balance, December 31, 2004                             39,700,156                    274,074
       Extensions and discoveries                            49,217,928                    222,943
       Revisions of previous estimates (b)                 (12,814,086)                  (109,093)
       Sales of reserves in place                                     -                          -
       Purchases of reserves in place                                 -                          -
       Production                                           (1,648,870)                   (10,636)
                                                            -----------                   --------
      Balance, December 31, 2005                             74,455,128                    377,288
        Extensions and discoveries                           16,006,692                     97,529
        Revisions of previous estimates (c)                (47,010,172)                  (212,400)
      Sales of reserves in place                                      -                          -
      Purchases of reserves in place                            210,954                    129,810
      Production                                            (3,686,638)                   (21,646)
                                                            -----------                   --------
      Balance, December 31, 2006                             39,975,964                    370,581
                                                             ==========                    =======

Proved Developed Reserves
      Balance, December 31, 2006                            38,817,964                     370,581
                                                            ==========                 ===========
      Balance, December 31, 2005                            18,974,697                     111,655
                                                            ==========                 ===========
      Balance, December 31, 2004                             8,163,127                      69,752
                                                           ===========                  ==========
</TABLE>


     (a)  The  revisions of previous  estimates  during 2004 relate to the write
          down of the reserves  related to two wells and their offset  locations
          resulting from scale deposits in the wellbores.

     (b)  The majority of the  revisions of previous  estimates  during 2005 are
          comprised of the following:

          -    Four proved  undeveloped  locations  were  omitted  from the 2005
               reserve report because these locations  required a higher capital
               investment  than   originally   estimated  due  to  drilling  and
               completion  problems  and  due to the  lack  of  historical  data
               related to recent completions and recompletions in this area.

          -    Six  proved  undeveloped  locations  were  omitted  from the 2005
               reserve report because recent  drilling  activity  indicates that
               these  locations may be outside of or on the edge of a previously
               identified zone.

          -    Two  proved  developed  non-producing  completions  significantly
               underperformed previous forecasts.

     (c)  The majority of the revisions of previous  estimates  were a result of
          the following:

                                       89
<PAGE>

          -    Fifty gross locations previously classified as proved undeveloped
               were omitted from the 2006 reserve report because these locations
               did not yield a positive net present  value at a discount rate of
               10% at the current estimated  capital  investment based on recent
               historical data to drill and complete wells in this area.

          -    Four gross locations previously  classified as proved undeveloped
               were developed in 2006 and two gross proved undeveloped locations
               were added.

Standardized Measure of Discounted Future Net Cash Flows
<TABLE>
<CAPTION>
                                                                                December 31,
                                                                --------------------- ----------------------
                                                              2006                  2005                  2004
                                                              ----                  ----                  ----

<S>                                                          <C>                   <C>                    <C>
Future cash flows                                            $ 195,545,000         $ 618,843,800          $ 231,958,400
Future production and development costs                       (69,135,000)         (300,991,100)          (123,579,100)
Future income taxes                                                                 (23,006,800)                     -
                                                              ------------          ------------           ------------
Future net cash flows before discount                          126,410,000           294,845,900            108,379,300
                                                               -----------           -----------            -----------
10% discount to present value                                 (63,242,800)         (190,224,900)           (76,077,700)
                                                              ------------         -------------           ------------
Standardized measure of discounted
  future net cash flows                                       $ 63,167,200         $ 104,621,000           $ 32,301,600
                                                              ============         =============           ============
</TABLE>

<TABLE>
<CAPTION>
Changes in the Standardized Measure of Discounted Future Net Cash Flows

                                                                                For the Years Ended December 31,
                                                                ---------------------- ---------------------- --------------------
                                                                              2006                  2005                  2004
                                                                              ----                  ----                  ----
Standardized measure of discounted future net
<S>                                                                      <C>                    <C>                   <C>
   cash flows at the beginning of year                                   $104,621,000           $ 32,301,600          $16,195,100
Sales of oil and gas produced, net of production
   Costs                                                                 (17,525,604)           (13,197,714)          (2,485,621)
Net changes in prices and production costs                              (110,791,730)             28,283,823          (4,045,575)
Extensions and discoveries, net of future
   production and development costs                                        26,686,765            107,380,301           34,439,255
Previously estimated development costs incurred                             9,571,134            (1,681,163)           17,499,346
Changes in estimated future development costs                             127,888,117           (34,138,277)         (62,687,146)
Revisions of previous quantity estimates                                 (77,662,093)           (28,607,463)          (1,055,871)
Purchases of reserves in place                                              1,592,041                      -            1,654,068
Sales of reserves in place                                                          -                      -            (623,985)
Net change in income taxes                                                  3,225,000            (3,225,000)                    -
Accretion of discount                                                      13,773,265              3,214,885            1,619,510
Other                                                                    (18,210,695)             14,290,008           31,792,519
                                                                         ------------             ----------           ----------
Standardized measure of discounted future net cash flows at
   the end of year                                                       $ 63,167,200          $ 104,621,000        $ 32,301,600
                                                                         ============          =============        ============
</TABLE>




                                       90
<PAGE>



ITEM 9 -  CHANGES  IN AND  DISAGREEMENTS  WITH  ACCOUNTANTS  ON  ACCOUNTING  AND
FINANCIAL DISCLOSURE

None.

ITEM 9A - CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

Our management has evaluated the  effectiveness  of our disclosure  controls and
procedures as of December 31, 2006. Our  disclosure  controls and procedures are
designed to provide us with a reasonable assurance that the information required
to be disclosed in reports filed with the SEC is recorded, processed, summarized
and reported within the time periods specified in the SEC's rules and forms. The
disclosure  controls  and  procedures  are also  designed to provide  reasonable
assurance  that  such   information  is  accumulated  and  communicated  to  our
management  as  appropriate  to allow  such  persons  to make  timely  decisions
regarding required disclosures.

