April 4, 2007

United States Securities and Exchange Commission
100 F Street, N.E.
Washington, D.C. 20549-7010
Attention: Mr. Gary Newberry
Fax: (202) 772-9368

Re: Gasco Energy, Inc.
Form 10-K for the fiscal year ended December 31, 2006 File No.
001-32369

Ladies and Gentlemen:

Set forth below are the responses of Gasco Energy, Inc. (the "Company")
to the comments of the staff of the Securities and Exchange Commission (the
"Staff") in the comment letter of the Staff dated April 2, 2007 addressed to the
Company. For your convenience, the comments provided by the Staff have been
included before the response in the order presented in the comment letter.

Form 10-K for the Fiscal Year Ended December 31, 2006

General

1. In the review of your filing for Fiscal Year 2006, we noted your April
29, 2005 supplemental response to our April 20, 2005 comment letter
regarding the review of your Form 10-K for the Fiscal Year 2004. In
this response, you stated you would comply with comments 1, 2, 9 and 12
in future filings. Please tell us how you have complied with each of
these prior comments in the Form 10-K for the Fiscal Year Ended
December 31, 2006, or amend this filing to comply with these prior
comments.

RESPONSE: For your convenience the original comments have been provided with the
description of how we complied with each comment.

Comment 1. In your discussion regarding the value of future net cash flows from
reserves, we note you state that "we generally base the estimated discounted
future net cash flows from proved reserves on prices and costs on the date of
the estimate." Please explain to us why you use the term generally, which seems
to imply that you have used other methods of determining the estimated value of
proved reserves. If so, please explain to us what methods you have used.

We have not used any other methods of determining our estimated value of proved
reserves and deleted the word generally from this discussion in the 2006 10-Q's,
however, this change was inadvertently omitted from the 2006 10-K. We will
correct this omission in the amended filing. See attached amended page 16.

Comment 2. In your document, please include the definition of proved reserves as
defined in Regulation S-X Rule 4-10(a) and P. 34 of FAS 25.

We included a glossary of oil and gas terms in the 2006 10-Q's however the
glossary was inadvertently omitted from the 2006 10-K. We will include a
glossary of oil and gas terms which includes the definition of proved reserves
set forth in Regulation S-X Rule 4-10(a). See attached amended pages 9 through
12.

Comment 9. We note that you state the costs of unproved properties are withheld
from the depletion base until they are either developed or abandoned. This does
not appear to be consistent with Rule 4-10(c) (3) (ii) which states that these
costs are excluded from the depreciation base "until it is determined whether or
not proved reserves can be assigned to the properties." Please clarify to us and
in your disclosure when such costs are transferred to the amortization base.

The Company withholds costs of unproved properties from the depletion base until
it is determined whether or not proved reserves can be assigned from the
properties. This change was made in all of the 2006 10-Q's however it was
inadvertently omitted from the 2006 10-K. This change will be made in the
amended filing. See attached amended pages 46 and 61.

Comment 12. Please expand your disclosure to include information specific to
your company, including when title transfers to the buyer, and industry specific
information including how the company accounts for imbalances. Please ensure
your revenue recognition disclosures are consistent with SAB Topic 13 B
requirements and EITF 90-22.

We will add the following additional disclosure to the Revenue Recognition
section of Note 2 - Significant Accounting Policies.

The Company records revenues from the sales of natural gas and crude oil when
delivery to the customer has occurred and title has transferred. This occurs
when oil or gas has been delivered to a pipeline or a tank lifting has occurred.
This change was made in all of the 2006 10-Q's however it was inadvertently
omitted from the 2006 10-K. This change will be made in the amended filing. See
attached amended page 64.

Notes to Consolidated Financial Statements

Note 2 - Significant Accounting Policies

Oil and Gas Properties, page 57

2. You have disclosed that your full cost pool was not impaired as of
December 31, 2006, based on increased oil and gas prices subsequent to
year end. Tell us what date was selected for the ceiling recomputation
and why this date bears a logical relationship to the filing date of
the affected financial statements. Also, tell us whether or not the
date selected is consistent from period to period. We may have further
comment.

