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, 2004

       [ ]   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.)

       14 Inverness Drive East, Building H, Suite 236, 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 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 an  accelerated  filer (as
defined in Rule 12b-2 of the Act). Yes X No __

As of June 30, 2004,  approximately 45,344,954 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 $88,422,660. As of March 15, 2005, approximately 70,517,209 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 2005 annual meeting of stockholders to be filed within
120 days after December 31, 2004.


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                                Table of Contents

                                     Part I

Item 1.  Description of Business...............................................2
              Business of Gasco................................................2
              History..........................................................2
              Acquisition, Exploration and Development Expenses................3
              Principal Products or Services and Markets.......................3
              Competitive Business Conditions, Competitive Position in the
                 Industry and Methods of Competition...........................3
              Governmental Regulations and Environmental Laws..................4
              Number of Total Employees and Number of Full-Time Employees......5
              Risk Factors.....................................................6
              Cautionary Statement Regarding Forward-Looking Statements.......17

Item 2.  Description of Property..............................................18
              Petroleum and Natural Gas Properties............................18
              Company Reserve Estimates.......................................21
              Volumes, Prices and Operating Expenses..........................22
              Development, Exploration and Acquisition Capital Expenditures...22
              Productive Gas Wells............................................23
              Oil and Gas Acreage.............................................23
              Drilling Activity...............................................25
              Office Space....................................................25

Item 3.  Legal Proceedings....................................................25

Item 4.  Submission of Matters to a Vote of Security Holders..................25

                               Part II

Item 5.  Market for Common Equity and Related Stockholder Matters.............26
              Equity Compensation Plans.......................................26
              Securities Transactions.........................................28

Item 6.  Selected Financial Data..............................................29

Item 7.  Management's Discussion and Analysis.................................29
              Forward Looking Statements......................................29
              Overview........................................................29
              Liquidity and Capital Resources.................................31
              Capital Budget..................................................33
              Schedule of Contractual Obligations.............................34
              Critical Accounting Policies and Estimates......................35
              Results of Operations...........................................37
              Recent Accounting Pronouncements................................39


<PAGE>



                    Table of Contents (continued)

Item 7A.  Quantitative and Qualitative Disclosures about Market Risk..........41

Item 8.   Financial Statements................................................42

Item 9.   Changes in and Disagreements with Accountants on Accounting and
            Financial Disclosure..............................................75

Item 9A.  Controls and Procedures.............................................75

Item 9B.  Other Information...................................................76

                              Part III

Item 10.  Directors and Executive Officers of the Registrant..................77

Item 11.  Executive Compensation..............................................77

Item 12.  Security Ownership of Certain Beneficial Owners and Management......77

Item 13.  Certain Relationships and Related Transactions......................77

Item 14.  Principal Accountant Fees and Services..............................77

Item 15.  Exhibits and Financial Statement Schedules..........................77










<PAGE>

PART I

ITEM 1 - DESCRIPTION OF BUSINESS

Business of Gasco

Gasco  Energy,  Inc.  ("Gasco" or "the  Company") is a natural gas and petroleum
exploitation,  development  and  production  company  engaged  in  locating  and
developing hydrocarbon prospects, primarily in the Rocky Mountain region. "Our",
"we", and "us" as used in this annual report,  also refer to Gasco Energy,  Inc.
The Company'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.  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 these leases.  The Company is currently focusing its drilling efforts
in the  Riverbend  Project  located  in the Uinta  Basin of  northeastern  Utah,
targeting the Wasatch, Mesaverde and Blackhawk formations.

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 know 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  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.  All information  presented for periods prior to March 30,
2001 represents the historical information of GPC.

                                       2
<PAGE>

Acquisition, Exploration and Development Expenses

During the year ended December 31, 2004 the Company entered into agreements with
third party service providers and investors who contributed approximately 70% of
the cost of developing  designated  wells.  During 2004, the Company completed a
property  acquisition of additional working interests in six producing wells and
certain  acreage  and  gathering  system  assets  for a net  purchase  price  of
approximately  $2,400,000,  acquired approximately 16,000 net acres in Uinta and
Duchesne  Counties Utah for  approximately  $3,432,000 and spent  $18,441,782 in
development and exploration activities. During the year ended December 31, 2003,
the Company spent $5,283,426 in development and exploration  activities.  During
the year ended December 31, 2002, the Company spent  $32,962,855,  including the
issuance of  9,500,000  shares of common  stock  valued at  $18,525,000,  in the
acquisition of additional  leases and in the development and exploitation of the
properties subject to these leases.  During 2004, the Company also completed the
expansion  of a gathering  system  located in Uinta  County Utah that  currently
gathers  approximately  97% of the Company's gas  production in this area. As of
December 31, 2004,  the Company  held working  interests in 266,886  gross acres
(136,922 net acres) located in Utah, Wyoming and California.  As of December 31,
2004,  the  Company  held an  interest  in 21 gross  (7.1  net to the  Company's
interest) producing gas wells and 3 gross (1.6 net) shut-in gas wells located on
these  properties.  As of March 15, 2005 the Company operates 25 wells, of which
23 are currently producing. See "Item 2 - Description of Properties".

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  companies,  utilities,  refining  companies  and private
industry end-users. Historically, nearly all of the Company's sales have been to
a few customers.  However, Gasco is not confined to, nor dependent upon, any one
purchaser  or  small  group  of  purchasers.  Accordingly,  the loss of a single
purchaser would not 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, 2004,  2003 and 2002,  purchases by the  following
company exceeded 10% of the total oil and gas revenues of the Company.

                                        Percent of Production Purchased
                                        For the Year Ended December 31,
                               ------------------------------------------------
                                    2004            2003            2002
                                    ----            ----            ----

      ConocoPhillips Company        93%              93%            98%


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


                                       3
<PAGE>

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
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  obtaining  drilling rigs and
services,  and the  manpower  to run them.  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 Risk Factors,  Gasco will be 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,
it may have difficulty  acquiring  additional  acreage and/or projects,  and may
have difficulty  arranging for the  transportation  of the oil or natural gas it
produces.

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


                                       4
<PAGE>

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
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,
more stringent regulations governing emissions of toxic air pollutants are being
developed  by the  EPA,  and may  increase  the  costs  of  compliance  for some
facilities.

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  in  negotiations  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.  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.

                                       5
<PAGE>

Number of Total Employees and Number of Full-Time Employees

As of March 15, 2005, Gasco had thirteen full-time employees.

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 will 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,  2004 and 2003,  we incurred a net loss of
$4,205,830  and  $2,526,525,  respectively.  As of December 31, 2004,  we had an
accumulated deficit of $29,497,591.  Our failure to achieve profitability in the
future could adversely affect the trading price of our common stock, our ability
to raise additional capital and our ability to continue as a going concern.

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

A sharp  decline in the price of natural  gas and oil prices  would  result in a
commensurate  reduction in our income from the production of oil and gas. In the
event prices fall substantially, we may not be able to realize a profit from our
production  and would  continue to operate at a loss. In recent  decades,  there
have been  periods  of both  worldwide  overproduction  and  underproduction  of
hydrocarbons  and  periods of both  increased  and relaxed  energy  conservation
efforts.  Such  conditions  have  resulted  in periods of excess  supply of, and
reduced  demand  for,  crude oil on a  worldwide  basis and for natural gas on a
domestic basis.  These periods have been followed by periods of short supply of,
and increased  demand for, crude oil and natural gas. The excess or short supply
of crude oil has resulted in dramatic price  fluctuations even during relatively
short periods of seasonal  market  demand.  Among the factors that can cause the
price volatility are:

          o    worldwide  or regional  demand for  energy,  which is affected by
               economic conditions;

          o    the domestic and foreign supply of natural gas and oil;

          o    weather conditions;

          o    domestic and foreign governmental regulations;

                                       6
<PAGE>


          o    political conditions in natural gas or oil producing regions;

          o    the ability of members of the Organization of Petroleum Exporting
               Countries to agree upon and  maintain  oil prices and  production
               levels;

          o    the price and availability of alternative fuels.

          o    acts of war, terrorism or vandalism; and

          o    market manipulation.

All of our production is currently  located in, and all of our future 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.

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 may  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.

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<PAGE>

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 proved reserve information as of December 31, 2004, 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
three years as of December 31, 2004,  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
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.

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.

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

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 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.

The development of oil and gas properties  involves  substantial  risks that may
result in a total loss of investment.

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.

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


                                       9
<PAGE>

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 adversely
affect our ability to continue as a going concern.

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 resources.  We
do not believe that our  competitive  position in the  petroleum and natural gas
industry will be 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.

Although  management  believes  the  operator  of any  property  in which we may
acquire interests will acquire and maintain  appropriate  insurance  coverage in
accordance  with  standard  industry   practice,   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 financial position.

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
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.

                                       10
<PAGE>

Prior to the drilling of a petroleum  and natural gas well,  however,  it is the
normal  practice in the  petroleum  and natural gas  industry  for the person or
company acting as the operator of the well to obtain a preliminary  title review
of the spacing unit within which the proposed  petroleum and natural gas well is
to be drilled to ensure there are no obvious  deficiencies in title to the well.
Frequently, as a result of such examinations, certain curative work must be done
to correct  deficiencies in the  marketability  of the title,  and such curative
work entails expense. The work might include obtaining affidavits of heirship or
causing an estate to be administered.

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.

We could become subject to certain Questar Pipeline Company Gas Requirements.

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 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
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   "Governmental
Regulations and Environmental Laws," above.


                                       11
<PAGE>


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.

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.

                                       12
<PAGE>


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 producing properties in
Utah and Wyoming.  If mechanical  problems,  depletion or other events reduced a
substantial  portion  of the  production,  our cash  flows  would  be  adversely
affected.  If the actual  reserves  associated with our fields are less than our
estimated  reserves,  our results of operations and financial condition could be
adversely affected.

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.

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

Our ability to conduct  operations in a timely and cost effective manner depends
on the  availability  of  supplies,  equipment  and  personnel.  The oil and gas
industry  is cyclical  and  experiences  periodic  shortages  of drilling  rigs,
supplies  and  experienced   personnel.   Shortages  can  delay  operations  and
materially increase operating and capital costs.

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:

          o    production is less than expected;

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

          o    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.

                                       13
<PAGE>

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 and Mr. Decker is an Executive  Vice President and
Chief  Operating  Officer of Gasco.  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. For example, our chairman,
Marc  A.  Bruner,  is the  largest  shareholder  and  Chairman  of the  Advisory
Committee of Galaxy Energy  Corporation.  As Advisory  Committee  Chairman,  Mr.
Bruner is  involved  in  identifying  and  acquiring  large  land  packages  for
exploitation and development by Galaxy.  In addition,  another of our directors,
C. Tony Lotito, is Executive Vice President,  Chief Financial Officer, Treasurer
and Director of Galaxy.

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 its  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,


                                       14
<PAGE>

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 Common 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:

          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.

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 following this
offering,  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  issuance of 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, 2004,  we had
70,517,209 shares of common stock issued and outstanding. As of such date, there
were  8,460,678  shares of common stock  issuable upon  exercise of  outstanding
options and conversion of our Series B Convertible  Preferred Stock  ("Preferred
Stock").  Additional  options  may be granted to  purchase  3,825,721  shares of
common stock under our stock  option plan and an  additional  179,150  shares of
common stock are issuable under our restricted  stock plan. As of December 31 of


                                       15
<PAGE>

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 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  86,767,209  shares (this number assumes no
exercise of the options or rights described above or conversion of the Preferred
Stock).

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.  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.

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.



                                       16
<PAGE>




              CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some  of  the  information  in  this  annual  report,  contains  forward-looking
statements  within the  meanings of Section 27A of the  Securities  Act of 1933.
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; and

          o    cash flow and anticipated liquidity.

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    our ability to generate sufficient cash flow to operate;

          o    the lack of liquidity of our common stock;

          o    the risks associated with exploration;

          o    natural gas and oil price volatility;

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

                                       17
<PAGE>

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

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

          o    climatic conditions;

          o    availability and cost of material and equipment;

          o    delays in anticipated start-up dates;

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

          o    our ability to find and retain skilled personnel;

          o    availability of capital;

          o    the strength and financial resources of our competitors;

          o    regulatory developments;

          o    environmental risks; and

          o    general economic conditions.

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 2 - DESCRIPTION OF PROPERTY

Petroleum and Natural Gas Properties

Gasco is a  natural  gas and  petroleum  exploitation  and  development  company
engaged in locating and developing  hydrocarbon prospects primarily in the Rocky
Mountain Region.  Gasco's strategy is to enhance  stockholder value by using new
technologies to generate high-potential exploitation prospects in this area. The
Company's  principal  business is the  acquisition  of  leasehold  interests  in


                                       18
<PAGE>

petroleum  and natural  gas  rights,  either  directly  or  indirectly,  and the
exploitation and development of properties subject to these leases.

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
2003 and 2004 due to factors such as inventory levels of gas storage,  different
temperatures  in parts of the country and changing  demand in the United States,
combined with the continued  instability  in the Middle East have  increased the
profitability  of the Company's  drilling  projects in this area.  The increased
drilling  activity  resulting  from the higher oil and gas prices have decreased
the availability of drilling rigs and experienced  personnel in this area and my
continue to do so.

         Riverbend Project

The Riverbend Project comprises  approximately  134,963 gross acres in the Uinta
Basin of  northeastern  Utah,  of which Gasco hold  interests  in  approximately
68,615 net acres as of December 31, 2004. The Company can also earn interests in
approximately   2,685  gross  acres  in  this  area  under  farm-out  and  other
agreements.  The Company's  engineering  and geologic focus is  concentrated  on
three  tight-sand  formations  in the Uinta basin:  the Wasatch,  Mesaverde  and
Blackhawk formations.

On January 20, 2004 the Company entered into agreements, which were subsequently
amended in July 2004, 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.

Gasco has agreed that the Service Parties,  which includes Schlumberger Oilfield
Services,  will  have the  exclusive  right to  provide  their  services  in the
development of the Riverbend acreage.  The agreement  initially provided for the
group  to  develop  a  bundle  of 10  wells  during  2004  using a  single  rig.
Thereafter, drilling was accelerated with the use of an additional rig.

General Terms of the Agreement:

          o    Contract Area consists of Gasco's leasehold  position in portions
               of Carbon,Duchesne  and Uintah  Counties,  Utah.

          o    Gasco is permitted to  independently  develop its acreage subject
               to certain limitations and provisions of the agreement.

          o    Schlumberger  will coordinate most  operational  activities under
               Gasco's direction as operator of record.

          o    Gasco has elected to fund  approximately 30% of each of the wells
               drilled under this agreement.  Gasco's interest in the production
               stream from a bundle, net of royalties, taxes and lease operating
               expenses,  is estimated to equal the proportion of the total well
               costs that it funds.

          o    The Service Parties have undertaken to provide  approximately 45%
               of the costs of each  project  bundle in return for a net profits
               interest in each bundle proportionate to their costs contributed.

                                       19
<PAGE>

          o    A third party investor, who also became a party to the Agreement,
               has undertaken to provide  approximately 25% of the costs of each
               project  bundle  in return  for a net  profits  interest  in each
               bundle proportionate to its costs contributed.

To secure its obligations under the agreement,  described above, the Company has
pledged its interests in each of the wells in each bundle.

In  connection  with the Service  Parties  agreements,  the Company  completed a
disposition  of net profits  interests of between  18.75% and 25% in the 8 wells
that have been drilled in the Riverbend  area in Utah during 2004 for total cash
consideration of $4,314,984, net of adjustments and commissions.  The purpose of
this  transaction was to allow the third party investor to become a party to our
service provider  arrangements.  The  consideration  paid to the Company in this
transaction  represented the share of such investor's development costs of the 8
wells  completed as of such date.  This investor has the opportunity to continue
to participate in the development program under the service provider arrangement
by funding 25% of future development costs.

During the fourth  quarter of 2004,  the Service  Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced late
in 2004.  The Company's  capital budget for this area during 2005 is anticipated
to be $38,000,000 for the drilling of 20 wells in this area.