Our management does not expect that our disclosure  controls and procedures will
prevent all errors and all fraud.  The design of a control  system must  reflect
the fact that there are resource constraints,  and the benefits of controls must
be considered relative to their costs. Based on the inherent  limitations in all
control systems,  no evaluation of controls can provide absolute  assurance that
all control issues and instances of fraud,  if any, within the Company have been
detected.  These  inherent  limitations  include the realities that judgments in
decision-making  can be faulty and that  breakdowns  can occur because of simple
errors or mistakes. Additionally, controls can be circumvented by the individual
acts of some  persons,  by  collusion of two or more  people,  or by  management
override of the controls.  The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events.  Therefore,
a control  system,  no matter how well conceived and operated,  can provide only
reasonable,  not absolute,  assurance  that the objectives of the control system
are met. Our  disclosure  controls and  procedures  are designed to provide such
reasonable  assurances of achieving our desired control objectives,  and our CEO
and CFO have concluded,  as of December 31, 2006,  that our disclosure  controls
and procedures are effective in achieving that level of reasonable assurance.

Internal control over financial reporting

Our  internal  controls  over  financial   reporting  are  designed  to  provide
reasonable  assurance  regarding the reliability of financial  reporting and the
preparation of our financial  statements in accordance with GAAP. These internal
controls over financial  reporting  were designed  under the  supervision of our
management  and  include  policies  and  procedures  that:  (i)  pertain  to the
maintenance of records that in reasonable  detail  accurately and fairly reflect
the  transactions  and  dispositions  of our  assets,  (ii)  provide  reasonable
assurance that  transactions are recorded as necessary to permit  preparation of
financial  statements  in  accordance  with  GAAP,  and  that our  receipts  and
expenditures  are  being  made only in  accordance  with  authorizations  of our
management  and  directors  and (iii)  provide  reasonable  assurance  regarding
prevention or timely detection of unauthorized  acquisition,  use or disposition
of our assets  that could have a material  effect on our  financial  statements.


                                       91
<PAGE>

Changes in internal  control over financial  reporting during the fourth quarter
of 2006.  There have been no  changes in our  internal  control  over  financial
reporting  (as defined in Rule  13a-15(f)  under the  Exchange  Act) or in other
factors that occurred  during the fiscal quarter ended  December 31, 2006,  that
have  materially  affected or are  reasonably  likely to  materially  affect our
internal controls over financial reporting.

In accordance  with Item 308 of SEC  Regulation  S-K,  management is required to
provide  an  annual  report  regarding  internal  controls  over  our  financial
reporting.   This  report,  which  includes   management's   assessment  of  the
effectiveness of our internal controls over financial reporting, is found below.


        Management's Report on Internal Control Over Financial Reporting

Management  of the  Company is  responsible  for  establishing  and  maintaining
adequate internal control over financial reporting as defined in Rules 13a-15(f)
and  15d-15(f)  under the Exchange  Act.  The  Company's  internal  control over
financial  reporting is designed,  under the  supervision of the Company's chief
executive  and  chief  financial  officers,   to  provide  reasonable  assurance
regarding  the  reliability  of  financial  reporting  and  the  preparation  of
financial  statements  for  external  purposes  in  accordance  with  accounting
principles  generally  accepted  in the  United  States of America  (GAAP).  The
Company's internal control over financial  reporting includes those policies and
procedures  that: (i) pertain to the  maintenance of records that, in reasonable
detail,  accurately and fairly reflect the  transactions and dispositions of the
assets of the Company;  (ii) provide reasonable  assurance that transactions are
recorded  as  necessary  to  permit  preparation  of  financial   statements  in
accordance  with GAAP,  and that  receipts and  expenditures  of the Company are
being made only in accordance with authorizations of management and directors of
the Company;  and (iii) 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 the 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 my deteriorate.

Management  assessed the  effectiveness  of the Company's  internal control over
financial  reporting  as of  December  31,  2006.  In  making  this  assessment,
management   used  the  criteria  set  for  by  the   Committee  of   Sponsoring
Organizations  of  the  Treadway   Commission  in  Internal   Control-Integrated
Framework.

Based on our assessment and those criteria, management believes that the Company
maintained  effective  internal control over financial  reporting as of December
31, 2006.

The Company's  assessment of the effectiveness of the Company's internal control
over  financial  reporting  as of December  31, 2006 has been  audited by Hein &
Associates LLP, an independent  registered  public accounting firm, as stated in
their report which appears elsewhere in this report.

                                       92
<PAGE>

Pursuant to the  requirements of Rules 13a-15(f) and 15d-15(f) of the Securities
Exchange Act of 1934, as amended,  this Annual  Report on Internal  Control Over
Financial  Reporting has been signed below by the following persons on behalf of
the registrant and in the capacities indicated below on February 27, 2007.

                                        Mark A. Erickson
                                        President & Chief Executive Officer

                                        W. King Grant
                                        Chief Financial Officer


             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM


To the Board of Directors
Gasco Energy, Inc.
Englewood, Colorado

We  have  audited   management's   assessment,   included  in  the  accompanying
Management's  Report on Internal  Control Over  Financial  Reporting  that Gasco
Energy,  Inc.  ("Gasco")  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  (COSO).   Gasco'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


                                       93
<PAGE>

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 Gasco  Energy,  Inc.  maintained
effective  internal control over financial  reporting as of December 31, 2006 is
fairly  stated,  in all  material  respects,  based on criteria  established  in
Internal  Control--Integrated  Framework  issued by COSO.  Also in our  opinion,
Gasco  maintained,  in all material  respects,  effective  internal control over
financial  reporting as of December 31, 2006,  based on criteria  established in
Internal Control--Integrated Framework issued by COSO.