RESPONSE: The Company consistently performs a second ceiling test using oil and
natural gas prices on the date that is seven days before we plan to file our
Form 10-K or Form 10-Q's with the SEC. We believe that this date bears a logical
relationship to the filing date of the affected financial statements because it
allows us to recomputed our ceiling test in circumstances in which oil and
natural gas prices have increased subsequent to period end, using the most
current date possible, but also allows sufficient time to make any necessary
revisions to our financial statements before the filing date. This year, we
performed a second ceiling test using prices on February 21, 2007, and filed our
Form 10-K on February 28, 2007.

Engineering Comments

Risk Factors, page 9

The volatility of oil and gas prices could have a material adverse effect on our
business, page 9
- --------------------------------------------------------------------------------

3. Risk factors should be as specific to you as possible. Please revise to
include the price of gas at year end 2006 compared to the previous
period and that this resulted in a downward revision in your proved
reserves of 63%. Also report, if true, that unless the price increases
you will be unable to economically develop most of your acreage, unless
costs also decline materially.

RESPONSE: The volatility of natural gas and oil prices could have a material
adverse effect on our business risk factor has been amended to disclose the oil
and gas prices at year end 2006 compared to the previous period and that this
decrease resulted in a downward revision in our proved reserves of 63%, and that
unless commodity prices increase or unless costs decline materially, we will be
unable to economically develop most of our acreage. See amended pages 13 through
14.

Our oil and gas reserve information is estimated, page 11

4. Please revise to include in this risk factor that you have revised your
reserves downward by 36%, 32% and 63% in each of the last three years.

RESPONSE: The risk factor Our oil and gas reserve information is estimated and
may not reflect our actual reserves, has been revised to add that we have
revised our reserves downward by 36%, 32% and 63% in each of the last three
years. See amended page 15.

Our officers and directors are engaged in other businesses, page 18

5. Please revise to include the percentage of each time person spends on company
business.

RESPONSE: The percentage of time each person spends on Company business has been
added to the Our officers and directors are engaged in other businesses which
may result in conflicts of interest risk factor. See amended page 22.

Management's Discussion and Analysis of Financial Condition and Results of
Operations, page 31
- --------------------------------------------------------------------------------

6. Revise to expand your disclosure on how the current gas price will
affect your 2007 development plans and the fact that most of your
previously booked proved undeveloped reserves are uneconomic at the
2006 end of year gas price.

RESPONSE: The disclosure under Management's Discussion and Analysis of Financial
Condition and Results of Operations has been revised to disclose how the current
gas price will affect our 2007 development plans and the fact that most of our
previously booked proved undeveloped reserves are uneconomic at the 2006 end of
year gas price. See amended pages 35 through 36.

Critical Accounting Policies and Estimates, page 39

Oil and Gas Reserves, page 40

7. Please expand your disclosure to include the SEC definition of proved
reserves as found in Rule 4-10(a) of Regulation S-X.

RESPONSE: We have added a glossary of terms that includes the definition of
proved reserves set forth in Rule 4-10(a). See amended pages 9 through 12.

Notes to Consolidated Financial Statements, page 55

Supplemental Oil and Gas Reserve Information, page 88

8. We note that you reported very few proved undeveloped reserves. Tell us
why you believe you do not have proved undeveloped reserves directly
offsetting more of the 97 wells you have an interest in. Reconcile the
fact that you report very few proved undeveloped reserves with the fact
that you currently have three rigs under contract in the Uinta Basin
and will take delivery on a fourth rig at the end of March 2007 and
have budgeted $40 million in capital expenditures in 2007 which include
the drilling of ten wells in your Riverbend project.