During the year ended December 31, 2004, the Company spudded twelve wells in the
Riverbend  area,  which  are part of the  first  and  second  ten  well  bundles
contemplated  by the  agreements  with the  Service  Parties  and  investor,  as
described  above.  As of March 15, 2005, all of these wells are  producing.  The
Company  increased its drilling  activity in the  Riverbend  area during 2004 by
adding a second  drilling rig during  April 2004 and by adding a third  drilling
rig  during  December  2004.  The  Company  also  successfully  recompleted  one
additional well in this area during 2004.

During  December 2004, the Company  completed the  acquisition of  approximately
16,000 net acres in the  Riverbend  Area for a purchase  price of  approximately
$3,432,000.  Pursuant to an existing contract,  an unrelated third party had the
right to  purchase  25% of the  acquired  acreage at a price equal to 25% of the
purchase price.  This right was exercised by the third party during January 2005
which had the effect of reducing the Company's  interest in the acquired acreage
to 12,000  net acres and  reducing  the  purchase  price of the  acquisition  to
approximately $2,575,000.

During July 2004,  the Company  began  construction  on an  additional  ten-mile
pipeline  as  part of the  gathering  system  in the  Riverbend  area to  create
additional  pipeline capacity for the Company's  drilling projects in this area.
This   pipeline  was  completed  in  early   November  and   currently   gathers
approximately 97% of the Company's gas across the Riverbend Project.

On March 9, 2004, the Company  completed the  acquisition of additional  working
interests in six producing  wells,  13,062 net acres and gathering system assets
located in the Uinta Basin in Utah for approximately $3,175,000. During May 2004
an  unrelated  third party  exercised  its right to purchase 25% of the acquired
properties  at the  acquisition  price,  which had the  effect of  reducing  the
purchase price to approximately  $2,400,000 and reducing the Company's  interest


                                       20
<PAGE>

in the  acquisition to 75%. The effective date of the acquisition was January 1,
2004;  however,  the net revenue from the producing wells during the period from
January  1,  2004  through  March 9, 2004 was  recorded  as a  reduction  to the
purchase price.

During October 2003, the Company  completed a transaction in which it settled an
outstanding  amount owed of $1,606,982 to an  oilservice  provider  arising from
drilling and completion expenditures on five Gasco-operated wells, by paying the
provider  $400,000  in cash and  conveying  to the  provider  a  portion  of its
interests in two Riverbend  wells.  Subsequent to the  transaction,  the Company
retained a 30% working  interest in the two subject  wells and the  ownership in
remaining three wells is unchanged.

         Greater Green River Basin Project

As of December 31, 2004, the Company has a leasehold  interest in  approximately
128,055  gross  acres and 65,666 net acres in this area.  The  Company  holds an
operated  interest  in five  nonproducing  wells in this  area  and an  operated
interest in one producing  well in this area.  Additionally,  the Company owns a
non-operated  interest in two  producing  wells in this area.  During 2004,  the
Company  re-entered a previously drilled well in this area which began producing
from one zone which is currently shut-in.

The Company is currently  considering  additional  options for this area such as
the farm-out of some of our acreage and other similar type transactions.

During 2003, the Company  impaired certain of its unproved acreage in Wyoming by
reclassifying  $1,725,000  of costs  associated  with this acreage into the full
cost pool.  The  impairment  represented  the cost of  certain of the  Company's
acreage that the Company no longer  considered  prospective.  These costs became
subject to amortization during the fourth quarter of 2003.

         Southern California Project

The Company has a leasehold  interest in approximately  3,868 gross acres (2,641
net acres) in Kern and San Luis  Obispo  Counties of  Southern  California.  The
Company itself has no drilling or development plans for this acreage during 2005
and plans to continue  paying  leasehold  rentals and other  minimum  geological
expenses to preserve the Company's  acreage  positions on these  prospects.  The
Company is  actively  pursuing a partner to test this  acreage  for  hydrocarbon
potential.

Company Reserve Estimates

The  following  table  summarizes  the  Company's  estimated  reserve data as of
December  31,  2004,  as estimated by  Netherland,  Sewell &  Associates,  Inc.,
independent  petroleum engineers.  The present value of future net cash flows is
based on prices at December  31, 2004 of $5.56 per Mcf of gas and $42.25 per bbl
of oil. All of the  Company's  proved  reserves are located  within the state of
Utah.

                                       21
<PAGE>
<TABLE>
<CAPTION>

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

<S>            <C>              <C>          <C>              <C>             <C>
   Total       39,700,156       274,074      $ 17,592,000     $ 14,709,600    $ 32,301,600
              ===========      ========      =============    =============    ============
</TABLE>

Actual future prices and costs may be materially higher or lower than the prices
and costs as of the date of any  estimate.  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,  2004  present  value  of  future  net  cash  flows  of
approximately $2,083,000.

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 for the periods indicated.

                                          For the Years Ended December 31,
                                     ------------------------------------------
                                       2004             2003         2002
                                     ------------    ----------- --------------

     Natural gas production (Mcf)        505,967        257,035         66,444
     Average sales price per Mcf           $5.79          $4.69         $ 2.47
     Oil production (Bbl)                  5,080          1,988              -
     Average sales price per Bbl          $38.43         $28.52              -
     Expenses per Mcfe:
        Lease operating                    $1.19          $1.25         $ 1.80
        General and administrative         $7.81         $10.48        $ 76.46
        Depletion and impairment           $2.06          $2.06         $ 9.73


Development, Exploration and Acquisition Capital Expenditures

During the year ended  December  31,  2004,  the Company  spent  $23,462,908  in
development and exploration  activities,  including a property acquisition for a
net purchase price of approximately $2,400,000 and an acreage acquisition in the
Riverbend Area for approximately  $3,432,000.  Pursuant to an existing contract,
an unrelated  third party had the right to purchase 25% of the acquired  acreage
at a price equal to 25% of the purchase  price.  This right was exercised by the
third party during  January 2005 which had the effect of reducing the  Company's
purchase price of the acquisition to approximately  $2,575,000.  During the year
ended  December  31, 2003,  the Company  spent  $5,283,426  in  development  and
exploration  activities.  During the year ended  December 31, 2002,  the Company
spent  $32,962,855,  including the issuance of 9,500,000  shares of common stock
valued at  $18,525,000,  in the  acquisition  of  additional  leases  and in the
development and  exploitation of the properties  subject to these leases.  As of
December 31, 2004,  the Company  held working  interests in 266,886  gross acres
(136,922 net acres) located in Utah, Wyoming and California.  As of December 31,


                                       22
<PAGE>

2004,  the Company  held an  interest in 21 gross (7.1 net to Gasco's  interest)
producing  gas wells and 3 gross (1.6 net)  shut-in  gas wells  located on these
properties.

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,
                                                       -----------------------------------------------------------
                                                              2004                 2003               2002
                                                       -------------------  ------------------- ------------------
Property acquisition costs:
<S>                                                           <C>                    <C>              <C>
   Unproved                                                   $ 5,021,126            $ 667,557        $22,324,547
   Proved                                                        723,9012                  --                  --
Exploration costs (a)                                             216,165              396,967          3,319,124
Development costs                                             17,501,7162           4,218,9022          7,319,184
                                                              -----------           ----------         ----------
     Total excluding asset retirement obligation               23,462,908            5,283,426         32,962,855
                                                               ==========            =========         ==========
     Total including asset retirement obligation              $23,398,559          $ 5,398,678       $ 32,962,855
                                                              ===========           ==========        ===========
</TABLE>

(a)  Includes  seismic  data  acquisitions  of  $850,000  during  the year ended
     December 31, 2002.

Productive Gas Wells

The following  summarizes  the Company's  productive and shut-in gas wells as of
December 31, 2004.  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 Gas Wells
                                      Gross                       Net

          Producing gas wells           21                          7.1
          Shut-in gas wells              3                          1.3
                                        --                          ---
                                        24                          8.4
                                        ==                          ===

The Company  operates  all of the above  producing  wells and one of the shut-in
wells.  The remaining two shut-in wells are located in Sublette  County  Wyoming
and were drilled and are operated by Burlington Oil & Gas, L.P.

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,  2004.  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


                                       23
<PAGE>

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.
<TABLE>
<CAPTION>

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

<S>                                <C>                <C>                    <C>               <C>
     Utah                          134,963            68,615                 880               344
     Wyoming                       128,055            65,666                 320                68
     California                      3,868             2,641                   -                 -
                                   --------         ---------              ------             -----

         Total acres               266,886           136,922               1,200               412
                                  =========         =========              ======             =====
</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.

                  Expiring in 2005     Expiring in 2006     Expiring in 2007
                  Gross       Net       Gross      Net      Gross        Net

   Utah           5,268      1,670      10,609    5,144      8,861      3,582
   Wyoming       38,543     23,283       8,352    4,492      4,644      3,628
   California       777        433           -        -          -          -
                 ------     ------      ------  -------     ------      -----

   Total         44,588     25,386      18,961    9,636     13,505      7,210
                 ======     ======      ======    =====     ======      =====

During 2003, the Company  impaired certain of its unproved acreage in Wyoming by
reclassifying  $1,725,000  of costs  associated  with this acreage into the full
cost pool.  The  impairment  represented  the cost of  certain of the  Company's
acreage  expiring  in 2004 that the  Company no longer  considered  prospective.
These costs became  subject to  amortization  during the fourth quarter of 2003.
The impaired acreage (approximately 9,136 net acres) is excluded from the tables
above.

As of December  31, 2004,  approximately  79% of the acreage that Gasco holds is
located  on federal  lands and  approximately  19% 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 30 days,  while
obtaining  federal permits has taken several months or longer.  Accordingly,  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.

                                       24
<PAGE>

Drilling Activity

The following table sets forth the Company's  drilling activity during the years
ended  December 31, 2004,  2003 and 2002.  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.
<TABLE>
<CAPTION>

                                                 For the Year Ended December 31,
                            -----------------------------------------------------------------------------
                                2004                      2003                          2002
                            ----------------     ------------------------    ----------------------------
                            Gross     Net          Gross          Net          Gross             Net
    Exploratory Wells:
<S>                          <C>       <C>          <C>            <C>          <C>             <C>
      Productive               -        -             -             -             2              0.7
      Dry                      -        -             -             -             1              1.0
                              --       --            --            --            --              ---
        Total wells            -        -             -             -             3              1.7
                              ==       ==            ==            ==            ==              ===

    Development Wells:
      Productive              11       3.0            -             -             6              3.3
      Dry                      -         -            -             -             -                -
                               -      ----           --            --            --              ---
        Total wells           11       3.0            -             -             6              3.3
                              ==      ====           ==            ==            ==              ===
</TABLE>

During the first quarter of 2005, the Company drilled and cased three successful
wells and is currently in the process of drilling three additional wells, all of
which are located in the Uinta Basin of Utah.

Office Space

During 2004, the Company leased  approximately 3,255 square feet of office space
in Englewood,  Colorado for approximately $46,000 per year, under a lease, which
terminates  on August 30, 2005.  Subsequent to December 31, 2004, as a result of
the Company's  growth,  the Company  entered into a new lease for  approximately
6,234  square feet of office  space  which  commences  April 1, 2005.  The lease
terminates  on March 31, 2010 and the average  rent for this space over the life
of the lease is  approximately  $86,500 per year. The Company believes that this
new space will meet its needs for the next five years.

ITEM 3 - LEGAL PROCEEDINGS

None.

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

None.





                                       25
<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 March 15, 2005, 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.

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 OTC
bulletin  board for the  periods  indicated  through  December  5, 2004,  and as
reported on the American Stock  Exchange from December 6, 2004 through  December
31, 2004.

                                       High            Low
2003
         First Quarter                  $0.75          $0.46
         Second Quarter                  0.90           0.42
         Third Quarter                   0.90           0.51
         Fourth Quarter                  1.32           0.54

2004
         First Quarter                   2.45           1.15
         Second Quarter                  2.54           1.59
         Third Quarter                   3.45           1.78
         Fourth Quarter                  4.30           2.75

Equity Compensation Plans

The  table  below  provides   information   relating  to  the  Company's  equity
compensation plans as of December 31, 2004.



                                       26
<PAGE>



<TABLE>
<CAPTION>

                                                                                           Number of securities
                                                                                           remaining available
                                            Number of securities    Weighted-average       for future issuance
                                                to be issued        exercise price of       under compensation
                                              upon exercise of         outstanding           plans (excluding
                                            outstanding options,        options,           securities reflected
Plan Category                               warrants and rights    warrants and rights       in first column)
-------------                               -------------------    -------------------       ----------------
Equity compensation plans
   approved by security holders
<S>                                                     <C>                 <C>                        <C>
     Stock option plan                           3,226,000           $      1.48                3,825,721(a)
     Restricted stock plan                         820,850                  N/A (b)                     -
Equity compensation plans
   not approved by security holders              3,817,250           $      2.17                      (c)
                                                 ---------                                     -----------
Total                                            7,864,100           $      1.85(d)             3,825,721
                                                 =========                  ====                =========
</TABLE>


(a)      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 number of shares of common  stock  issuable  under the plan will be
         equal to 10% of the total number of shares of common stock  outstanding
         on that date.

(b)      The  restricted  shares vest 20% on the first  anniversary,  20% on the
         second  anniversary  and 60% on the third  anniversary  of the  awards,
         provided the holder remains employed by the Company.

(c)      The equity  compensation plan not approved by shareholders is comprised
         of  individual  common stock  option  agreements  issued to  directors,
         consultants  and  employees of the Company,  as summarized  below.  The
         common  stock  options  vest  between zero and two years of the date of
         issue and expire  within ten years of the vesting  date.  The  exercise
         prices of these  options range from $1.00 per share to $3.70 per share.
         Since these options are issued in individual compensation arrangements,
         there are no options available under any plan for future issuance.  The
         material terms of these options are as follows:
<TABLE>
<CAPTION>

    Options Issued to:        Number of Options  Exercise Price       Vesting Dates      Expiration Dates
<S>                               <C>             <C>     <C>          <C>    <C>           <C>    <C>
           Employees              3,394,750       $1.00 - $3.15        2001 - 2003          2006 - 2008
           Consultants              272,500       $3.00 - $3.70        2001 - 2003          2006 - 2008
           Directors                150,000       $3.00 - $3.15        2001 - 2003          2006 - 2008
                                    -------

    Total Issued                  3,817,250
                                  =========
</TABLE>

(d)  Weighted average exercise price of options to purchase a total of 7,043,250
     shares of common stock.




                                       27
<PAGE>



Securities Transactions

The Company's  securities  transactions  during the year ended December 31, 2004
that were not  registered  under the  Securities  Act of 1933 are  described  as
follows:

On February 11, 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.  Financing fees of $1,118,000 and $279,500  associated
with this  transaction  were paid to First Albany Capital and Pritchard  Capital
Partners, respectively.

On October 20, 2004, the Company closed the private  placement of $65 million 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,  between the
Company and Wells Fargo Bank, National Association,  as trustee. The amount sold
consisted of $45 million principal amount  originally  offered plus the exercise
by the initial  purchasers of their option to purchase an additional $20 million
principal amount. The Notes were sold only to qualified  institutional buyers in
reliance  on Rule  144A  under the  Securities  Act of 1933.  Financing  fees of
$2,383,875 and $541,125  associated with this transaction were paid to JP Morgan
and First Albany Capital, respectively.

Immediately  prior to and in connection  with the closing of the offering of the
Notes, the holders of the Company's 8.00% Convertible  Debentures  converted the
entire $2.5 million  principal  amount thereof into  4,166,665  shares of common
stock in accordance  with the terms of such  Debentures.  In connection with the
conversion,  the Company  paid the holders  $270,247,  representing  120% of the
future  interest  payments under the Debentures  through  November 15, 2005. 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.

During 2004,  certain  holders of the Company's  Series B Convertible  Preferred
Stock  ("Preferred  Stock")  converted  9,479  shares of  Preferred  Stock  into
5,958,226  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.

During 2004,  the Company  granted an additional  1,410,000  options to purchase
shares of common stock to employees,  directors and  consultants of the Company,
at exercise  prices  ranging from $1.61 to $2.15 per share.  The options vest 16
2/3% at the end of each  four-month  period after the  issuance  date and expire
within ten years from the grant date.