We have also  audited,  in accordance  with the standards of the Public  Company
Accounting   Oversight  Board  (United  States),   the  consolidated   financial
statements  of Gasco  Energy,  Inc.  and our  report  dated  February  27,  2007
expressed an unqualified opinion.



/s/ Hein & Associates LLP
Denver, Colorado
February 27, 2007


ITEM 9B - OTHER INFORMATION

None.

PART III

ITEM 10 - DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
          GOVERNANCE

The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2007 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.

ITEM 11 - EXECUTIVE COMPENSATION

The information required by this item will be included in the definitive proxy
statement of Gasco relating to the Company's 2007 Annual Meeting of Shareholders
to be filed with the SEC pursuant to Regulation 14A, which information is
incorporated herein by reference.

                                       94
<PAGE>

ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                       MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2007 Annual Meeting of Shareholders
to be filed with the SEC  pursuant  to  Regulation  14A,  which  information  is
incorporated herein by reference.

ITEM 13 - CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
          DIRECTOR INDEPENDENCE

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2007 Annual Meeting of Shareholders
to be filed with the SEC  pursuant  to  Regulation  14A,  which  information  is
incorporated herein by reference.

ITEM 14 - PRINCIPAL ACCOUNTING FEES AND SERVICES

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2007 Annual Meeting of Shareholders
to be filed with the SEC  pursuant  to  Regulation  14A,  which  information  is
incorporated herein by reference.

ITEM 15 - EXHIBITS, FINANCIAL STATEMENT SCHEDULES

          (a)  1. See "Index to Financial Statements" under Item 8 on page 101.

               2.   Financial Statement Schedules - none.

               3.   Exhibits - See Index to Exhibits, below.

                                INDEX TO EXHIBITS

2.1  Agreement  and Plan of  Reorganization  dated  January  31,  2001 among San
     Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian  Energy,  Inc.
     (incorporated  by reference to Exhibit 2.1 to the Company's  Form 8-K dated
     January 31, 2001, filed on February 2, 2001, File No. 000-26321).

2.2  Agreement and Plan of Reorganization dated December 15, 1999 by and between
     LEK  International,  Inc. and San Joaquin Oil & Gas Ltd.  (incorporated  by
     reference to Exhibit 2.1 to the Company's Form 8-K dated December 31, 1999,
     filed on January 21, 2000, File No. 000-26321).

2.3  Property Purchase Agreement dated as of April 23, 2002, between the Company
     and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1
     to the Company's Form 8-K dated May 1, 2002, filed on May 9, 2002, File No.
     000-26321).

2.4  Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy
     Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum
     (California),  Inc. and certain  stockholders  of Gasco.  (incorporated  by
     reference  to Exhibit 2.1 to the  Company's  Form 8-K dated July 16,  2002,
     filed on July 31, 2002, File No. 000-26321).



                                       95
<PAGE>




2.5  Purchase and Sale Agreement between ConocoPhillips and the Company relating
     to the  Riverbend  Field,  Uintah and Duchesne  Counties,  Utah,  Effective
     January 1, 2004  (incorporated by reference to Exhibit 2.1 to the Company's
     Form 8-K dated March 9, 2004, filed on March 15, 2004, File No. 000-26321).

2.6  Net Profits Purchase  Agreement between Gasco Production  Company,  Red Oak
     Capital Management,  LLC, MBG, LLC and MBGV Partition, LLC, dated August 6,
     2004  (incorporated  by reference to Exhibit 2.1 of the  Company's  Current
     Report on Form 8-K filed September 7, 2004, File No. 000-26321).

2.7  Purchase  Supplement  to  Net  Profits  Purchase  Agreement  between  Gasco
     Production  Company,  Red Oak Capital  Management,  LLC,  MBG, LLC and MBGV
     Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit
     2.2 of the Company's  Current  Report on Form 8-K filed  September 7, 2004,
     File No. 000-26321).

2.8  Agreement  and Plan of Merger dated  January 31,  2007,  by and among Gasco
     Energy,   Inc.,  Gasco  Acquisition,   Inc.  and  Brek  Energy  Corporation
     (incorporated  by reference to Exhibit 2.1 to the Company's  Form 8-K dated
     September 20, 2006, filed September 21, 2006, File No. 001-32369).

2.9  First  Amendment to Agreement and Plan of Merger dated January 31, 2007, by
     and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by
     reference to Exhibit 2.1 to the Company's  Form 8-K dated January 31, 2007,
     filed February 2, 2007, File No. 001-32369).

3.1  Amended and Restated  Articles of Incorporation  (incorporated by reference
     to Exhibit 3.1 to the Company's Form 8-K dated December 31, 1999,  filed on
     January 21, 2000).

3.2  Certificate  of Amendment  to Articles of  Incorporation  (incorporated  by
     reference  to Exhibit 3.1 to the  Company's  Form 8-K/A  dated  January 31,
     2001, filed on February 16, 2001, File No. 000-26321).

3.3  Certificate of Amendment to Articles of  Incorporation  dated June 21, 2005
     (incorporated  by reference to Exhibit 3.3 to the Company's Form 10-Q/A for
     the  quarter  ended  June 30,  2005,  filed on  August  9,  2005,  File No.
     001-32369).

3.4  Certificate  of  Designation  for  Series  B  Convertible  Preferred  Stock
     (incorporated  by  reference  to  Exhibit  3.5 to the  Company's  Form  S-1
     Registration Statement dated April 16, 2003, filed April 17, 2003, File No.
     333-104592).

4.1  Form of Subscription and Registration Rights Agreement,  dated as of August
     14, 2002 between the Company and certain investors  Purchasing Common Stock
     in  August,  2002.  (Filed  as  Exhibit  10.21  to the  Company's  Form S-1
     Registration  Statement  dated August 26,  2002,  filed on August 27, 2002,
     File No. 333-98759).

4.2  Form of Gasco Energy, Inc. 8.00% Convertible  Debenture,  dated October 15,
     2003 between each of The Frost National Bank,  Custodian FBO Renaissance US
     Growth &  Investment  Trust PLC Trust No.  W00740100,  HSBC Global  Custody
     Nominee (U.K.) Limited  Designation No. 896414 and The Frost National Bank,
     Custodian FBO Renaissance  Capital Growth & Income Fund III, Inc. Trust No.
     W00740000  (incorporated  by reference to Exhibit 4.6 to the Company's Form
     10-Q for the quarter ended September 30, 2003,  filed on November 10, 2003,
     File No. 000-26321).

4.3  Deed of Trust and  Security  Agreement,  dated  October  15,  2003  between
     Pannonian and BFSUS Special  Opportunities  Trust PLC,  Renaissance Capital
     Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC
     (incorporated  by reference to Exhibit 4.7 to the  Company's  Form 10-Q for
     the quarter ended September 30, 2003,  filed on November 10, 2003, File No.
     000-26321).



                                       96
<PAGE>




4.4  Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and
     Renn Capital Group,  Inc  (incorporated  by reference to Exhibit 4.8 to the
     Company's  Form 10-Q for the quarter  ended  September  30, 2003,  filed on
     November 10, 2003, File No. 000-26321).


4.5  Subsidiary Guaranty  Agreement,  dated October 15, 2003 between San Joaquin
     Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to
     Exhibit 4.9 to the Company's Form 10-Q for the quarter ended  September 30,
     2003, filed on November 10, 2003, File No. 000-26321).

4.6  Form of Subscription and Registration  Rights Agreement between the Company
     and  investors  purchasing  Common Stock in October 2003  (incorporated  by
     reference to Exhibit 4.10 to the Company's  Form 10-Q for the quarter ended
     September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.7  Form of Subscription and Registration  Rights Agreement between the Company
     and investors  purchasing Common Stock in February,  2004  (incorporated by
     reference  to  Exhibit  4.7 to the  Company's  Form 10-K for the year ended
     December 31, 2003, filed on March 26, 2004, File No. 000-26321).

4.8  Indenture  dated as of October 20, 2004,  between  Gasco  Energy,  Inc. and
     Wells  Fargo  Bank,  National  Association,  as  Trustee  (incorporated  by
     reference to Exhibit 4.1 to the Company's  Current Report on Form 8-K filed
     on October 20, 2004, File No. 000-26321).

4.9  Form of Global  Note  representing  $65  million  principal  amount of 5.5%
     Convertible  Senior Notes due 2011  (incorporated by reference to Exhibit A
     to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October
     20, 2004, File No. 000-26321).

4.10 Registration  Rights  Agreement dated October 20, 2004, among Gasco Energy,
     Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate
     by  reference to Exhibit  4.10 to the  Company's  Form 10-Q for the quarter
     ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).

4.11 Pledge and  Security  Agreement  dated  March 29,  2006 by and among  Gasco
     Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton
     Oilfield  Rentals,  LLC and  JPMorgan  Chase Bank,  N.A.  (incorporated  by
     reference  to Exhibit 4.2 to the  Company's  Form 8-K dated March 29, 2006,
     filed March 30, 2006, File No. 001-32369).

4.12 Credit  Agreement  dated March 29, 2006 by and among  Gasco  Energy,  Inc.,
     Gasco  Production  Company,  Riverbend Gas  Gathering,  LLC, Myton Oilfield
     Rentals,  LLC,  JPMorgan Chase Bank, N.A. and J.P.  Morgan  Securities Inc.
     (incorporated  by reference to Exhibit 4.1 to the Company's  Form 8-K dated
     March 29, 2006, filed March 30, 2006, File No. 001-32369).

4.13 Voting Agreement dated September 20, 2006 by and among Gasco Energy,  Inc.,
     Richard N. Jeffs,  Gregory Pek, Ian Robinson,  Michael L.  Nazmack,  Eugene
     Sweeney and Shawne Malone  (incorporated by reference to Exhibit 4.1 to the
     Company's Form 8-K dated September 20, 2006, filed September 21, 2006, File
     No. 001-32369).

#10.1 1999 Stock  Option Plan  (incorporated  by reference to Exhibit 4.1 to the
     Company's Form 10-KSB for the fiscal year ended December 31, 1999, filed on
     April 14, 2000, File No. 000-26321).

#10.2 Form  of  Stock  Option   Agreement  under  the  1999  Stock  Option  Plan
     (incorporated  by reference to Exhibit 10.8 to the Company's  Form 10-K for
     the fiscal year ended December 31, 2001,  filed on March 29, 2002, File No.
     000-26321).



                                       97
<PAGE>





#10.3 Stock Option Agreement dated January 2, 2001 between Gasco and Mark A.
     Erickson  (Filed as Exhibit 10.9 to the Company's  Form 10-K for the fiscal
     year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

#10.4 Form of Stock Option  Agreement  between Gasco and each of the individuals
     named  therein  (incorporated  by reference to Exhibit 4.6 to the Company's
     Form S-8 Registration  Statement (Reg. No.  333-122716),  filed on February
     10, 2005).