During the year ended  December  31,  2004,  the Company  paid  dividends to the
holders of its Preferred  Stock  consisting of 41,959 shares of common stock and
$61,960 in cash.

Unless  otherwise  noted,  each of the above sales of  securities by the Company
were exempt  from  registration  under the  Securities  Act of 1933  pursuant to
Section  4(2)  thereof,  inasmuch as each such sale was  conducted  as a private
placement to a limited number of sophisticated buyers.

                                       28
<PAGE>

The  aggregate  net  proceeds  from the  securities  offerings  during 2004 were
approximately  $81,870,000.  The  proceeds  were  used for the  development  and
exploitation  of the  Company's  Riverbend  Project  and for  general  corporate
purposes during 2004 and will be used for the same purposes during 2005.

ITEM 6 - SELECTED FINANCIAL DATA

The  following  table sets  forth  selected  financial  data,  derived  from the
consolidated  financial  statements,  regarding Gasco's  financial  position and
results of operations as the dates indicated.  All information for periods prior
to March 30, 2001  represents the historical  information of GPC because GPC was
considered the acquiring entity for accounting purposes.
<TABLE>
<CAPTION>

                                                                 As of and for the Year Ended December 31,
                                                  2004            2003             2002             2001            2000
                                                  ----            ----             ----             ----            ----
Summary of Operations
<S>                                               <C>            <C>                 <C>             <C>                <C>
      Oil and gas revenue                         $3,123,888     $1,263,443          $ 164,508       $ 36,850           $    -
      General & administrative expense             4,191,978      2,819,675          5,080,287      4,326,065          951,734
      Net loss                                   (4,205,830)    (2,526,525)        (5,649,682)    (4,129,459)        (843,261)
      Net loss per share                              (0.07)         (0.07)             (0.16)         (0.63)           (0.06)

                                                                 As of and for the Year Ended December 31,
                                                 2004               2003              2002             2001            2000
                                                 ----               ----              ----             ----            ----
Balance Sheet
      Working capital (deficit)                  $52,719,245        $1,192,246     $ (2,857,539)     $11,860,584     $ (420,370)
      Cash and cash equivalents                   25,717,081         3,081,109         2,089,062      12,296,585         881,041
      Oil and gas properties, net                 50,820,383        28,470,917        24,760,149       9,152,740       1,991,290
      Total assets                               117,368,168        33,059,179        27,505,501      21,658,525       3,007,259
      Long-term obligations                       65,108,566         2,483,084                 -
                                                                                                               -               -
      Stockholders' equity                        46,213,198        27,382,083        22,014,265      21,065,425       1,578,905
</TABLE>

ITEM 7 - MANAGEMENT'S DISCUSSION AND ANALYSIS

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  and  development  company
engaged in locating and developing hydrocarbon prospects, primarily in the Rocky
Mountain region. The Company's mission is to enhance  shareholder value by using
new technologies to generate and develop  high-potential  exploitation prospects
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.

                                       29
<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
2003 and 2004 due to factors such as inventory levels of gas storage,  different
temperatures  in parts of the country and changing  demand in the United States,
combined with the continued  instability  in the Middle East have  increased the
profitability of the Company's  drilling projects in this area. The wells in the
Riverbend Project tend to have multiple productive zones. The increased drilling
activity  resulting  from  the  higher  oil and gas  prices  has  decreased  the
availability  of drilling  rigs and  experienced  personnel in this area and may
continue to do so in the future.

The Company's  capital budget for fiscal year 2004 was approximately $13 million
for the drilling,  completion and pipeline  connection of wells in the Riverbend
Project. In connection with Gasco's  exploitation  efforts, we have entered into
agreements  with third party service  providers  and  investors  who  contribute
approximately 70% of the cost of developing  designated wells. During the twelve
months ended December 31, 2004, twelve wells were spudded in the Riverbend area,
nine of  which  were  producing  at year  end and  all of  which  are  currently
producing.  The Company increased its drilling  activities in the Riverbend area
in April 2004 by adding a second  drilling rig and added a third  drilling  rig,
which began drilling operations during December 2004.

During 2004, the Company  completed the  acquisition of additional  interests in
six producing  wells,  13,062 net acres and certain other assets  located in the
Uinta Basin in Utah for net  purchase  price of  approximately  $2,400,000.  The
Company also acquired  approximately  16,000 net acres in the Riverbend area for
approximately $3,432,000.

The following table presents the Company's reserve information as of December 31
of each of last three  years and  production  information  for each of the three
years ended  December 31, 2004. The Mcfe  calculations  assume a conversion of 6
Mcf's for each Bbl of oil.

                                            For the Years Ended December 31,
                                       -----------------------------------------
                                         2004             2003           2002
                                       ------------ ------------- --------------

  Natural gas production (Mcf)             505,967       257,035         66,444
  Average sales price per Mcf                $5.79         $4.69         $ 2.47
  Year-end proved gas reserves (Mcf)    39,700,156    13,601,003     20,622,266

  Oil production (Bbl)                       5,080         1,988              -
  Average sales price per Bbl               $38.43        $28.52              -
  Year-end proved oil reserves (Bbl)       274,074       100,987        141,652

  Production (Mcfe)                        536,447       268,963         66,444
  Year-end proved reserves (Mcfe)       41,344,600    14,206,925     21,472,178

During 2004,  the Company's oil and gas  production  increased by  approximately
171% primarily due to the drilling  projects and working  interest  acquisitions
discussed  above.  During  2004,  on a combined  basis,  the oil and gas reserve
quantities  have  increased  by  approximately  191%  primarily  due to  reserve


                                       30
<PAGE>

additions  of  196%  and  purchases  of  reserves  of 56%  partially  offset  by
production of 4%,  property sales of 21% and revisions of previous  estimates of
36%. The previous  estimate  revisions  relate to the write down of the reserves
related to two wells and their offset locations resulting from scale deposits in
the wellbores.

The Company's oil and gas production increased by approximately 300% during 2003
as compared with 2002 primarily due to the Company's completions,  recompletions
and the  installation  of a compressor  during 2003.  During 2003, on a combined
basis,  the  oil  and gas  reserve  quantities  declined  by  approximately  34%
primarily due to normal decline curves of approximately  30%,  property sales of
7%, annual production of 1% and revisions of previous estimates of 18% partially
offset by extensions and discoveries of 22%.

The Company's  capital  budget for 2005 is anticipated to be $38 million for the
drilling,  completion and pipeline connection of wells in the Riverbend Project.
The  Company  plans  to drill  and  complete  20 gross or 13 to 14 net  wells in
Gasco's  Riverbend Project in the Uinta Basin of Utah.  Pending  notification by
industry  partners of their  decision to  participate  in Gasco's  proposed 2005
drilling  program,  the Company  would  expect to spend up to an  additional  $5
million to drill 10 gross and two net wells. The initial capital budget does not
include  surface   infrastructure   costs   associated  with  gathering   system
improvements.  The anticipated  2005 gathering system budget is $2 million to $3
million,  or  approximately  $100,000  per well  for  compression  and  pipeline
hook-up.  If we choose to proceed with the drilling of the 10 additional  wells,
the Company  would need to add a fourth  drilling rig during the last six months
of the  year.  The  overall  increase  in  drilling  activity  has  made it more
difficult  for  the  Company  to  obtain  additional  drilling  rigs  as well as
experienced personnel,  which may reduce the number of wells the Company is able
to drill during 2005. The Company  anticipates an overall increase in its salary
expense because it will have to hire additional employees to manage the workload
associated  with its  operational  plan for  2005.  Management  believes  it has
sufficient  capital  for its 2005  operational  budget,  but will  need to raise
additional  capital for its capital  budget in 2006.  The Company will  consider
several options for raising  additional  funds such as entering into a revolving
line of credit, 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.

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, 2004, 2003 and 2002.
<TABLE>
<CAPTION>

                                                 For the Year Ended December 31,
                                          -----------------------------------------------------
                                              2004                 2003               2002
                                              ----                 ----               ----

<S>                                         <C>               <C>                <C>
Net cash used in operations                 $ (905,369)       $ (2,191,914)      $ (1,390,306)
Net cash used in investing activities      (48,336,958)         (5,286,690)       (14,541,197)
Net cash provided by financing activities    71,878,299           8,470,651          5,723,980
Net cash flow (deficit)                      22,635,972             992,047       (10,207,523)
</TABLE>

                                       31
<PAGE>

Cash used in  operations  during 2002 was  primarily  comprised of the Company's
general and  administrative  expenses  partially  offset by gas revenue from the
wells  drilled  throughout  the year.  The  increase in cash used in  operations
during 2003 was primarily due to the increase in revenue  resulting  from a 300%
increase in production due to the Company's  drilling  activity  during 2002 and
2003,  partially  offset by a decrease  in the changes in  operating  assets and
liabilities  primarily due to the timing of the Company's  operational activity.
Oil and  gas  production  increased  another  100%  during  2004 as the  Company
continued  their drilling  activity and completed the  acquisition of additional
working  interests  in six wells  resulting  in a  decrease  in the cash used in
operations.  General and  administrative  expenses decreased as well during 2003
due primarily to the Company's cost cutting measures,  but increased during 2004
due to the Company's  increase in drilling  activity as well as its fund raising
projects during 2004. See further discussion under Results of Operations.

The Company's  investing  activities  during 2003, and 2002 related primarily to
the Company's  development and exploration  activities.  During 2002 the Company
acquired  acreage  for  approximately  $22,000,000  in cash  and  stock  and the
remaining  $11,000,000  was used to fund the Company's  drilling  projects.  The
Company's unproved acquisitions during 2003 decreased to approximately  $700,000
and related  primarily to delay rentals and other leasehold costs. The remaining
$ 4,600,000 in property  costs was spent on the Company's  drilling  projects in
the  Riverbend  Project.  During 2004,  the Company  completed  acquisitions  of
acreage and additional  working  interests in producing wells for  approximately
$5,800,000 and the remaining  $19,936,066 in property costs was primarily  spent
on the Company's drilling projects in the Riverbend Project.  Additionally,  the
Company invested $27,000,000 in short-term investments during 2004.

Historically, the Company has relied on the sale of equity capital and farm-outs
and other similar types of transactions to fund working capital, the acquisition
of its  prospects  and its drilling and  development  activities.  The financing
activities in each of the years  presented is comprised of the net proceeds from
the sale of equity in the Company, as further described below.

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  2003  the  Company  closed  the  sale of  $2,500,000  of 8%  Convertible
Debentures  ("Debentures")  in a  private  placement  offering,  sold  through a
private  placement,  11,052  shares  of  Series B  Convertible  Preferred  Stock
("Preferred  Stock") to a group of accredited  investors,  including  members of
Gasco's management for $440 per share resulting in net proceeds of approximately
$4,797,000  and  completed  the sale  through a private  placement  of 4,788,436
shares of its common  stock to a group of  accredited  previous  investors  at a
selling  price of $0.58 per  common  share  for net  proceeds  of  approximately
$2,765,000.

On August 14, 2002, the Company issued  6,500,000 shares of common stock for net
proceeds of approximately $6,000,000 in a private placement.

                                       32
<PAGE>

Capital Budget

In January 16, 2004 the Company entered into agreements, which were subsequently
amended  during July 2004,  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.  Gasco has agreed that the Service  Parties will have the exclusive
right to provide their services in the development of the Riverbend acreage. The
agreement  provides  for the group to initially  proceed with the first  10-well
bundle,  which  approximates  one year of drilling  with a single rig,  with the
drilling of  additional  10-well  bundles  being  subject to the approval of the
group.  The Company is currently  using three  drilling  rigs and has  commenced
drilling of the second 10-well  bundle under this project.  If the group agrees,
drilling may be accelerated  using additional rigs.  Gasco's 2004 capital budget
was  approximately  $13  million  for  the  drilling,  completion  and  pipeline
connection  of wells  in this  area.  Two of the  drilling  rigs  are  currently
drilling the second 10-well bundle. Under this agreement, the Company has agreed
to fund approximately 30% of the development costs of each of the wells drilled,
with the service providers providing drilling and completion services equivalent
to 45%  of the  total  development  costs  and  an  additional  capital  partner
providing  25% of the total  development  costs.  The service  providers are not
required to expend more than a total of $13.5 million for development of a given
bundle.  Furthermore,  the service  providers  are not  obligated to provide any
services  unless  each is  satisfied  that we  will  be  able to meet  our  cash
expenditure  requirements.  The Company's interest in the production stream from
each  10-well  bundle  of wells,  net of  royalties,  taxes and lease  operating
expenses,  is estimated to equal the  proportion of the total well costs that we
fund.

To secure its obligations  under the agreement  described above, the Company has
pledged its interests in each of the wells in each bundle.

During the fourth  quarter of 2004,  the Service  Parties agreed to proceed with
the second bundle of ten wells. The drilling of the second bundle commenced upon
completion  of the  first  bundle.  The  Company  and the  Service  Parties  are
currently  negotiating the third 10-well bundle which is anticipated to commence
during the last half of 2005.

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  for gross  proceeds  of  $21,500,001  and  closed  the
private  placement of  $65,000,000  in aggregate  principal  amount of its 5.50%
Convertible  Senior Notes due 2011. The proceeds from these sales are being used
for the development and exploitation of Gasco's  Riverbend  Project in the Uinta
Basin in Uintah County, Utah and for general corporate purposes.

The  Company's  use of the  funds  from  this  transaction  and its cash on hand
included the following projects:

     -    The March 9, 2004 acquisition of additional interests in six producing
          wells,  13,062 net acres and certain other assets located in the Uinta
          Basin in Utah.

     -    The Company's  planned  expenditures for the drilling,  completion and
          pipeline connection of nine wells in this area.

     -    The completion of a gathering system within the Riverbend Area.

                                       33
<PAGE>

The Company's  capital  budget for 2005 is anticipated to be $38 million for the
drilling,  completion and pipeline  connection of 20 gross or 13 to 14 net wells
in Gasco's Riverbend Project in the Uinta Basin of Utah. Pending notification by
industry  partners of their  decision to  participate  in Gasco's  proposed 2005
drilling  program,  the Company  would  expect to spend up to an  additional  $5
million to drill 10 gross and two net wells. The initial capital budget does not
include  surface   infrastructure   costs   associated  with  gathering   system
improvements.  The anticipated  2005 gathering system budget is $2 million to $3
million,  or  approximately  $100,000  per well  for  compression  and  pipeline
hook-up.  The Company  plans to add a fourth  drilling  rig during the first six
months of the year.

Management  believes it has sufficient capital for its 2005 operational  budget,
but will need to raise  additional  capital for its capital  budget in 2006. The
Company  will  consider  several  options for raising  additional  funds such as
entering into a revolving line of credit, 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
and consulting agreement for the periods specified as of December 31, 2004.
<TABLE>
<CAPTION>

                                                                        Payments due by Period
Contractual Obligations                        Total            1 year        2-3 years        4-5 years      After 5 years
-----------------------                        -----            ------        ---------        ---------      -------------

Convertible Notes Principal
<S>                                            <C>              <C>             <C>             <C>              <C>
    and Interest                               $89,180,903      $3,575,000      $7,150,000      $ 7,150,000      $ 71,305,903
Operating Lease - office space                     462,424          85,796         164,172          187,862            24,594
Employment Contracts                               509,167         470,000          39,167                -                 -
Consulting Agreement                               130,000         120,000          10,000                -                 -
                                               -----------      ----------      ----------     ------------       --------- -
Total Contractual Cash
  Obligations                                 $ 90,282,494     $ 4,250,796      $7,363,339      $ 7,337,862       $71,330,497
                                              ============     ===========      ==========      ===========       ===========
</TABLE>

The Company  current  office  lease  expires on August 30, 2005.  Subsequent  to
December 31, 2004, the Company entered into a new lease which commences April 1,
2005 and  terminates  on  March  31,  2010.  The  table  above  includes  future
obligations that will exist as a result of the new lease.