#10.5 Michael Decker Amended and Restated Employment Contract dated February 14,
     2003 (Filed as Exhibit 10.11 to the Company's Form 10-K for the fiscal year
     ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.6 Mark A. Erickson Amended and Restated  Employment  Contract dated February
     14, 2003 (Filed as Exhibit 10.12 to the Company's  Form 10-K for the fiscal
     year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.7 Amended and Restated Consulting Agreement dated February 14, 2003, between
     Gasco and Marc Bruner (Filed as Exhibit  10.13 to the  Company's  Form 10-K
     for the fiscal year ended December 31, 2002,  filed on March 29, 2003, File
     No. 000-26321).

#10.8 2003  Restricted  Stock Plan (Filed as Appendix B to the  Company's  Proxy
     Statement   dated   August  25,  2003  for  its  2003  Annual   Meeting  of
     Stockholders, filed on August 25, 2003, File No. 000-26321).

10.9 Muddy Creek  Exploration  Agreement  dated August 15, 2001,  between Gasco,
     Shama Zoe Limited  Partnership and Burlington Oil and Gas Company (Filed as
     Exhibit 10.15 to the Company's Form 10-K for the fiscal year ended December
     31, 2001, filed on March 29, 2002, File No. 000-26321).

10.10 CD Exploration  Agreement dated August 15, 2001,  between Gasco, Shama Zoe
     Limited  Partnership  and  Burlington Oil and Gas Company (Filed as Exhibit
     10.16 to the  Company's  Form 10-K for the fiscal year ended  December  31,
     2001, filed on March 29, 2002, File No. 000-26321).

10.11 Gamma Ray  Exploration  Agreement  dated August 15, 2001,  between  Gasco,
     Shama Zoe Limited  Partnership and Burlington Oil and Gas Company (Filed as
     Exhibit 10.17 to the Company's Form 10-K for the fiscal year ended December
     31, 2001, filed on March 29, 2002, File No. 000-26321).

10.12 Sublette  County,  WY AMI Agreement  dated August 22, 2001 between  Gasco,
     Alpine Gas Company  and  Burlington  Oil and Gas Company  (Filed as Exhibit
     10.18 to the  Company's  Form 10-K for the fiscal year ended  December  31,
     2001, filed on March 29, 2002, File No. 000-26321).

10.13 Lead  Contractor  Agreement  dated  January 24,  2002,  between  Gasco and
     Halliburton Energy Services,  Inc. (Filed as Exhibit 10.19 to the Company's
     Form 10-K for the fiscal year ended  December 31, 2001,  filed on March 29,
     2002, File No. 000-26321).

10.14 Property  Purchase  Agreement,  dated as of April 23,  2002,  between  the
     Company  and Shama Zoe  Limited  Partnership  (Filed as Exhibit  2.1 to the
     Company's  Form 8-K  dated  May 1,  2002,  filed on May 9,  2002,  File No.
     000-26321).

10.15 Purchase  Agreement,  dated  as of  July  16,  2002,  among  the  Company,
     Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation,
     Brek  Petroleum  Inc.,  Brek  Petroleum  (California),   Inc.  and  certain
     stockholders (Filed as Exhibit 2.1 to the Company's Form 8-K dated July 16,
     2002, filed on July 31, 2002, File No. 000-26321).

10.16 Amendment No. 1 to Property Purchase  Agreement dated as of August 9, 2002
     between the Company  and Shama Zoe Limited  Partnership.  (Filed as Exhibit
     10.22 to the Company's Form S-1 dated August 15, 2002,  filed on August 17,
     2002, File No. 333-98759).



                                       98
<PAGE>




10.17 Financial  Advisory Services  Agreement dated August 22, 2002, between the
     Company and Energy Capital  Solutions  LLC.  (Filed as Exhibit 10.23 to the
     Company's Form S-1 dated August 16, 2002, filed on August 17, 2002 File No.
     333-98759).

10.18 Termination and Settlement Agreement, dated as of December 23, 2004, among
     Gasco Energy,  Inc.,  Marc A. Bruner and Mark A. Erickson (Filed as Exhibit
     10.1 to the Company's Current Report on Form 8-K filed on January 31, 2005,
     File No. 001-32369).

10.19 Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I,
     LLC,  Nabors  Drilling  USA,  LP, Pool Well  Services  Co., Red Oak Capital
     Management LLC and Schlumberger  Technology  Corporation  dated January 16,
     2004  (incorporated  by reference to Exhibit 10.1 to the Company's  Current
     Report on Form 8-K filed on January 21, 2004, File No. 000-26321).

#10.20 Employment Agreement dated February 14, 2005 by and between Gasco Energy,
     Inc.  and W. King Grant  (incorporated  by  reference to Exhibit 4.2 to the
     Company's  Form 10-Q for the  quarter  ended March 31,  2006,  filed May 5,
     2006, File No. 001-32369).

*23.1 Consent of Netherland, Sewell & Associates, Inc.

*23.2 Consent of Hein & Associates LLP

*31  Rule 13a-14(a)/15d-14(a) Certifications

*32  Section 1350 Certifications

     * Filed herewith.

     # Identifies management contracts and compensatory plans or arrangements.



                                       99
<PAGE>



SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Exchange Act, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

GASCO ENERGY, INC.                           Dated:  February 27, 2007



By:      /s/ Mark A. Erickson
         ------------------------------
           Mark A. Erickson, President and CEO

Pursuant to the requirements of the Securities 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 dates indicated.
<TABLE>


   Signature                                           Title                                                Date

<S>                                  <C>                                                              <C>
/s/ Mark A. Erickson                 Director and President and Chief Executive Officer                February 27, 2007
--------------------
Mark A. Erickson

/s/ Marc A. Bruner                   Director                                                          February 27, 2007
---------------------
Marc A. Bruner

/s/ Carl Stadelhofer                 Director                                                          February 27, 2007
--------------------
Carl Stadelhofer

/s/ W. King Grant                    Executive Vice President and Chief Financial Officer              February 27, 2007
-----------------
W. King Grant                        (Principal Financial Officer and Principal Accounting
                                     Officer)

/s/ Carmen Lotito                    Director                                                          February 27, 2007
-----------------
Carmen ("Tony") Lotito

/s/ Charles B. Crowell               Director                                                          February 27, 2007
----------------------
Charles B. Crowell

/s/ Richard S. Langdon               Director                                                          February 27, 2007
----------------------
Richard S. Langdon

/s/ R. J. Burgess                    Director                                                          February 27, 2007
---------------------
R.J. Burgess

/s/ John A. Schmit                   Director                                                          February 27, 2007
------------------
John A. Schmit

</TABLE>

                                      100
<PAGE>


                                INDEX TO EXHIBITS

2.1  Agreement  and Plan of  Reorganization  dated  January  31,  2001 among San
     Joaquin Resources Inc., Nampa Oil & Gas, Ltd., and Pannonian  Energy,  Inc.
     (incorporated  by reference to Exhibit 2.1 to the Company's  Form 8-K dated
     January 31, 2001, filed on February 2, 2001, File No. 000-26321).

2.2  Agreement and Plan of Reorganization dated December 15, 1999 by and between
     LEK  International,  Inc. and San Joaquin Oil & Gas Ltd.  (incorporated  by
     reference to Exhibit 2.1 to the Company's Form 8-K dated December 31, 1999,
     filed on January 21, 2000, File No. 000-26321)).

2.3  Property Purchase Agreement dated as of April 23, 2002, between the Company
     and Shama Zoe Limited Partnership (incorporated by reference to Exhibit 2.1
     to the Company's Form 8-K dated May 1, 2002, filed on May 9, 2002, File No.
     000-26321)).

2.4  Purchase Agreement dated as of July 16, 2002, among Gasco, Pannonian Energy
     Inc., San Joaquin Oil & Gas Ltd., Brek, Brek Petroleum Inc., Brek Petroleum
     (California),  Inc. and certain  stockholders  of Gasco.  (incorporated  by
     reference  to Exhibit 2.1 to the  Company's  Form 8-K dated July 16,  2002,
     filed on July 31, 2002, File No. 000-26321)).

2.5  Purchase and Sale Agreement between ConocoPhillips and the Company relating
     to the  Riverbend  Field,  Uintah and Duchesne  Counties,  Utah,  Effective
     January 1, 2004  (incorporated by reference to Exhibit 2.1 to the Company's
     Form  8-K  dated  March  9,  2004,  filed  on  March  15,  2004,  File  No.
     000-26321)).

2.6  Net Profits Purchase  Agreement between Gasco Production  Company,  Red Oak
     Capital Management,  LLC, MBG, LLC and MBGV Partition, LLC, dated August 6,
     2004  (incorporated  by reference to Exhibit 2.1 of the  Company's  Current
     Report on Form 8-K filed September 7, 2004, File No. 000-26321)).

2.7  Purchase  Supplement  to  Net  Profits  Purchase  Agreement  between  Gasco
     Production  Company,  Red Oak Capital  Management,  LLC,  MBG, LLC and MBGV
     Partition, LLC, dated August 20, 2004 (incorporated by reference to Exhibit
     2.2 of the Company's  Current  Report on Form 8-K filed  September 7, 2004,
     File No. 000-26321).

2.8  Agreement  and Plan of Merger dated  January 31,  2007,  by and among Gasco
     Energy,   Inc.,  Gasco  Acquisition,   Inc.  and  Brek  Energy  Corporation
     (incorporated  by reference to Exhibit 2.1 to the Company's  Form 8-K dated
     September 20, 2006, filed September 21, 2006, File No. 001-32369).

2.9  First  Amendment to Agreement and Plan of Merger dated January 31, 2007, by
     and between Gasco Energy, Inc. and Brek Energy Corporation (incorporated by
     reference to Exhibit 2.1 to the Company's  Form 8-K dated January 31, 2007,
     filed February 2, 2007, File No. 001-32369).

3.1  Amended and Restated  Articles of Incorporation  (incorporated by reference
     to Exhibit 3.1 to the Company's Form 8-K dated December 31, 1999,  filed on
     January 21, 2000, File No. 000-26321).

3.2  Certificate  of Amendment  to Articles of  Incorporation  (incorporated  by
     reference  to Exhibit 3.1 to the  Company's  Form 8-K/A  dated  January 31,
     2001, filed on February 16, 2001, File No. 000-26321).

3.3  Certificate of Amendment to Articles of  Incorporation  dated June 21, 2005
     (incorporated  by reference to Exhibit 3.3 to the Company's Form 10-Q/A for
     the  quarter  ended  June 30,  2005,  filed on  August  9,  2005,  File No.
     001-32369).

3.4  Certificate  of  Designation  for  Series  B  Convertible  Preferred  Stock
     (incorporated  by  reference  to  Exhibit  3.5 to the  Company's  Form  S-1
     Registration Statement dated April 16, 2003, filed April 17, 2003, File No.
     333-104592).



                                      101
<PAGE>





4.1  Form of Subscription and Registration Rights Agreement,  dated as of August
     14, 2002 between the Company and certain investors  Purchasing Common Stock
     in  August,  2002.  (Filed  as  Exhibit  10.21  to the  Company's  Form S-1
     Registration  Statement  dated August 26,  2002,  filed on August 27, 2002,
     File No. 333-98759).