The Company has not included asset retirement obligations as discussed in Note 2
of the accompanying  financial statements,  as the Company cannot determine with
accuracy the timing of such payments.




                                       34
<PAGE>



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.

         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 plus the cost, or estimated fair value
if lower, of unproved properties.  Should capitalized costs exceed this ceiling,
an impairment would be recognized.

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 two years,  their  production  history is 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 reservoir were used
in  conjunction  with the decline  analysis  method to determine  the  Company's
estimates  of  proved  reserves   including   developed   producing,   developed


                                       35
<PAGE>

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.  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. During 2003, the Company's management reviewed the unproved property
located  within  the  state of  Wyoming  and  determined  that it  would  not be
developing  some of the acres that were not considered to be  prospective.  As a
result,  the  Company  estimated  the value of these  acres for the  purpose  of
recording the related impairment.  The impairment was estimated by calculating a
per acre value from the total unproved  costs  incurred for the Wyoming  acreage
divided by the total net acres owned by the Company.  This per acre estimate was
applied to the acres that the Company did not plan to develop to  calculate  the
impairment. A change in the estimated value of the acreage could have a material
impact on the total of the impairment recorded by the Company.

         Revenue Recognition

The Company's  revenue is derived from the sale of oil and gas  production  from
its producing wells. This revenue is recognized as income when the production is
produced and sold.  The Company  typically  receives its payment for  production
sold one to three months  subsequent to the month the  production  is sold.  For
this reason,  the Company must estimate the revenue that has been earned but not
yet received by the Company as of the  reporting  date.  The Company uses actual
production  reports  to  estimate  the  quantities  sold and the  Questar  Rocky
Mountain spot price less  marketing and  transportation  adjustments to estimate
the price of the  production.  Variances  between our  estimates  and the actual
amounts received are recorded in the month the payment is received.

         Stock Based Compensation

The Company accounts for its stock-based  compensation using the intrinsic value
recognition and measurement principles detailed in Accounting Principles Board's
Opinion No. 25 ("APB No.  25").  No  stock-based  compensation  expense has been
reflected in the Company's  financial  statements for the options granted to its


                                       36
<PAGE>

employees  as these  options  had  exercise  prices  equal to or higher than the
market value of the  underlying  common stock on the date of grant.  The Company
uses  the  Black-Scholes  option  valuation  model  to  calculate  the  required
disclosures  under SFAS 123. 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  difference  estimate  for any one of  these  components  could  have a
material impact on the amount of calculated compensation expense.

Results of Operations

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 for the periods indicated.

                                       For the Year Ended December 31,
                                 -----------------------------------------------
                                         2004             2003            2002
                                         ----             ----            ----

    Natural gas production (Mcf)        505,967        257,035           66,444
    Average sales price per Mcf          $ 5.79         $ 4.69            $2.47
    Oil production (Bbl)                  5,080          1,988                -
    Average sales price per Bbl          $38.43         $28.52                -

2004 Compared to 2003

Oil and gas revenue  increased  $1,860,445 during 2004 compared with 2003 due to
an increase in gas  production of 248,932 Mcf and an increase in oil  production
of 3,092 bbls during 2004  combined  with an increase in the average gas and oil
prices  of  $1.10  per Mcf and  $9.91  per bbl  during  2004.  The  increase  in
production  is primarily due to the  Company's  2004  drilling and  recompletion
activity as well as the acquisition of additional working interests in six wells
during March 2004.

The  gathering  income of  $143,326  during the year  ended  December  31,  2004
represents  the  income  earned  from  the  Riverbend  area  pipeline  that  was
constructed by the Company during 2004.

Interest  income  increased  $313,014 from 2003 to 2004  primarily due to higher
average cash and cash equivalent and short-term  investment balances during 2004
relating primarily to proceeds from the Company's  $65,000,000  Convertible Note
issuance  during October 2004 and its  $21,500,000  common stock offering during
February 2004.

General  and  administrative  expense  increased  by  $1,372,303  during 2004 as
compared  with  2003,  primarily  due to  the  Company's  increased  operational
activity.  The increase in these expenses is comprised of approximately $305,000
in salary  expense  due to the  hiring of  additional  full-time  employees  and
employee and officer bonuses, approximately $280,000 in stock based compensation
primarily  related to the Company's  restricted  stock  issuance,  approximately
$215,000  related to increased  shareholder  communication  due to the Company's
expanded operational activity during 2004,  approximately $245,000 in consulting
expenses due to the increased  operational activity,  approximately  $185,000 in


                                       37
<PAGE>

audit and legal fees related to the property and financing  transactions  during
the year and approximately $140,000 of increased administrative expenses related
to the operations of the Company's corporate office resulting from the increased
operational activity and the increase number of consultants and employees during
2004. The remaining  increase in general and  administrative  expenses is due to
the  fluctuation  in numerous  other  expenses,  none of which are  individually
significant.

Lease operating  expense  increased by $300,989,  during 2004,  primarily due to
increased  operating  costs  and  production  taxes  relating  to the  increased
production discussed above.

Gathering  operation  expense  during  2004  relates  to the  operations  of the
Company's  pipeline in the Riverbend  area that was  constructed  by the Company
during 2004.

Depletion,  depreciation  and  amortization  expense during 2004 is comprised of
$1,025,100  of depletion  expense  related to the  Company's  proved oil and gas
properties,  $60,812 of depreciation expense related to the Company's equipment,
furniture,  fixtures and other assets and $16,663 of accretion  expense  related
the Company's asset retirement obligation. The corresponding expense during 2003
consists of $480,000 of depletion expense,  $61,128 of depreciation  expense and
$11,795 of accretion  expense.  The increase in depletion expense during 2004 as
compared with 2003 is due primarily to the increase in production resulting from
the Company's increased drilling and completion activity as well as the property
acquisition discussed above.

Interest  expense  during  2004  consists  of  interest  expense  related to the
Company's  outstanding  Convertible  Notes which were issued on October 20, 2004
and interest expense related to the Company's  outstanding  Debentures that were
converted  into common stock in October 2004.  The interest  expense during 2003
consists of the interest incurred on an outstanding note payable that was repaid
during  February  2004  as  well  as  interest  on  the  Company's   outstanding
Debentures.

2003 Compared to 2002

Oil and gas revenue  increased  $1,098,935 during 2003 compared with 2002 due to
an increase in gas production  from 66,444 Mcf during 2002 to 257,035 Mcf during
2003  combined  with an increase in the average gas price from $2.47 during 2002
to $4.69 per Mcf during 2003.  During 2003, the Company also produced 1,988 bbls
of oil at an average  price of $28.52 per bbl.  The increase in  production  was
primarily due to the Company's completion and recompletion  activity during 2003
as well as the compressor  installation  discussed  above which occurred  during
February 2003.

Interest  income  decreased  by 84%  from  2002 to 2003  primarily  due to lower
average cash and cash equivalent balances during 2003.

General and  administrative  expense  decreased  from  $5,080,287  to $2,819,675
during 2003 as compared with 2002,  primarily  due to the  Company's  efforts to
decrease its overhead  expenses.  The $2,260,612  decrease in these expenses was


                                       38
<PAGE>

comprised  of   approximately   $775,000  in  salary   reductions   due  to  the
implementation,  during  January  2003,  of a 36% annual  reduction  in the cash
component of the Company's senior management compensation,  a $300,000 reduction
in compensation expense due to the one time payment of a bonus to an employee of
the Company,  a $565,000 reduction in legal fees and $246,000 in accounting fees
as a  result  of fewer  transaction  related  fees  during  2003 and a  $400,000
decrease  in  consulting  fees that were  incurred in  connection  with the 2002
property transactions discussed above.

Lease  operating  expense  increased  $217,469  during 2003 as compared with the
2002.  The  increase  was due a greater  number of  producing  wells during 2003
resulting from the Company's drilling activity during 2002 and 2003.

Depletion,  depreciation and  amortization  expense during 2003 was comprised of
$480,000  of  depletion  expense  related  to the  Company's  proved oil and gas
properties,  $61,128 of depreciation expense related to the Company's furniture,
fixtures and other assets and $11,795 of accretion expense related the Company's
asset retirement obligation.  The corresponding expense during 2002 consisted of
$105,321 of depletion expense and $43,788 of depreciation  expense. The increase
in depletion  expense during 2003 as compared with 2002 was due primarily to the
increase in production discussed above.

Impairment  expense during 2002 represented costs associated with a well drilled
in the  Southwest  Jonah  field  located in the  Greater  Green  River  Basin in
Sublette  County,  Wyoming.  The well was plugged and abandoned  during March of
2002. The Company recognized impairment expense of $541,125 associated with this
well during 2002 because the Company  believed that the costs  incurred for this
well exceeded the present  value,  discounted at 10%, of the future net revenues
from its proved oil and gas reserves.

Interest  expense during 2003  represented  the interest  expense related to the
Company's outstanding Debentures.

The cumulative effect of change in accounting  principle during 2003 represented
the Company's  recognition of an asset retirement  obligation in connection with
the adoption of SFAS 143 on January 1, 2003.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R),  "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for interim or annual periods beginning
after June 15, 2005,  supersedes APB Opinion No. 25, Accounting for Stock Issued
to Employees, and amends SFAS No. 95, Statement of Cash Flows.

SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock  options,  to be recognized in the income  statement  based on
their fair values.  Pro-forma  disclosure is no longer an  alternative.  The new
standard will be effective for the Company,  beginning  August 1, 2005. SFAS No.
123R  permits  companies  to adopt its  requirements  using  either a  "modified
prospective" method, or a "modified  retrospective"  method. Under the "modified


                                       39
<PAGE>

prospective" method, compensation cost is recognized in the financial statements
beginning with the effective  date,  based on the  requirements of SFAS No. 123R
for  all  share-based  payments  granted  after  that  date,  and  based  on the
requirements  of SFAS  No.  123 for all  unvested  awards  granted  prior to the
effective date of SFAS No. 123R. Under the "modified  retrospective" method, the
requirements are the same as under the "modified  prospective"  method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods  presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123.  The Company has not yet  determined  which of the methods it
will use upon adoption.  The Company has not yet completed their  evaluation but
expects  the  adoption  SFAS  No.  123(R)  to have an  effect  on the  financial
statements  similar  to the  pro  forma  effects  reported  in the  Stock  Based
Compensation disclosure in Item 8. Note 2.
The FASB issued SFAS 153,  Exchanges of  Nonmonetary  Assets,  which changes the
guidance  in APB Opinion  29,  Accounting  for  Nonmonetary  Transactions.  This
Statement amends Opinion 29 to eliminate the exception for nonmonetary exchanges
of  similar  productive  assets and  replaces  it with a general  exception  for
exchanges  of  nonmonetary  assets  that do not  have  commercial  substance.  A
nonmonetary  exchange has  commercial  substance if the future cash flows of the
entity are expected to change  significantly  as a result of the exchange.  SFAS
153 is effective  during fiscal years beginning after June 15, 2005. The Company
does not  believe the  adoption  of SFAS 153 will have a material  impact on the
Company's financial statements.
In March 2004, the FASB issued consensus on EITF 03-6, "Participating Securities
and the  Two-Class  Method Under FASB  Statement  No. 128,  Earnings Per Share,"
related to  calculating  earnings per share with respect to using the  two-class
method for  participating  securities.  This  pronouncement is effective for all
periods after March 31, 2004, and requires prior periods to be restated. As, the
Company has  incurred  net losses in the current and prior  periods,  and as the
Company's preferred stock does not have a contractual obligation to share in the
losses of the Company,  the adoption of EITF 03-6 had no impact on the Company's
financial condition,  or its results of operations.  The Securities and Exchange
Commission  issued Staff  Accounting  Bulletin  (SAB) No. 106 in September  2004
regarding the  application  of SFAS No. 143,  "Accounting  for Asset  Retirement
Obligations,"  for oil and gas  producing  entities  that  follow  the full cost
accounting  method. SAB No. 106, states that after adoption of SFAS No. 143, the
future cash outflows associated with settling asset retirement  obligations that
have been accrued on the balance sheet should be excluded from the present value
of  estimated  future  net  cash  flows  used  for the full  cost  ceiling  test
calculation.  The Company has  calculated  its ceiling test  computation in this
manner  since the  adoption of SFAS No. 143 and,  therefore,  SAB No. 106 had no
effect on the Company's financial statements, effective in the fourth quarter of
2004.




                                       40
<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  that are subject
to variable rates of interest.




                                       41
<PAGE>



ITEM 8 - FINANCIAL STATEMENTS

                          INDEX TO FINANCIAL STATEMENTS

Reports of Independent Registered Public Accounting Firms                  43-44

Consolidated Balance Sheets at December 31, 2004 and 2003                  45-46

Consolidated Statements of Operations for the Years Ended
    December 31, 2004, 2003 and 2002                                          47

Consolidated Statements of Stockholders' Equity for the Years
    Ended December 31, 2004, 2003 and 2002                                    48

Consolidated Statements of Cash Flows for the Years Ended
    December 31, 2004, 2003 and 2002                                          49

Notes to Consolidated Financial Statements                                 50-74




                                       42
<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  sheet of Gasco  Energy,  Inc.  and
subsidiaries   (the  "Company")  as  of  December  31,  2004,  and  the  related
consolidated  statements of operations,  stockholders' equity and cash flows for
the  year  ended  December  31,  2004.   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 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 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  audit  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, 2004, and the results of their  operations and their cash flows the
year ended  December  31,  2004,  in  conformity  with U.S.  generally  accepted
accounting principles.


/s/ Hein & Associates LLP
Denver, Colorado
March 15, 2005





                                       43
<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  sheet of Gasco  Energy,  Inc.  (the
"Company")  and its  subsidiaries  as of  December  31,  2003,  and the  related
consolidated statements of operations,  stockholders' equity, and cash flows for
each of the two years in the period ended  December 31,  2003.  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.  The Company is not  required to
have,  nor were we engaged to perform,  an audit of its  internal  control  over
financial  reporting.  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  provide a  reasonable  basis for our
opinion.

In our opinion,  such consolidated  financial  statements present fairly, in all
material  respects,  the  financial  position of the Company as of December  31,
2003,  and the results of their  operations and their cash flows for each of the
two years in the period ended December 31, 2003, in conformity  with  accounting
principles generally accepted in the United States of America.

As discussed in Note 2 to the  consolidated  financial  statements,  in 2003 the
Company adopted Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations."



/s/ DELOITTE & TOUCHE LLP
Denver, Colorado
March 25, 2004










                                       44
<PAGE>

<TABLE>
<CAPTION>

                               GASCO ENERGY, INC.
                           CONSOLIDATED BALANCE SHEETS



                                                                                December 31,
                                                                    ---------------------------------------
                                                                         2004                  2003
ASSETS

CURRENT ASSETS
<S>                                                                      <C>                   <C>
  Cash and cash equivalents                                              $25,717,081           $ 3,081,109
  Restricted investment                                                    3,535,055               250,000
  Short-term investments                                                  27,000,000                     -
  Accounts receivable                                                      1,045,044               499,363
  Inventory                                                                1,009,914                     -
  Prepaid expenses                                                           458,555               555,786
                                                                         -----------             ---------
          Total                                                          58,765,649              4,386,258
                                                                         -----------             ---------

PROPERTY, PLANT AND EQUIPMENT, at cost
  Oil and gas properties (full cost method)
    Proved mineral interests                                              29,811,483            16,386,252
    Unproved mineral interests                                            18,449,330            13,212,039
    Gathering assets                                                       2,469,580                     -
    Equipment                                                                 89,900                     -
  Furniture, fixtures and other                                              158,590               166,051
                                                                          ----------            ----------
           Total                                                          50,978,883            29,764,342
                                                                          ----------            ----------
  Less accumulated depreciation, depletion and amortization              (2,247,032)           (1,232,634)
                                                                         -----------           -----------
           Total                                                         48,731,851             28,531,708
                                                                         -----------            ----------

NON-CURRENT ASSETS
  Restricted investment                                                    6,778,040                     -
  Deferred financing costs                                                 3,092,628               141,213
                                                                           ---------               -------
                                                                           9,870,668               141,213
                                                                       -------------           -----------

TOTAL ASSETS                                                           $ 117,368,168          $ 33,059,179
                                                                       =============          ============

</TABLE>












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





                                       45
<PAGE>

<TABLE>
<CAPTION>

                               GASCO ENERGY, INC.
                     CONSOLIDATED BALANCE SHEETS (continued)


                                                                                               December 31,
                                                                                   ---------------------------------------
                                                                                      2004                    2003

LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES
<S>                                                                                    <C>                    <C>
  Accounts payable                                                                     $ 1,447,149            $ 2,016,979
  Revenue payable                                                                          334,765                243,513
  Advances from joint interest owners                                                      891,999                      -
  Accrued interest                                                                         695,139                      -
  Accrued expenses                                                                       2,677,352                933,520
                                                                                        ----------              ---------
           Total                                                                        6,046,404               3,194,012
                                                                                        ----------              ---------

NONCURRENT LIABILITES
   5.5% Convertible Senior Notes                                                        65,000,000                      -
   8% Convertible Debentures, net of unamortized discount of $159,722                            -              2,340,278
   Asset retirement obligation                                                             108,566                142,806
                                                                                           -------              ---------
       Total                                                                            65,108,566              2,483,084
                                                                                        ----------              ---------

COMMITMENTS AND CONTINGENCIES (NOTES 5, 13, 16)

STOCKHOLDERS' EQUITY
  Series B  Convertible  Preferred  stock  -  $.001  par  value;  20,000  shares
     authorized;   2,255  shares  issued  and  outstanding  with  a  liquidation
     preference of $992,200 in 2004 and 11,734 shares issued and
    outstanding with a liquidation preference of $5,162,960 in 2003                              2                     12
  Common stock - $.0001 par value; 100,000,000 shares authorized;
     70,590,909 shares issued and 70,517,209 outstanding in 2004;
     45,675,936 shares issued and 45,602,236 shares outstanding in 2003                      7,059                  4,568
  Additional paid in capital                                                            76,346,463             52,979,325
  Deferred compensation                                                                  (512,440)              (179,766)
  Accumulated deficit                                                                 (29,497,591)           (25,291,761)
  Less cost of treasury stock of 73,700 common shares                                    (130,295)              (130,295)
                                                                                      ------------           ------------
           Total                                                                       46,213,198              27,382,083
                                                                                      ------------           ------------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY                                          $ 117,368,168            $ 33,059,179
                                                                                    =============-           ============

</TABLE>








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






                                       46
<PAGE>


<TABLE>
<CAPTION>


                               GASCO ENERGY, INC.
                      CONSOLIDATED STATEMENTS OF OPERATIONS



                                                                               For the Year Ended December 31,
                                                                        -------------------------------------------------
                                                                                 2004             2003             2002

REVENUES
<S>                                                                      <C>               <C>                 <C>
  Gas                                                                    $  2,928,689      $  1,206,741        $ 164,508
  Oil                                                                         195,199            56,702
                                                                                                                       -
  Gathering                                                                   143,326                 -                -
  Interest income                                                             325,001            11,987           76,140
                                                                            ---------         ---------         --------
          Total                                                             3,592,215         1,275,430          240,648
                                                                            ---------         ---------         --------

OPERATING EXPENSES
  General and administrative                                                4,191,978         2,819,675        5,080,287
  Lease operating                                                             638,267           337,278          119,809
  Gathering operations                                                        267,450                 -                -
  Depletion, depreciation, amortization and asset retirement
    liability accretion                                                     1,102,575           552,923          149,109
  Impairment                                                                        -                 -          541,125
  Interest expense                                                          1,597,775            82,392
                                                                            ---------        ----------        ---------
           Total                                                            7,798,045         3,792,268        5,890,330
                                                                            ---------        ----------        ---------

LOSS BEFORE CUMULATIVE EFFECT OF
  CHANGE IN ACCOUNTING PRINCIPLE                                          (4,205,830)       (2,516,838)      (5,649,682)

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
  PRINCIPLE                                                                                     (9,687)                -
                                                                          ----------         ----------       ----------

NET LOSS                                                                  (4,205,830)       (2,526,525)      (5,649,682)

Preferred stock dividends                                                   (140,853)         (304,172)                -
                                                                          -----------       -----------     ------------

NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS                            $ (4,346,683)     $ (2,830,697)    $(5,649,682)
                                                                        =============     =============    ============

PER COMMON SHARE DATA - BASIC AND DILUTED:
Loss before cumulative effect of change in accounting principle             $  (0.07)         $  (0.07)        $  (0.16)
Cumulative effect of change in accounting principle                                -                 -                 -
                                                                            -----------        --------            -----

NET LOSS PER COMMON SHARE - BASIC AND DILUTED                               $  (0.07)         $  (0.07)        $  (0.16)
                                                                            =========         =========        =========

WEIGHTED AVERAGE COMMON SHARES
  OUTSTANDING - BASIC AND DILUTED                                          63,194,223         41,262,778       36,439,074
                                                                         =============        ==========       ==========

</TABLE>




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



                                       47
<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>
Balance, January 1, 2001    1,000     1     27,252,500    2,725   38,569,923   (261,375) (17,115,554)   (130,295)      21,065,425
 Conversion of preferred
  shares to common shares                    4,760,000      476        (476)                                                    -
 Issuance of common shares
  for acreage                                9,500,000      950   18,524,050                                            18,525,000
 Amortization of deferred
   compensation expense                                                         208,542                                    208,542
 Redemption of preferred
   and common stock         (1,000)   (1)   (6,250,000)    (625) (16,708,374)                                          (16,709,000)
 Issuance of common stock                    6,500,000      650    5,973,330                                             5,973,980
 Repurchase of common stock                 (1,400,000)    (140)  (1,399,860)                                           (1,400,000)
 Net loss                                -                                               (5,649,682)              -     (5,649,682)
                             ------  -----  -----------    ------ ----------   ---------  ----------     ----------      -----------

Balance, December 31, 2002                   40,362,500    4,036   44,958,593   (52,833)(22,765,236)      (130,295)      22,014,265
Issuance of preferred stock   11,052    11                          4,797,398                                             4,797,409
Issuance of common stock                      4,888,436      490    2,808,719                                             2,809,209
Issuance of restricted stock                    425,000       42      250,708  (221,250)                                     29,500
Amortization of deferred
  compensation                                                                   94,317                                      94,317
Beneficial conversion feature                                         166,667                                                166,667
Dividends paid                   682     1                             (4,092)                                               (4,091)
Net loss                                                                                  (2,526,525)                    (2,526,525)
Other                              -     -                               1,332             -               -                   1,332
                                ----    --   ----------     -----    ---------   ------- ------------     ----------     -----------

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
Amortization of deferred
  compensation                                                                     415,483                                   415,483
Proceeds from 16b violation                                            106,858                                               106,858
Dividends paid                                    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
                               =====   ===   ==========   =======    =========== ========== ============     ==========    =========

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

</TABLE>




                                       48
<PAGE>
<TABLE>
<CAPTION>



                                                             GASCO ENERGY, INC.
                                                    CONSOLIDATED STATEMENTS OF CASH FLOWS

                                                                              For the Years Ended December 31,
                                                                    ------------------------------------------------------
                                                                              2004             2003                2002
CASH FLOWS FROM OPERATING ACTIVITIES
<S>                                                                     <C>              <C>                 <C>
  Net loss                                                              $(4,205,830)     $(2,526,525)        $(5,649,682)
  Adjustment to reconcile net loss to net cash used in
   operating activities
     Depreciation, depletion and impairment expense                        1,085,912          541,128             690,234
     Accretion of asset retirement obligation                                 16,663           11,795                   -
     Amortization of deferred compensation                                   415,483           94,317             208,542
     Amortization of beneficial conversion feature                           161,514            6,945                   -
     Amortization of offering costs                                          294,993            7,758                   -
     Cumulative effect of change in accounting principle                           -            9,687                   -
     Changes in operating assets and liabilities:
      Accounts receivable                                                  (545,681)        (403,219)            (63,397)
      Inventory                                                          (1,009,914)                -                   -
         Prepaid expenses                                                     59,992        (320,059)            (74,139)
         Accounts payable                                                  (600,723)          164,303           1,303,823
         Revenue payable                                                      91,252          185,215              58,298
         Advances from joint interest owners                                 891,999                -                   -
         Accrued interest                                                    695,139                -                   -
         Accrued expenses                                                  1,743,832           36,741          2,136,015
                                                                           ---------        ---------      -------------
                  Net cash used in operating activities                    (905,369)      (2,191,914)         (1,390,306)
                                                                           ---------      -----------      --------------

CASH FLOWS FROM INVESTING ACTIVITIES
  Cash paid for furniture, fixtures and other                               (64,053)          (3,264)           (103,342)
  Cash paid for acquisitions, development and exploration               (25,736,066)      (5,283,426)        (14,437,855)
  Proceeds from property sales                                             4,463,161                -                   -
  Investment in short-term investments                                  (27,000,000)                -                   -
                                                                        ------------       ----------         -----------
                 Net cash used in investing activities                  (48,336,958)      (5,286,690)        (14,541,197)
                                                                        ------------  ---------------      --------------

CASH FLOWS FROM FINANCING ACTIVITIES
  Issuance of convertible notes                                           65,000,000                -                   -
  Cash designated as restricted                                         (10,313,095)        (250,000)           (250,000)
  Cash undesignated as restricted                                            250,000          250,000                   -
  Preferred dividends                                                       (61,973)          (4,092)                   -
  Exercise of options to purchase common stock                                33,336                -                   -
  Proceeds from sale of preferred stock                                            -        4,862,840                   -
  Proceeds from sale of common stock                                      21,500,001        2,777,292           6,500,000
  Proceeds from sale of convertible debentures                                     -        2,500,000                   -
  Cash paid for offering costs                                           (4,636,828)        (266,721)           (526,020)
  Repayment of note payable                                                        -      (1,400,000)                   -
  Proceeds from 16b violation                                                106,858           1,332                    -
                                                                        ------------       ----------           ---------
                Net cash provided by financing activities                 71,878,299        8,470,651           5,723,980
                                                                        ------------        ---------           ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS                      22,635,972          992,047        (10,207,523)

CASH AND CASH EQUIVALENTS:
    BEGINNING OF PERIOD                                                    3,081,109        2,089,062          12,296,585
                                                                          ----------       ----------          ----------
    END OF PERIOD                                                        $25,717,081      $ 3,081,109         $ 2,089,062
                                                                         ===========      ===========         ===========
</TABLE>

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

                                       49
<PAGE>

                                GASCO ENERGY INC.
                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
              FOR THE YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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.

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, 2004  represents  funds
invested in U.S.  government  securities in an amount  sufficient to provide for
the  payment of the first six  semi-annual  scheduled  interest  payments on the
Company's outstanding 5.5% Convertible Notes ("Notes"),  as further described in
Note 7. The current portion of restricted cash represents the interest  payments
that are due within the first year and the  non-current  portion  represents the
interest  payments  that are due after one year.  This  investment  will be held
until maturity and the cost of the investment approximates its market value. The
restricted  cash  balance at December 31, 2003  consisted  of a $250,000  escrow
agreement in  connection  with one of its drilling  projects.  The funds held in
escrow were released during May 2004.

Short-term Investments

The Company's short-term investments consist primarily of preferred auction rate
securities,  which are classified as  available-for-sale.  These  securities are
stated at fair value based on quoted market prices.

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.

                                       50
<PAGE>

Property, Plant and Equipment

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. 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.

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  periodically  for impairment.  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 may not exceed an
amount equal to the present  value,  discounted at 10%, of estimated  future net
revenues  from proved oil and gas  reserves  plus the cost,  or  estimated  fair
value, if lower of unproved  properties.  Should  capitalized  costs exceed this
ceiling, an impairment is recognized.  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.

Gathering Assets

Gathering assets as of December 31, 2004 represent 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.

Impairment of Long-lived Assets

The Company's unproved properties are evaluated periodically for the possibility
of potential impairment.  During 2003, the Company recorded an impairment of its
Wyoming  acreage of $1,725,000 by  reclassifying  these costs into the full cost
pool. The impairment  represented  the cost of certain of the Company's  acreage
that expired in 2004 that it did not consider to be prospective.  Other than oil
and gas properties,  the Company has no other long-lived  assets and to date has
not recognized any impairment losses.

                                       51
<PAGE>

Deferred Financing Costs

Deferred financing costs as of December 31, 2004 consist of the costs associated
with the  Company's  issuance of  $65,000,000  of Notes during  October 2004, as
further described in Note 7. These costs are being amortized over the seven-year
life of the Notes.  The December 31, 2003 balance  represents the offering costs
associated  with  the  Company's   issuance  of  $2,500,000  in  8%  Convertible
Debentures  ("Debentures"),  further described in Note 7. These costs were being
amortized over the five-year  life of the  Debentures  until they were converted
into common stock during October 2004. The Company recorded amortization expense
of $294,993 and $7,758  related to these costs  during the years ended  December
31, 2004 and 2003, respectively.

Asset Retirement Obligation

In June 2001 the Financial  Accounting Standards Board ("FASB") issued Statement
of  Financial  Accounting  Standards  ("SFAS")  No. 143,  "Accounting  for Asset
Retirement Obligations,  " which required 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 asset retirement  liability will be allocated to operating
expense by using a systematic  and  rational  method.  The Company  adopted this
statement as of January 1, 2003 and recorded a net asset of $139,247,  a related
liability of $148,934  (using a 9% discount rate and a 2% inflation  rate) and a
cumulative  effect of change in  accounting  principle on prior years of $9,687.
The information  below reconciles the value of the asset  retirement  obligation
from the date the liability was recorded.

                                                      Year Ended December 31,
                                                      2004               2003

        Balance beginning of period                 $142,806         $ 148,934
          Liabilities incurred                        29,394                 -
          Liabilities settled                       (25,188)                 -
          Revisions in estimated cash flows         (55,109)          (17,923)
          Accretion expense                           16,663            11,795
                                                   --------             ------
        Balance end of period                     $ 108,566          $ 142,806
                                                  ==========         =========


The  revisions in estimated  cash flows is primarily the result of the Company's
decision to revise the life of the  producing  wells from twenty years to thirty
years based upon the drilling and production results in the area.

The following  schedules  present,  on a pro forma basis,  the asset  retirement
obligation,  the net loss,  net loss per share  amounts as if the  provisions of
SFAS No. 143 had been applied  during all the periods  presented.  The pro forma
information  for the year  ended  December  31,  2004 is the same as the  actual
information reported.

                                       52
<PAGE>

                                             As of December 31,
                                                    2002

    Asset Retirement Obligation                $ 148,934

                                      For the Year Ended December 31,
                              -----------------------------------------------
                                   2003                    2002
                                   ----                    ----
       Net Loss
           As reported         $ (2,526,525)           $ (5,649,682)
           Pro forma             (2,516,838)             (5,652,438)
       Net Loss per Common
       Share
           As reported               $(0.07)                 $(0.16)
           Pro forma                  (0.07)                  (0.16)

Revenue Recognition

Oil and gas revenue is  recognized as income when the oil or gas is produced and
sold.

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  computed  using the treasury  stock method
which assumes that the increase in the number of shares is reduced by the number
of shares  which could have been  repurchased  by the Company  with the proceeds
from the  exercise of the options  (which were  assumed to have been made at the
average  market price of the common  shares during the  reporting  period).  The
Series B Convertible  Preferred  Stock  ("Preferred  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,  2004,  we had  70,517,209  shares of common stock issued and
outstanding.  As of such  date,  there  were  8,460,678  shares of common  stock
issuable upon  exercise of  outstanding  options and  conversion of our Series B
Convertible  Preferred  Stock.  Additional  options  may be granted to  purchase
3,825,721  shares of common stock under our stock option plan and an  additional
179,150 shares of common stock are issuable under our restricted  stock plan. As
of December 31, 2004, 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.

                                       53
<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  86,767,209  shares (this number assumes no
exercise of the options or rights  described above or conversion of the Series B
Convertible Preferred Stock).