4.2  Form of Gasco Energy, Inc. 8.00% Convertible  Debenture,  dated October 15,
     2003 between each of The Frost National Bank,  Custodian FBO Renaissance US
     Growth &  Investment  Trust PLC Trust No.  W00740100,  HSBC Global  Custody
     Nominee (U.K.) Limited  Designation No. 896414 and The Frost National Bank,
     Custodian FBO Renaissance  Capital Growth & Income Fund III, Inc. Trust No.
     W00740000  (incorporated  by reference to Exhibit 4.6 to the Company's Form
     10-Q for the quarter ended September 30, 2003,  filed on November 10, 2003,
     File No. 000-26321).

4.3  Deed of Trust and  Security  Agreement,  dated  October  15,  2003  between
     Pannonian and BFSUS Special  Opportunities  Trust PLC,  Renaissance Capital
     Growth & Income Fund III, Inc. and Renaissance US Growth & Income Trust PLC
     (incorporated  by reference to Exhibit 4.7 to the  Company's  Form 10-Q for
     the quarter ended September 30, 2003,  filed on November 10, 2003, File No.
     000-26321).

4.4  Subsidiary Guaranty Agreement, dated October 15, 2003 between Pannonian and
     Renn Capital Group,  Inc  (incorporated  by reference to Exhibit 4.8 to the
     Company's  Form 10-Q for the quarter  ended  September  30, 2003,  filed on
     November 10, 2003, File No. 000-26321).

4.5  Subsidiary Guaranty  Agreement,  dated October 15, 2003 between San Joaquin
     Oil and Gas, Ltd. And Renn Capital Group, Inc (incorporated by reference to
     Exhibit 4.9 to the Company's Form 10-Q for the quarter ended  September 30,
     2003, filed on November 10, 2003, File No. 000-26321).

4.6  Form of Subscription and Registration  Rights Agreement between the Company
     and  investors  purchasing  Common Stock in October 2003  (incorporated  by
     reference to Exhibit 4.10 to the Company's  Form 10-Q for the quarter ended
     September 30, 2003, filed on November 10, 2003, File No. 000-26321).

4.7  Form of Subscription and Registration  Rights Agreement between the Company
     and investors  purchasing Common Stock in February,  2004  (incorporated by
     reference  to  Exhibit  4.7 to the  Company's  Form 10-K for the year ended
     December 31, 2003, filed on March 26, 2004, File No. 000-26321).

4.8  Indenture  dated as of October 20, 2004,  between  Gasco  Energy,  Inc. and
     Wells  Fargo  Bank,  National  Association,  as  Trustee  (incorporated  by
     reference to Exhibit 4.1 to the Company's  Current Report on Form 8-K filed
     on October 20, 2004, File No. 000-26321).

4.9  Form of Global  Note  representing  $65  million  principal  amount of 5.5%
     Convertible  Senior Notes due 2011  (incorporated by reference to Exhibit A
     to Exhibit 4.1 to the Company's Current Report on Form 8-K filed on October
     20, 2004, File No. 000-26321).

4.10 Registration  Rights  Agreement dated October 20, 2004, among Gasco Energy,
     Inc., J.P. Morgan Securities Inc. and First Albany Capital Inc (incorporate
     by  reference to Exhibit  4.10 to the  Company's  Form 10-Q for the quarter
     ended September 30, 2004 filed on November 12, 2004, File No. 000-26321).

4.11 Pledge and  Security  Agreement  dated  March 29,  2006 by and among  Gasco
     Energy, Inc., Gasco Production Company, Riverbend Gas Gathering, LLC, Myton
     Oilfield  Rentals,  LLC and  JPMorgan  Chase Bank,  N.A.  (incorporated  by
     reference  to Exhibit 4.2 to the  Company's  Form 8-K dated March 29, 2006,
     filed March 30, 2006, File No. 001-32369).



                                      102
<PAGE>





4.12 Credit  Agreement  dated March 29, 2006 by and among  Gasco  Energy,  Inc.,
     Gasco  Production  Company,  Riverbend Gas  Gathering,  LLC, Myton Oilfield
     Rentals,  LLC,  JPMorgan Chase Bank, N.A. and J.P.  Morgan  Securities Inc.
     (incorporated  by reference to Exhibit 4.1 to the Company's  Form 8-K dated
     March 29, 2006, filed March 30, 2006, File No. 001-32369).

4.13 Voting Agreement dated September 20, 2006 by and among Gasco Energy,  Inc.,
     Richard N. Jeffs,  Gregory Pek, Ian Robinson,  Michael L.  Nazmack,  Eugene
     Sweeney and Shawne Malone  (incorporated by reference to Exhibit 4.1 to the
     Company's Form 8-K dated September 20, 2006, filed September 21, 2006, File
     No. 001-32369).

#10.1 1999 Stock  Option Plan  (incorporated  by reference to Exhibit 4.1 to the
     Company's Form 10-KSB for the fiscal year ended December 31, 1999, filed on
     April 14, 2000).

#10.2 Form  of  Stock  Option   Agreement  under  the  1999  Stock  Option  Plan
     (incorporated  by reference to Exhibit 10.8 to the Company's  Form 10-K for
     the fiscal year ended December 31, 2001,  filed on March 29, 2002, File No.
     000-26321).

#10.3 Stock Option  Agreement  dated  January 2, 2001 between  Gasco and Mark A.
     Erickson  (Filed as Exhibit 10.9 to the Company's  Form 10-K for the fiscal
     year ended December 31, 2001, filed on March 29, 2002, File No. 000-26321).