In March 2004, the FASB issued consensus on EITF 03-6, "Participating Securities
and the  Two-Class  Method Under FASB  Statement  No. 128,  Earnings Per Share,"
related to  calculating  earnings per share with respect to using the  two-class
method for  participating  securities.  This  pronouncement is effective for all
periods after March 31, 2004, and requires prior periods to be restated.  As the
Company has  incurred  net losses in the current and prior  periods,  and as the
Company's preferred stock does not have a contractual obligation to share in the
losses of the Company,  the adoption of EITF 03-6 had no impact on the Company's
financial condition, or its results of operations.

Significant Customers

Although the Company sells the majority of its  production to a few  purchasers,
there  are  numerous  other  purchasers  in the  areas in which  Gasco  sells it
production; therefore, the loss of its significant customers would not adversely
affect the Company's operations. For the years ended December 31, 2004, 2003 and
2002,  purchases by the following  company exceeded 10% of the total oil and gas
revenues of the Company.

                                     For the Year Ended December 31,
                              ------------------------------------------------
                                 2004            2003                 2002
                                 ----            ----                 ----

      ConocoPhillips Company     93%              93%                 98%

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


                                       54
<PAGE>

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, 2004,  the market value of the Company's  short-term
investments was equal to its cost basis and therefore,  there were no unrealized
gains and losses included in other comprehensive income during 2004.

The Company does not have any other items of other comprehensive  income for the
years ended December 31, 2004,  2003 and 2002.  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 Based Compensation

The  Company  accounts  for  its  stock-based   compensation   using  Accounting
Principles  Board's  Opinion No. 25 ("APB No. 25") and related  interpretations.
Under APB 25,  compensation  expense is  recognized  for stock  options  with an
exercise  price  that is less than the  market  price on the  grant  date of the
option. The Company has adopted the  disclosure-only  provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation
("SFAS 123") for the stock options granted to the employees and directors of the
Company.  Accordingly,  no  compensation  cost has  been  recognized  for  these
options.  Had compensation expense for the options granted been determined based
on the  fair  value  at the  grant  date for the  options,  consistent  with the
provisions  of SFAS 123, the Company's pro forma net loss and net loss per share
for the years ended  December 31, 2004,  2003 and 2002 would have been increased
to the pro forma amounts indicated below:
<TABLE>
<CAPTION>
                                                              For the Year Ended December 31,
                                                         2004               2003               2002
                                                         ----               ----               ----

Net loss attributable to common shareholders:
<S>                                                    <C>               <C>                 <C>
    As reported                                        $ (4,205,830)     $ (2,830,697)       $ (5,649,682)
    Add: Stock-base employee compensation
       included in net loss (a)                             312,243            41,484                   -
    Less: Stock based employee compensation
      determined under the fair value based method          757,294           742,211           1,709,226
                                                        -----------       -----------          ----------
    Pro forma                                           $(4,650,881)      $(3,531,424)        $(7,358,908)
                                                        ============      ============        ============

Net loss per common share:
    As reported                                             $ (0.07)          $ (0.07)            $ (0.16)
                                                            ========          ========            ========

    Pro forma                                               $ (0.07)          $ (0.09)            $ (0.20)
                                                            ========          ========            ========
</TABLE>


                                       55
<PAGE>

     (a)  Represents  the  compensation  expense  associated  with the Company's
          restricted stock awards, further described in Note 8.

The fair value of the common stock options  granted during 2004,  2003 and 2002,
for disclosure purposes was estimated on the grant dates using the Black Scholes
Pricing Model and the following assumptions.

                                         For the Year Ended December 31,
                                  ------------------------------------------
                                         2004          2003            2002
                                         ----          ----            ----

     Expected dividend yield               --            --              --
     Expected price volatility       79 - 87%           82%             90%
     Risk-free interest rate       3.2 - 3.9%          2.9%     3.5% - 4.1%
     Expected life of options         5 years       5 years         5 years

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.

Fair Value

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 5.5% Convertible 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.

Recent Accounting Pronouncements

In December 2004, the FASB issued SFAS No. 123(R),  "Share-Based Payment," which
is a revision of SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No.
123(R) is effective for public companies for interim or annual periods beginning
after June 15, 2005,  supersedes APB Opinion No. 25, Accounting for Stock Issued
to Employees, and amends SFAS No. 95, Statement of Cash Flows.

                                       56
<PAGE>

SFAS No. 123(R) requires all share-based payments to employees, including grants
of employee stock  options,  to be recognized in the income  statement  based on
their fair values.  Pro-forma  disclosure is no longer an  alternative.  The new
standard will be effective for the Company,  beginning  August 1, 2005. SFAS No.
123R  permits  companies  to adopt its  requirements  using  either a  "modified
prospective" method, or a "modified  retrospective"  method. Under the "modified
prospective" method, compensation cost is recognized in the financial statements
beginning with the effective  date,  based on the  requirements of SFAS No. 123R
for  all  share-based  payments  granted  after  that  date,  and  based  on the
requirements  of SFAS  No.  123 for all  unvested  awards  granted  prior to the
effective date of SFAS No. 123R. Under the "modified  retrospective" method, the
requirements are the same as under the "modified  prospective"  method, but also
permits entities to restate financial statements of previous periods, either for
all prior periods  presented or to the beginning of the fiscal year in which the
statement is adopted, based on previous pro forma disclosures made in accordance
with SFAS No. 123.  The Company has not yet  determined  which of the methods it
will use upon adoption.  The Company has not yet completed their  evaluation but
expects  the  adoption  SFAS  No.  123(R)  to have an  effect  on the  financial
statements  similar  to  the  pro-forma  effects  reported  in the  Stock  Based
Compensation  disclosure above. In March 2004, the FASB issued consensus on EITF
03-6,  "Participating  Securities and the Two-Class  Method Under FASB Statement
No. 128,  Earnings Per Share,"  related to  calculating  earnings per share with
respect  to using  the  two-class  method  for  participating  securities.  This
pronouncement  is effective for all periods  after March 31, 2004,  and requires
prior  periods to be  restated.  As, the Company has  incurred net losses in the
current and prior periods,  and as the Company's preferred stock does not have a
contractual  obligation  to share in the losses of the Company,  the adoption of
EITF 03-6 had no impact on the Company's financial condition,  or its results of
operations.  The  Securities  and Exchange  Commission  issued Staff  Accounting
Bulletin (SAB) No. 106 in September  2004 regarding the  application of SFAS No.
143,  "Accounting for Asset Retirement  Obligations,"  for oil and gas producing
entities that follow the full cost accounting  method.  SAB No. 106, states that
after  adoption  of SFAS No.  143,  the future  cash  outflows  associated  with
settling  asset  retirement  obligations  that have been  accrued on the balance
sheet should be excluded  from the present  value of  estimated  future net cash
flows  used  for the  full  cost  ceiling  test  calculation.  The  Company  has
calculated  its ceiling  test  computation  in this manner since the adoption of
SFAS  No.  143  and,  therefore,  SAB No.  106 had no  effect  on the  Company's
financial statements, effective in the fourth quarter of 2004.

Reclassifications

Certain  reclassifications  have been made to prior years' amounts to conform to
the classifications used in the current year.



                                       57
<PAGE>



NOTE 3 - OIL AND GAS PROPERTY

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,
                                                  ----------------------------------------------------
                                                    2004              2003                2002
                                                  -------------------------------- -------------------
Property acquisition costs:
<S>                                                 <C>                  <C>              <C>
   Unproved                                         $ 5,021,126          $667,557         $22,324,547
   Proved                                               723,901               --                   --
Exploration costs (a)                                   216,165           396,967           3,319,124
Development costs                                    17,501,716         4,218,902           7,319,184
                                                    -----------         ---------          ----------
   Total excluding asset retirement obligation       23,462,908         5,283,426          32,962,855
                                                     ==========         =========          ==========
   Total including asset retirement obligation      $23,398,559       $ 5,398,678        $ 32,962,855
                                                    ===========       ===========        ============
</TABLE>

(a) Includes  seismic data  acquisitions  of $850,000 during twelve months ended
December 31, 2002.

Depletion and impairment expense related to proved properties per equivalent Mcf
of production  for the years ended  December 31, 2004,  2003 and 2002 was $2.06,
$2.06 and $9.73, respectively.

During the first  quarter of 2002,  the Company  drilled a well in the Southwest
Jonah  field  located in the  Greater  Green  River  Basin in  Sublette  County,
Wyoming.  The  well  was  drilled  to a total  depth of  11,000  feet.  The well
encountered  natural  gas,  however not of  sufficient  quantities  to be deemed
economic.  The well was plugged and  abandoned  during March of 2002.  The costs
associated with this well of $541,125, were charged to impairment expense during
the year ended  December  31, 2002 because the Company  believed  that the total
costs for this well exceeded the present value, discounted at 10%, of the future
net revenues from its total proved oil and gas reserves at the time the well was
plugged and abandoned.

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

                                        2004                 2003
                                        ----                 ----

        Utah                        $ 5,950,861            $ 963,530
        Wyoming                      12,312,742           12,089,104
        California                      185,727              159,405
                                    -----------          -----------
                                    $18,449,330          $13,212,039
                                    ===========          ===========

During 2003, the Company  impaired certain of its unproved acreage in Wyoming by
reclassifying  $1,725,000  of costs  associated  with this acreage into the full
cost pool.  The  impairment  represents  the cost of  certain  of the  Company's
acreage  that the Company no longer  considerd  prospective.  These costs became
subject to amortization during the fourth quarter of 2003.




                                       58
<PAGE>



The following table  represents the additions,  net of impairments and transfers
to proved oil and gas  properties,  to unproved  acreage from inception  through
December 31, 2004:

                                                             Net Acquisition
                        Years                                     Costs
                  2001 and earlier                            $ 9,152,740
                        2002                                    4,831,796
                        2003                                    (772,497)
                        2004                                    5,237,291
                                                              -----------
   Unproved Mineral Interest as of
       December 31, 2004                                     $ 18,449,330
                                                             ============

The Company's drilling activities are located primarily in the Riverbend Area of
Utah, and the Company plans to drill  approximately 20 wells in this area during
2005.  The Company  continues  to consider  several  options for its Wyoming and
California acreage such as the farm-out of some of its acreage and other similar
type transactions.

NOTE 4 - PROPERTY ACQUISITIONS

On March 9, 2004 the Company  completed the  acquisition  of additional  working
interests in six producing  wells,  13,062 net acres and gathering system assets
located in the Uinta Basin in Utah for approximately $3,175,000. During May 2004
an  unrelated  third party  exercised  its right to purchase 25% of the acquired
properties  at the  acquisition  price,which  had the  effect  of  reducing  the
purchase price to approximately  $2,400,000 and reducing the Company's  interest
in the  acquisition to 75%. The effective date of the acquisition was January 1,
2004;  however,  the net revenue from the producing wells during the period from
January  1,  2004  through  March 9, 2004 was  recorded  as a  reduction  to the
purchase price.

The  following  unaudited  pro forma  consolidated  results  of  operations  are
presented as if the acquisition occurred on January 1, 2002.
<TABLE>
<CAPTION>

                                                      For the Year Ended December 31,
                                                  2004                2003               2002
                                                  ----                ----               ----

<S>                                           <C>                  <C>                 <C>
Revenue                                       $ 3,742,586          $2,363,046          $801,884
Loss before cumulative effect of
   change   in accounting principle            (4,136,633)         (1,918,451)       (5,465,693)
Net Loss                                       (4,136,633)         (1,928,138)       (5,465,693)
Net Loss Attributable to Common
  Stockholders                                 (4,277,486)         (2,232,310)       (5,545,693)

Net Loss per Common Share - Basic
  and Diluted                                     $(0.07)            $ (0.05)          $ (0.15)
</TABLE>

During  December  2004,  the Company  completed  the  acquisition  of additional
acreage in the Riverbend Area for a purchase price of approximately  $3,432,000.
Pursuant  to an existing  contract,  an  unrelated  third party had the right to

                                       59
<PAGE>

purchase  25% of the  acquired  acreage at a price equal to 25% of the  purchase
price. This right was exercised by the third party during January 2005 which had
the effect of  reducing  the  Company's  purchase  price of the  acquisition  to
approximately $2,575,000.

NOTE 5 - SERVICE PARTIES' AGREEMENT

On January 20, 2004 the Company entered into agreements, which were subsequently
amended in July 2004, 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.

Gasco has agreed that the Service Parties,  which includes Schlumberger Oilfield
Services,  will  have the  exclusive  right to  provide  their  services  in the
development of the Riverbend acreage.  The agreement  initially provided for the
group to develop a bundle of 10 wells during 2004 using a single  drilling  rig.
Thereafter,  drilling was  accelerated  using an  additional  rig. A third party
investor was  subsequently  added as a party to these  agreements.  Gasco's 2004
capital budget was  approximately  $13 million for the drilling,  completion and
pipeline  connection of wells in this area.  During the fourth  quarter of 2004,
the Service Parties and the investor agreed to proceed with the second bundle of
ten wells.  The  drilling  of the  second  bundle  commenced  in  December  upon
completion of the first bundle.

General Terms of the Amended Agreement:

     o    Contract  Area consists of Gasco's  leasehold  position in portions of
          Carbon, Duchesne and Uintah Counties, Utah.

     o    Gasco is permitted  to  independently  develop its acreage  subject to
          certain limitations and provisions of the agreement.

     o    Schlumberger will coordinate most operational activities under Gasco's
          direction as operator of record.

     o    Gasco  has  elected  to fund  approximately  30% of each of the  wells
          drilled  under this  agreement.  Gasco's  interest  in the  production
          stream  from a bundle,  net of  royalties,  taxes and lease  operating
          expenses, is estimated to equal the proportion of the total well costs
          that it funds.

     o    The  Service  Parties  and the  investor  have  undertaken  to provide
          approximately 45% and 25%, respectively,  of the costs of each project
          bundle  in  return  for  a  net   profits   interest  in  each  bundle
          proportionate to their costs contributed.

To secure its obligations under the agreement,  described above, the Company has
pledged its interests in each of the wells in each bundle.

NOTE 6 - PROPERTY DIVESTITURES

In  connection  with the Service  Parties  agreements,  described in Note 5, the
Company  completed a disposition of net profits  interests of between 18.75% and
25% in the 8 wells that have been drilled in the  Riverbend  area in Utah during


                                       60
<PAGE>

2004  for  total  cash  consideration  of  $4,314,984,  net of  adjustments  and
commissions.  The purpose of this transaction was to allow third party investors
to  become  a  party  to  the  Company's  service  provider  arrangements.   The
consideration  paid to the Company in this transaction  represented the share of
such  investor's  development  costs of the 8 wells  completed  as of such date.
These  investors  have  the  opportunity  to  continue  to  participate  in  the
development  program under the service  provider  arrangement  by funding 25% of
future development costs.

The cash received by the Company consisted of $4,314,984,  which represented the
purchase price for the  transaction of $4,790,387  less  adjustments of $327,227
for net revenue minus lease operating  expense for the properties from June 2004
and $148,176,  representing a commission to the purchasers'  financial  advisor,
which the Company agreed to pay.

The  following  unaudited  pro forma  consolidated  results  of  operations  are
presented as if the disposition occurred on January 1, 2003. The results for the
year ended  December  31,  2002 are the same as the actual  results  because the
wells were not drilled until 2003.

                                           For the Year Ended December 31,
                                             2004                     2003
                                             ----                     ----

Revenue                                  $ 3,139,967               $1,222,848
Loss before cumulative effect of
   change  in accounting principle       (4,688,491)              (2,605,703)
Net Loss                                 (4,688,491)              (2,615,390)
Net Loss Attributable to Common
  Stockholders                           (4,829,344)              (2,919,562)

Net Loss per Common Share - Basic
  and Diluted                                $(0.08)                 $ (0.07)

During October 2003, the Company  completed a transaction  whereby it settled an
outstanding  amount owed of $1,606,982 to an  oilservice  provider  arising from
drilling and completion expenditures on five Gasco-operated wells, by paying the
provider  $400,000  in cash and  conveying  to the  provider  a  portion  of its
interests in two Riverbend  wells.  Subsequent to the  transaction,  the Company
retained a 30% working  interest in the two subject  wells and  ownership in the
remaining three wells is unchanged.