#10.4 Form of Stock Option  Agreement  between Gasco and each of the individuals
     named  therein  (incorporated  by reference to Exhibit 4.6 to the Company's
     Form S-8 Registration  Statement (Reg. No.  333-122716),  filed on February
     10, 2005).


#10.5 Michael Decker Amended and Restated Employment Contract dated February 14,
     2003 (Filed as Exhibit 10.11 to the Company's Form 10-K for the fiscal year
     ended December 31, 2002, filed on March 29, 2003) , File No. 000-26321.


#10.6 Mark A. Erickson Amended and Restated  Employment  Contract dated February
     14, 2003 (Filed as Exhibit 10.12 to the Company's  Form 10-K for the fiscal
     year ended December 31, 2002, filed on March 29, 2003, File No. 000-26321).

#10.7 Amended and Restated Consulting Agreement dated February 14, 2003, between
     Gasco and Marc Bruner (Filed as Exhibit  10.13 to the  Company's  Form 10-K
     for the fiscal year ended December 31, 2002,  filed on March 29, 2003, File
     No. 000-26321).

#10.8 2003  Restricted  Stock Plan (Filed as Appendix B to the  Company's  Proxy
     Statement   dated   August  25,  2003  for  its  2003  Annual   Meeting  of
     Stockholders, filed on August 25, 2003, File No. 000-26321).

10.9 Muddy Creek  Exploration  Agreement  dated August 15, 2001,  between Gasco,
     Shama Zoe Limited  Partnership and Burlington Oil and Gas Company (Filed as
     Exhibit 10.15 to the Company's Form 10-K for the fiscal year ended December
     31, 2001, filed on March 29, 2002, File No. 000-26321).

10.10 CD Exploration  Agreement dated August 15, 2001,  between Gasco, Shama Zoe
     Limited  Partnership  and  Burlington Oil and Gas Company (Filed as Exhibit
     10.16 to the  Company's  Form 10-K for the fiscal year ended  December  31,
     2001, filed on March 29, 2002, File No. 000-26321).

10.11 Gamma Ray  Exploration  Agreement  dated August 15, 2001,  between  Gasco,
     Shama Zoe Limited  Partnership and Burlington Oil and Gas Company (Filed as
     Exhibit 10.17 to the Company's Form 10-K for the fiscal year ended December
     31, 2001, filed on March 29, 2002, File No. 000-26321).

10.12 Sublette  County,  WY AMI Agreement  dated August 22, 2001 between  Gasco,
     Alpine Gas Company  and  Burlington  Oil and Gas Company  (Filed as Exhibit
     10.18 to the  Company's  Form 10-K for the fiscal year ended  December  31,
     2001, filed on March 29, 2002, File No. 000-26321).

                                      103
<PAGE>

10.13 Lead  Contractor  Agreement  dated  January 24,  2002,  between  Gasco and
     Halliburton Energy Services,  Inc. (Filed as Exhibit 10.19 to the Company's
     Form 10-K for the fiscal year ended  December 31, 2001,  filed on March 29,
     2002, File No. 000-26321).

10.14 Property  Purchase  Agreement,  dated as of April 23,  2002,  between  the
     Company  and Shama Zoe  Limited  Partnership  (Filed as Exhibit  2.1 to the
     Company's  Form 8-K  dated  May 1,  2002,  filed on May 9,  2002,  File No.
     000-26321).

10.15 Purchase  Agreement,  dated  as of  July  16,  2002,  among  the  Company,
     Pannonian Energy Inc., San Joaquin Oil & Gas Ltd., Brek Energy Corporation,
     Brek  Petroleum  Inc.,  Brek  Petroleum  (California),   Inc.  and  certain
     stockholders (Filed as Exhibit 2.1 to the Company's Form 8-K dated July 16,
     2002, filed on July 31, 2002, File No. 000-26321).

10.16 Amendment No. 1 to Property Purchase  Agreement dated as of August 9, 2002
     between the Company  and Shama Zoe Limited  Partnership.  (Filed as Exhibit
     10.21 to the Company's Form S-1 dated November 15, 2002,  filed on November
     15, 2002, File No. 333-98759)).

10.17 Financial  Advisory Services  Agreement dated August 22, 2002, between the
     Company and Energy Capital  Solutions  LLC.  (Filed as Exhibit 10.23 to the
     Company's Form S-1 dated August 16, 2002, filed on August 17, 2002 File No.
     333-98759).

10.18 Termination and Settlement Agreement, dated as of December 23, 2004, among
     Gasco Energy,  Inc.,  Marc A. Bruner and Mark A. Erickson (Filed as Exhibit
     10.1 to the Company's Current Report on Form 8-K filed on January 31, 2005,
     File No. 001-32369).

10.19 Joint Value Enhancement Agreement by and among Pannonian Energy Inc., M-I,
     LLC,  Nabors  Drilling  USA,  LP, Pool Well  Services  Co., Red Oak Capital
     Management LLC and Schlumberger  Technology  Corporation  dated January 16,
     2004  (incorporated  by reference to Exhibit 10.1 to the Company's  Current
     Report on Form 8-K filed on January 21, 2004, File No. 000-26321).

#10.20 Employment Agreement dated February 14, 2005 by and between Gasco Energy,
     Inc.  and W. King Grant  (incorporated  by  reference to Exhibit 4.2 to the
     Company's  Form 10-Q for the  quarter  ended March 31,  2006,  filed May 5,
     2006, File No. 001-32369).

*23.1 Consent of Netherland, Sewell & Associates, Inc.

*23.2 Consent of Hein & Associates LLP

*31  Rule 13a-14(a)/15d-14(a) Certifications

*32  Section 1350 Certifications

     * Filed herewith.

     # Identifies management contracts and compensatory plans or arrangements.



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