NOTE 7 - CONVERTIBLE 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.

                                       61
<PAGE>

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
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 October 20, 2004 or the most recent  interest
payment date, and is payable in cash  semi-annually  in arrears on April 5th and
October 5th of each year,  commencing  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  "Pledge  Agreement"),  the  Company  has  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.
$10,313,095  of the net proceeds  from the offering of Notes was used to acquire
such U. S.  government  securities,  which is recorded as restricted cash 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.

                                       62
<PAGE>

Based on the market price of the Company's common stock as of December 31, 2004,
the fair value of the Notes is $69,225,000.

The Notes are due in 2011 and  therefore do not have any  maturities  within the
next five years.

Immediately  prior to and in connection  with the closing of the offering of the
Notes, the holders of the Company's  Debentures  converted the entire $2,500,000
principal  amount thereof into 4,166,665  shares of Common Stock.  In connection
with the conversion, the Company paid the holders $270,247, representing 120% of
the future interest payments under the Debentures through November 15, 2005.

NOTE 8 - STOCKHOLDERS' EQUITY

The  Company's  capital  stock as of  December  31,  2004 and 2003  consists  of
100,000,000  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, 2004, Gasco had 2,255
shares of Series B Preferred Stock  ("Preferred  Stock") issued and outstanding.
The Preferred Stock is 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 is $0.70 per common share,  which was greater than the market price on the
issuance  date,   making  each  share  of  Preferred  Stock   convertible   into
approximately  629 shares of Gasco common stock.  Shares of the Preferred  Stock
are convertible  into Gasco common shares at any time at the holder's  election.
Gasco  may  redeem  shares  of the  Preferred  Stock  at a price  of 105% of the
purchase price at any time after February 10, 2006. The Preferred Stock votes as
a class on issues that affect the  Preferred  Stockholder's  interests and votes
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,  2004,  the Company  paid  dividends to the
holders of its Preferred  Stock  consisting of 41,959 shares of common stock and
$61,973 in cash.

Common Stock - Gasco has 70,590,909 shares of Common Stock issued and 70,517,209
shares outstanding as of December 31, 2004. 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, the holders of the
Preferred  Stock  are  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  2004  and  2003 are
described as follows:

                                       63
<PAGE>

On February 11, 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. Proceeds to the Company, net of fees and expenses were
approximately  $20,070,000.  The  proceeds  from this  sale are  being  used for
general  corporate  purposes  including the  acquisition  of oil and natural gas
assets and the development and exploitation of Gasco's  Riverbend Project in the
Uinta Basin in Uintah County, Utah.

During 2004,  certain  holders of the Company's  Preferred Stock converted 9,479
shares of Preferred Stock into 5,958,226 shares of common stock.

On June 14, 2004,  the  Company's  Board of  Directors  approved the issuance of
395,850  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.

The  compensation  expense related to the restricted  stock was measured on June
14, 2004 using the trading  price of the Company's  common  stock,  the date the
restricted  shares  were issued 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 735,850 unvested shares of
restricted  stock  outstanding  as of  December  31,  2004 and the  compensation
expense  related  to these  shares  during  year  ended  December  31,  2004 was
$312,243.

During the third quarter of 2004,  upon vesting of a previous  restricted  stock
grant,  an officer  of Gasco  returned  14,397 of his  shares to the  Company in
satisfaction of his personal tax liability that resulted from the vesting of the
restricted stock. The Company canceled these shares during the fourth quarter of
2004.

On October 23, 2003 the Company  completed the sale through a private  placement
of  4,788,436  shares  of its  common  stock to a group of  accredited  previous
investors.  The selling price of $0.58 per common share was determined by taking
97 percent of the 20-day average closing price of the Company's common stock for
the  period  ending  October  17,  2003,  and  resulted  in  total  proceeds  of
approximately  $2,780,000.  The expenses  associated with this  transaction were
approximately  $15,000.  The  Company  plans  to  use  the  proceeds  from  this
transaction to develop and exploit its core-area  Riverbend Project in the Uinta
Basin in Utah and for its ongoing operations.

On August 12, 2003,  the Company's  Board of Directors  approved the issuance of
425,000  shares of common stock,  under the Gasco Energy,  Inc. 2003  Restricted
Stock Plan ("Restricted  Stock Plan"), to certain of the Company's  officers and
directors.  The restricted shares vest 20% on the first anniversary,  20% on the


                                       64
<PAGE>

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.

The  compensation  expense  related  to the  restricted  stock was  measured  on
September  18,  2003,  the date the  Restricted  Stock Plan was  approved by the
Company's  stockholders 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  425,000  unvested  shares  of
restricted  stock  outstanding  as of  December  31,  2003 and the  compensation
expense  related to these  shares  during the year ended  December  31, 2003 was
$41,484.

NOTE 9 - STOCK OPTIONS

During 2004,  the Company  granted an additional  1,410,000  options to purchase
shares of common stock to employees,  directors and  consultants of the Company,
at exercise  prices  ranging from $1.61 to $2.15 per share.  The options vest 16
2/3% at the end of each  four-month  period after the  issuance  date and expire
within ten years from the grant date.

During 2003,  the Company  granted an additional  1,658,000  options to purchase
shares of common stock to employees and directors of the Company, at an exercise
price of $1.00 per share. The options vest 16 2/3% at the end of each four-month
period after the issuance date.  Additionally,  the Company cancelled  2,346,664
options to purchase shares of common stock during the first quarter of 2003. The
exercise  price of the cancelled  options  ranged from $1.95 to $3.15 per share.
None of the 1,658,000 options granted during 2003 were issued to the individuals
whose options were cancelled.

As of December 31, 2004 options to purchase an aggregate 7,043,250 shares of the
Company's common stock were outstanding. These options were granted during 2004,
2003,  2002 and 2001 to the Company's  employees,  directors and  consultants at
exercise  prices  ranging  from $1.00 to $3.70 per share.  The  options  vest at
varying  schedules  within two years of their  grant date and expire  within ten
years  from the  grant  date.  The  aggregate  fair  market  value  of  options,
determined using the Black Scholes Pricing Model,  granted to consultants and an
officer of the  Company,  of  $73,705,  $52,833,  and  $208,542  was  charged to
operations   during  the  years  ended   December  31,  2004,   2003  and  2002,
respectively.

A summary  of the  options  granted to  purchase  common  stock and the  changes
therein  during the years ended  December 31,  2004,  2003 and 2002 is presented
below.



                                       65
<PAGE>
<TABLE>
<CAPTION>




                                                     2004                         2003                            2002
                                                     ----                         -----                           ----
                                                          Weighted                     Weighted                         Weighted
                                                           Average                      Average                         Average
                                           Number of      Exercise       Number of     Exercise         Number of       Exercise
                                            Options         Price         Options        Price           Options         Price
                                            -------         -----         -------        -----           -------         -----

<S>                                          <C>               <C>         <C>             <C>             <C>              <C>
Outstanding at beginning of year             5,666,586         $ 2.07      6,355,250       $ 2.17          6,392,750        $ 2.23
Granted                                      1,410,000           1.98      1,658,000         1.00            500,000          1.80
Exercised                                     (33,336)           1.00              -                               -
Cancelled                                                        2.18    (2,346,664)         2.18          (537,500)          2.56
                                              ---------          ----    -----------         ----          ---------          ----
Outstanding at end of year                   7,043,250         $ 1.85      5,666,586       $ 1.83          6,355,250        $ 2.17
                                             =========         ======      =========       ======          =========        ======

Exercisable at December 31,                  5,624,417         $ 1.42      4,476,586       $ 2.07          6,027,085        $ 2.06
                                             =========         ======      =========       ======          =========        ======

Weighted average fair value of options granted                 $ 1.28                      $ 0.45                           $ 1.37
                                                               ======                      ======                           ======
</TABLE>

Weighted average remaining contractual life of options
    outstanding as of December 31, 2004                         7.1 years
                                                                ===


The  following  table  presents  additional  information  related to the options
outstanding as of December 31, 2004.

          Exercise                          Number of     Weighted Average
          Price per    Number of Shares      Shares     Remaining Contractual
            Share        Outstanding        Exercisable     Life (years)
            -----        -----------        ----------       -------
           $1.00           2,558,000       2,298,333           8.1
            1.58             150,000         150,000           3.3
            1.61             100,000          33,334           9.1
            1.73             100,000         100,000           3.2
            1.80              50,000          50,000           6.7
            1.92             735,000         122,500           9.6
            2.00           1,451,000       1,326,000           8.1
            2.15             425,000          70,000           9.6
            2.20               8,000           8,000           2.9
            3.00             650,000         650,000           5.6
            3.10              82,500          82,500           1.8
            3.15             613,750         613,750           1.8
            3.70             120,000         120,000           1.4
                           ---------        --------           ----
        Total              7,043,250        5,624,417           7.1
                           =========        =========           ===

NOTE 10 - STATEMENT OF CASH FLOWS

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

                                       66
<PAGE>

     Conversion  of $2,500,000 of  Debentures  into  4,166,665  shares of common
stock.

     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.

The  following  transactions  represent  the non-cash  investing  and  financing
activities of the Company during the year ended December 31, 2003.

     Recognition  of  an  asset  retirement  obligation  for  the  plugging  and
     abandonment costs related to the Company's oil and gas properties valued at
     $148,934.

     Issuance  of 682 shares of  Preferred  Stock in payment of the June 30, and
     December 31, 2003 Preferred Stock dividends.

     Issuance of 425,000  shares of  restricted  common  stock to certain of the
     Company's  officers and  directors  and the  issuance of 100,000  shares of
     common stock as compensation to a former employee.

     Assignment  of property  interests in two wells in settlement of $1,206,982
     in accounts payable and $17,923 in the asset retirement obligation.

During the year ended  December 31, 2002, the Company's  non-cash  investing and
financing activities consisted of the following transactions:

     Conversion of 500 shares of Series A Preferred stock into 4,750,000  shares
of common stock.

     Issuance of 9,500,000  shares of common  stock,  valued at  $18,525,000  in
     exchange for oil and gas properties.

                                       67
<PAGE>

     Repurchase of 500 shares of Series A Preferred  stock and 6,250,000  shares
     of common stock in exchange for an  undivided  25% working  interest in the
     Company's undeveloped acreage valued at $16,709,000.

     Repurchase of 1,400,000 shares of common stock in exchange for a promissory
     note.

     Noncash  stock  offering  costs of  $250,000  incurred in  connection  with
     redeemable common stock.

Cash paid for  interest  was $ 463,769 and $82,392 for the years ended  December
31, 2004 and 2003, respectively.  There was no cash paid for interest during the
year ended  December 21, 2002 and there was no cash paid for income taxes in any
of the years ended December 31, 2004, 2003 and 2002.

NOTE 11 - INCOME TAXES

A provision  (benefit)  for income taxes for the years ended  December 31, 2004,
2003 and 2002 consists of the following:

                                       2004            2003              2002
                                       ----            ----              ----
Current taxes:
  Federal                              $     -            $   -         $     -
  State                                      -                -               -
Deferred taxes:
  Federal                          (1,371,000)      (2,556,837)        (74,128)
  State                              (157,580)        (285,004)        (68,422)
  Less: valuation allowance          1,528,580        2,841,841         142,550
                                     ---------        ---------         -------
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, 2004, 2003 and 2002 is
summarized below:
<TABLE>
<CAPTION>

                                                           2004                 2002              2001
                                                           ----                 ----              ----

<S>                                                    <C>                   <C>              <C>
Tax provision (benefit) at federal statutory rate      $ (1,429,982)         $ (859,019)      $ (1,920,892)
State taxes, net of federal tax effects                    (104,032)           (188,102)           (45,159)
Valuation adjustment on assets distributed in
  stock redemption                                                 -                   -          1,798,941
Prior year tax return permanent true-up                            -         (1,798,941)                  -
Other Permanent items                                          5,434               4,221             24,560
Valuation allowance                                        1,528,580           2,841,841            142,550
                                                           ---------          ----------            -------
Net income tax provision (benefit)                      $          -         $         -       $          -
                                                           ==========         ==========        ===========
</TABLE>




                                       68
<PAGE>



The  components  of the deferred tax assets and  liabilities  as of December 31,
2004 and 2003 are as follows:

                                                       2004           2003
                                                       ----           ----
Deferred tax assets:
Federal and state net operating loss carryovers     $ 7,415,121     $4,576,075
Oil and gas property                                    133,530      1,272,043
Deferred compensation                                   362,029        284,805
                                                        -------      ---------
    Total deferred tax assets                         7,910,680      6,132,923
  Less: valuation allowance                         (6,935,384)    (5,406,804)
                                                    -----------    -----------
                                                        975,296        726,119
Deferred tax liabilities:
Other property, plant & equipment                       758,796        318,777
Other                                                   216,500        407,342
                                                        -------        -------
     Total deferred tax liabilities                     975,296        726,119
                                                        -------        -------
Net deferred tax asset                                  $     -        $     -
                                                        =======        =======

The Company has a $19,622,107  net operating  loss  carryover for federal income
tax purposes and a $15,342,165 net operating loss carryover for state income tax
purposes as of December 31, 2004.  The net operating  losses may offset  against
taxable  income  through the year ended  December 31, 2024. A portion of the net
operating  loss  carryovers  begins  expiring in 2019.  The  Company  provided a
valuation  allowance against its deferred tax asset of $6,935,384 and $5,406,804
as of December  31, 2004 and 2003,  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.

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,  will 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 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").


                                       69
<PAGE>

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 year ended December 31, 2003 a clerical error was made in the payroll
process,  which caused the president and chief executive officer of the Company,
Mark  Erickson,  to be overpaid by $55,000  during 2003,  and $9,196  during the
first quarter of 2004.  The error was discovered  during  February 2004, and Mr.
Erickson made  restitution as soon as possible  thereafter.  Since the repayment
was made as soon as possible,  no interest was charged and Mr.  Erickson owes no
further  amounts to the Company.  The overpayment of $55,000 was included in the
accounts  receivable  balance of the  accompanying  financial  statements  as of
December 31, 2003.

During the each of years ended  December  31, 2004,  2003 and 2002,  the Company
paid $120,000 in consulting fees to a company owned by a director of Gasco.  The
Company is committed to pay $120,000 per year in consulting fees to this company
through January 31, 2006. Another director of the Company earned consulting fees
of $16,000 from the Company during the year ended December 31, 2002.

During the year ended December 31, 2002, the Company paid $110,266 in consulting
fees to an unrelated  third party.  The obligation to pay these fees was a joint
and several  liability of Gasco and a Company of which two of Gasco's  directors
have a combined 66.67% ownership.

An officer of the Company,  who retired  effectively  December 31, 2002,  was an
employee  of and owned a less than 1%  interest  in an entity  from which  Gasco
purchased  acreage in Utah and Wyoming during 2001 and 2002.  Additionally,  the
Company  recorded a payable to this  officer of $213,000 as of December 31, 2002
representing  a bonus of $150,000  and  severance  payments  of  $63,000.  These
amounts  were paid to this  officer in full during the year ended  December  31,
2003.

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.




                                       70
<PAGE>



NOTE 13 - COMMITMENTS

The Company currently leases  approximately 3,255 square feet of office space in
Englewood,  Colorado  for  approximately  $46,000 per year under a lease,  which
terminates  on August 30, 2005.  Subsequent to December 31, 2004, as a result of
the Company's  growth,  the Company  entered into a new lease for  approximately
6,234  square feet of office  space  which  commences  April 1, 2005.  The lease
terminates  on March 31, 2010 and the average  rent for this space over the life
of the lease is  approximately  $86,500 per year. The Company believes that this
new space will meet its needs for the next five years. The following table shows
the annual rentals per year for the life of the lease.

        Year Ending December 31,                  Annual Rentals

                  2005                              $   85,796
                  2006                                  79,125
                  2007                                  85,047
                  2008                                  90,970
                  2009                                  96,892
               Thereafter                               24,594
                                                        ------
                                                      $462,424
                                                      ========

Rent expense for the years ending  December 31, 2004, 2003 and 2002 was $52,822,
$56,970 and $42,055, 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 has  entered  into  employment  agreements  with three key  officers
through January 31, 2006. These agreements were revised during the first quarter
of 2003 to  reduce  the  total  compensation  for the  officers  covered  by the
employment  agreements  from  $560,000  per annum to  $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.

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 the  participating  employee's
compensation to the Plan. The contributions made by the Company totaled $36,225,


                                       71
<PAGE>

$32,708 and $41,726  during the years ended  December 31,  2004,  2003 and 2002,
respectively.

NOTE 15 - SELECTED QUARTERLY INFORMATION (Unaudited)

The following represents selected quarterly financial  information for the years
ended December 31, 2004 and 2003.
<TABLE>
<CAPTION>

            2004                                                  For the Quarter Ended
                                 ----------------------------------------------------------------------------------------
                                       March 31,           June 30,              September 30,            December 31,

<S>                                     <C>               <C>                       <C>                     <C>
Gross revenue                           $751,518          $ 777,155                 $ 817,325               $921,216
Net revenue from oil and
gas operations                           590,450            521,411                   638,084                611,552
Net loss                               (544,086)           (720,981)                 (540,411)            (2,400,352) a
Net loss per share
  basic and diluted                       (0.01)             (0.01)                    (0.01)                 (0.04)
</TABLE>

a - The increase in the Company's net loss during the fourth quarter as compared
with the previous  quarters is primarily due to the additional  interest expense
related to the  conversion of the  Debentures  of  approximately  $555,000,  the
interest expense accrued on the Notes during the fourth quarter of approximately
$700,000 and the increased  amortization  expense  related to the offering costs
related to the issuance of the Notes of  approximately  $115,000.  The remaining
increase is due to higher general and administrative  costs due to the increased
operational activity and increased depletion expense resulting from the increase
in the number of producing wells.
<TABLE>
<CAPTION>

             2003                                                 For the Quarter Ended
                                     ---------------------------------------------------------------------------------
                                         March 31,           June 30,         September 30,          December 31,

<S>                                      <C>               <C>             <C>                          <C>
Gross revenue                            $158,850          $499,527        $     277,101                $327,965
Net revenue from oil
  and gas operations                       92,402             389,091               173,017              271,655
Net loss                             (747,465)              (508,492)             (634,209)            (636,359)
Net loss per share
  basic and diluted                        (0.02)              (0.02)                (0.02)               (0.01)
</TABLE>

NOTE 16 - LITIGATION

On June 9, 2003, Pannonian Energy Inc. ("Pannonian"),  a wholly-owned subsidiary
of the Company was named as a defendant in a lawsuit  filed in the United States
District Court of Midland County,  Texas. On July 15, 2003, Gasco was also named
as defendant in the same lawsuit. The plaintiffs, Burlington Resources Oil & Gas
Company LP by BROG GP Inc. its sole  General  Partner  ("Burlington  Resources")
claimed that Pannonian and Gasco owed them $1,007,894 in unpaid invoices. During
March 2004,  the Company  repaid  $900,723 of this liability and during July the
Company made a final payment of $100,000 in settlement of this matter. Orders to
dismiss both cases with prejudice were filed on July 10, 2004.

                                       72
<PAGE>

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

The  following  reserve  quantity and future net cash flow  information  for the
Company represents proved reserves located in the United States. The reserves as
of December  31, 2004 and 2003 have been  estimated  by  Netherland,  Sewell and
Associates,  Inc., independent petroleum engineers.  The reserves as of December
31, 2002 were estimated by James R. Stell,  independent petroleum engineer.  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, 2004 and 2003 were $42.25 per bbl of
oil and $5.56  per Mcf of gas and  $29.69  per bbl of oil,  and $5.89 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.  No  consideration  has
been  given to future  income  taxes as of  December  31,  2004,  2003 and 2002,
because  the tax  basis  of the  Company's  properties  and net  operating  loss
carryforwards exceed future net cash flows in each of the years presented.

Reserve Quantities
                                              Gas                     Oil
                                              Mcf                     Bbls
Proved Reserves:
      Balance, December 31, 2002             20,622,266              141,652
       Extensions and discoveries             4,446,547               36,288
       Revisions of previous estimates (a)   (9,752,505)             (66,455)
       Sales of reserves in place            (1,458,270)              (8,500)
       Purchases of reserves in place                --                   --
       Production                              (257,035)              (1,998)
                                             -----------             --------

      Balance, December 31, 2003             13,601,003               100,987
       Extensions and discoveries             26,788,308              168,451
       Revisions of previous estimates (b)   (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
                                              ==========             ========

Proved Developed Reserves
      Balance, December 31, 2004              3,916,089                39,103
                                            ===========            ==========
      Balance, December 31, 2003              2,937,388                24,818
                                            ===========            ==========
      Balance, December 31, 2002              5,889,981                34,493
                                            ===========            ==========

                                       73
<PAGE>

(a)      The revisions of previous  estimates during 2003 was due primarily to a
         failed re-completion on one of the Company's wells, which resulted in a
         reduction  in the  reserves  associated  with  the  producing  wellbore
         location  and the loss of the  surrounding  proved  undeveloped  offset
         locations.
(b)      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.

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

                                                              December 31,
                                                 --------------------- --------------------
                                               2004                2003                 2002
                                               ----                ----                 ----

<S>                                           <C>                <C>             <C>
Future cash flows                             $ 231,958,400      $  83,099,200   $   73,763,406
Future production and development costs       (123,579,100)        (32,804,600)     (38,958,416)
                                              -------------       -------------  ---------------
Future net cash flows before discount           108,379,300         50,294,600       34,804,990
                                                -----------      -------------   ---------------
10% discount to present value                  (76,077,700)       (34,099,500)     (22,492,988)
                                               ------------       -------------  ---------------
Standardized measure of discounted
  future net cash flows                        $ 32,301,600        $16,195,100  $   12,312,002
                                               ============        ===========  ===============
</TABLE>


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

                                                                               For the Years Ended December 31,
                                                                             ---------------------- --------------------
                                                                             2004                   2003                 2002
                                                                             ----                   ----                 ----
Standardized measure of discounted future net
<S>                                                                       <C>          <C>                                <C>
   cash flows at the beginning of year                                    $16,195,100  $          12,312,002              $     -
Sales of oil and gas produced, net of production
   Costs                                                                  (2,485,621)              (926,165)             (44,699)
Net changes in prices and production costs                                (4,045,575)             13,209,650                    -
Extensions and discoveries, net of future
   production and development costs                                        34,439,255              7,250,499           21,007,459
Development costs incurred                                                 17,499,346              4,218,902            7,319,184
Changes in estimated future development costs                            (62,687,146)              1,890,021         (31,717,307)
Revisions of previous quantity estimates                                  (1,055,871)            (2,629,973)                    -
Purchases of reserves in place                                              1,654,068                      -                    -
Sales of reserves in place                                                  (623,985)              (391,020)                    -
Accretion of discount                                                       1,619,510              1,231,200                    -
Changes in production rates and other
                                                                           31,792,519           (19,970,016)           15,747,365
                                                                           ----------           ------------           ----------
Standardized measure of discounted future net cash flows at
   the end of year                                                      $ 32,301,600             $16,195,100          $12,312,002
                                                                        =============            ===========          ===========

</TABLE>



                                       74
<PAGE>



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

During the third quarter of 2004, the Company's Audit Committee, certain members
of  management  and  Deloitte & Touche LLP  ("Deloitte"),  the  Company's  prior
independent  registered public accounting firm,  engaged in several  discussions
regarding whether Deloitte would continue to provide audit services to us. These
discussions focused partly on Deloitte's increased staffing  requirements for us
and many of Deloitte's other clients, due in part to additional  requirements of
Rule 404 under the Securities  Exchange Act of 1934 and other rules  promulgated
under the Sarbanes-Oxley Act. Deloitte indicated that it had to make a choice in
the deployment of its resources.  On September 8, 2004, Deloitte resigned as the
Company's independent  registered public accounting firm. On September 14, 2004,
our Audit  Committee  engaged  Hein & Associates  LLP to serve as the  Company's
independent public accountants for the fiscal year 2004. The Audit Committee has
decided to continue to retain Deloitte to advise the Company with respect to tax
matters.  During Gasco's two most recent fiscal years and the subsequent interim
period through  September 8, 2004, there were no disagreements  with Deloitte on
any  matter  of  accounting   principles  or  practices,   financial   statement
disclosure, or auditing scope or procedure, which disagreements, if not resolved
to  Deloitte's  satisfaction,  would  have  caused it to make  reference  to the
subject  matter of the  disagreements  in connection  with its report on Gasco's
consolidated  financial statements for such years; and during such period, there
were  no  "reportable  events"  of the  kind  listed  in  Item  304(a)(1)(v)  of
Regulation S-K.

ITEM 9A - CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

The  Company  carried  out an  evaluation,  under the  supervision  and with the
participation  of  the  Company's  management,  including  the  Company's  Chief
Executive  Officer and Chief  Financial  Officer,  of the  effectiveness  of the
design and operation of the Company's  disclosure  controls and procedures as of
December 31, 2004  pursuant to Rule 13a-15 under the  Exchange  Act.  Based upon
that  evaluation,  the Company's  Chief  Executive  Officer and Chief  Financial
Officer  concluded  that the Company's  disclosure  controls and  procedures are
effective.  Disclosure  controls and procedures are controls and procedures that
are  designed to ensure that  information  required to be  disclosed  in Company
reports  filed or  submitted  under the  Exchange  Act is  recorded,  processed,
summarized and reported within the time periods  specified in the Securities and
Exchange Commission's rules and forms.

There have been no changes in the  Company's  internal  control  over  financial
reporting  (as defined in Rule  13a-15(f)  under the Exchange Act) that occurred
during the  Company's  last fiscal  quarter that has  materially  affected or is
reasonably  likely to  materially  affect the  Company's  internal  control over
financial reporting.

Internal Control over Financial Reporting

We  became  an  accelerated  filer on June 30,  2004 as a result  of our  market
capitalization  exceeding $75 million on that date.  Because of our status as an


                                       75
<PAGE>

accelerated  filer,  we are  required  to  include  management's  opinion on the
internal  controls of the Company in our form 10-K for the year ending  December
31, 2004.  On November 30, 2004,  the SEC issued an exemption  order that allows
companies with less $700 million in market  capitalization  as of June 30, 2004,
an additional  45 days to file  management's  annual report on internal  control
over  financial  reporting and the related  attestation  report of the Company's
registered public accounting firm.

Many  companies had 18 months  advance  notice from the time that the rules were
announced until the date of required compliance.  Because of the increase in our
market  capitalization  during  the  first  half of 2004,  we did not  become an
accelerated  filer until nine months prior to the compliance date.  Further,  we
were forced to find a new accounting firm during this period when our registered
public accounting firm informed us in September 2004 that they would not perform
the 2004 audit.  As a result our  evaluation  and our  auditor's  testing of the
internal controls are not complete.

The management of the Company is responsible  for  establishing  and maintaining
adequate  internal control over financial  reporting for the Company.  We are in
the process of evaluating the  effectiveness  of the Company's  internal control
over  financial  reporting,  however for the reasons set forth above we have not
completed our  assessment as of the date of this annual  report.  As of the date
hereof,  we have not  identified any errors or  irregularities  in our financial
reporting.

Through our  evaluation  to date,  we have  identified  the  following  material
weaknesses in our internal control systems:

     1.   Insufficient  segregation  of duties with respect to the review of the
          bank  reconciliation of an account used for general and administrative
          expenses and the review of certain other general  corporate  accounts,
          such as prepaid and other assets.

     2.   Insufficient  documentation with respect to the review of non-standard
          journal entries.

     3.   Insufficient documentation of our quarterly closing procedures.

     4.   Insufficient  documentation of the controls with respect to the output
          of transactions  recorded by our outsourced  accounting  function with
          respect to the revenue and joint interest billing processes.

Additional  material  weaknesses may be uncovered as we complete our evaluation.
We have  already  initiated  changes to our control  systems to  mitigate  these
weaknesses for 2005.

We  anticipate  no  difficulty  in  completing  our  evaluation  of the internal
controls  within the 45 day  period  following  March 16,  2005 and will file an
amended  10-K that will  include  management's  report on internal  control over
financial  reporting  required by Item 308(a) of Regulation S-K, and the related
attestation  report of the registered  public  accounting  firm required by Item
308(b) of Regulation S-K.

ITEM 9B - OTHER INFORMATION



                                       76
<PAGE>

None.

PART III

ITEM 10 - DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2005 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 2005 Annual Meeting of Shareholders
to be filed with the SEC  pursuant  to  Regulation  14A,  which  information  is
incorporated herein by reference.

ITEM 12 - SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                       MANAGEMENT

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2005 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

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2005 Annual Meeting of Shareholders
to be filed with the SEC  pursuant  to  Regulation  14A,  which  information  is
incorporated herein by reference.

ITEM 14 - PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information  required by this item will be included in the definitive  proxy
statement of Gasco relating to the Company's 2005 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 AND REPORTS ON FORM 8-K

     (a)  1. See "Index to Financial Statements" under Item 8 on page 42.
          2. Financial Statement Schedules - none.
          3. Exhibits

                                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).



                                       77
<PAGE>




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).

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).

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).

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).

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).

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.

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).

3.3  Amended and Restated  Bylaws  (incorporated  by reference to Exhibit 3.4 to
     the Company's Form 10-Q for the quarter ended March 31, 2002,  filed on May
     15, 2002).

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, 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  November  15,  2002,  filed on November 15,
     2002).

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).

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).



                                       78
<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).

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).

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).

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).

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).

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).

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).

#10.11999 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).

#10.2Form  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).

#10.3Stock 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).

#10.4Form 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).

#10.5W. King Grant Amended and Restated  Employment  Contract dated February 14,
     2003 (Filed as Exhibit 10.10 to the Company's Form 10-K for the fiscal year
     ended December 31, 2002, filed on March 29, 2003).

#10.6Michael 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).

#10.7Mark 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).

#10.8Amended 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).

                                       79
<PAGE>

#10.92003  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).

10.10Muddy 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).

10.11CD 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).

10.12Gamma 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).

10.13Sublette  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).

10.14Lead  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).

10.15Property  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).

10.16Purchase  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).

10.17Amendment 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).

10.18Financial  Advisory Services  Agreement dated August 22, 2002,  between the
     Company and Energy Capital  Solutions  LLC.  (Filed as Exhibit 10.21 to the
     Company's Form S-1 Registration Statement, filed on November 15, 2002).

10.19Termination 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  October  20,
     2004).

21   List of  Subsidiaries  (Filed as Exhibit 21 to the Company's  Form 10-K for
     the year ended December 31, 2003, filed on March 26, 2004).

*23.1 Consent of Deloitte & Touche, LLP

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

*23.3 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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<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:  March 15, 2005



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>
<CAPTION>


             Signature                                           Title                                       Date

<S>                                  <C>                                                                <C>
/s/ Mark A. Erickson                 Director and President and Chief Executive Officer                 March 15, 2005
--------------------
Mark A. Erickson

/s/ Marc A. Bruner                   Director                                                           March 15, 2005
---------------------
Marc A. Bruner

/s/ Carl Stadelhofer                 Director                                                           March 15, 2005
--------------------
Carl Stadelhofer

/s/ W. King Grant                    Executive Vice President and Chief Financial Officer               March 15, 2005
-----------------
W. King Grant                        (Principal Financial Officer and Principal Accounting
                                     Officer)

/s/ Carmen Lotito                    Director                                                           March 15, 2005
-----------------
Carmen ("Tony") Lotito

/s/ Charles B. Crowell               Director                                                           March 15, 2005
----------------------
Charles B. Crowell

/s/ Richard S. Langdon               Director                                                           March 15, 2005
----------------------
Richard S. Langdon

/s/ R. J. Burgess                    Director                                                           March 15, 2005
---------------------
R.J. Burgess

/s/ John A. Schmit                   Director                                                           March 15, 2005
------------------
John A. Schmit

</TABLE>


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<PAGE>