RESPONSE: Gasco has little proved undeveloped reserves because the offsetting
locations did not yield a positive net present value at a discount rate of 10%
at year end 2006 prices of natural gas and oil, the current estimated capital
investment based on recent historical data to drill and complete wells and the
current estimated well performance based on historical well performance in this
area.

In 2007, we plan to continue to prove the geological model, delineate the
resource and demonstrate additional operational efficiencies. Long term the
Company believes that it will be able to demonstrate reduced well investment
through operating efficiencies gained through improved drilling and completion
practices, introduction of new technologies and economies of scale. The Company
believes that well performance is likely to improve as knowledge increases with

additional well development and introduction of new technologies. Historically,
during periods of lower prices of natural gas and oil well investment has been
much lower and the Company believes that any prolonged period of prices similar
to those seen at year end 2006 would result in significantly lower well
investment in the future. However, the Company believes that commodity prices
reflected at the year end 2006 are not representative of the long term price for
natural gas and oil.

In connection with responding to comments from the Staff addressed to the
Company on April 2, 2007, the Company hereby acknowledges that:

- the Company is responsible for the adequacy and accuracy of the
disclosure in its filings with the Securities and Exchange Commission
(the "Commission");

- Staff comments or changes to disclosure in response to Staff comments
do not foreclose the Commission from taking any action with respect to
the filing and;

- the Company may not assert Staff comments as a defense in any
proceeding initiated by the Commission or any person under the federal
securities laws of the United States.

If you have any questions or comments, please call me at (303) 483-0044.

Sincerely,

/s/ W. King Grant

W. King Grant
Chief Financial Officer and
Executive Vice President

AMENDED PAGES TO FORM 10-K:

our ability to find and retain skilled personnel;

the lack of liquidity of our common stock; and

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

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

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

GLOSSARY OF NATURAL GAS AND OIL TERMS

The following is a description of the meanings of some of the natural
gas and oil industry terms used in this annual report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in
this annual report in reference to crude oil or other liquid hydrocarbons.

Bbl/d. One Bbl per day.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

Completion. The installation of permanent equipment for the production
of natural gas or oil, or in the case of a dry hole, the reporting of
abandonment to the appropriate agency.

Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.

Developed acreage. The number of acres that are allocated or assignable
to productive wells or wells capable of production.

Development well. A well drilled within the proved area of an oil or
gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production exceed
production expenses and taxes.

Exploratory well. A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field previously
found to be productive of natural gas or oil in another reservoir or to extend a
known reservoir. Generally, an exploratory well is any well that is not a
development well, a service well, or a stratigraphic test well.

Farm-in or farm-out. An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."

Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may
be, in which a working interest is owned.

Lead. A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

Mcf. Thousand cubic feet of natural gas.

Mcfe. Thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

MMBls. Million barrels of crude oil or other liquid hydrocarbons.

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

MMcf/d. One MMcf per day.

MMcfe. Million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interest
owned in gross acres or wells, as the case may be.

Net feet of pay. The true vertical thickness of reservoir rock estimated
to both contain hydrocarbons and be capable of contributing to producing rates.

Present value of future net revenues or present value of discounted
future net cash flows or present value or PV-10. The pretax present value of
estimated future revenues to be generated from the production of proved reserves
calculated in accordance with SEC guidelines, net of estimated production and
future development costs, using prices and costs as of the date of estimation
without future escalation, without giving effect to non-property related
expenses such as general and administrative expenses, debt service and
depreciation, depletion and amortization, and discounted using an annual
discount rate of 10%.

Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of the
production exceed production expenses and taxes.

Prospect. A specific geographic area which, based on supporting
geological, geophysical or other data and also preliminary economic analysis
using reasonably anticipated prices and costs, is deemed to have potential for
the discovery of commercial hydrocarbons.

Proved area. The part of a property to which proved reserves have been
specifically attributed.

Proved developed oil and gas reserves. Reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production responses that
increased recovery will be achieved.

Proved oil and gas reserves. The estimated quantities of crude oil, natural
gas and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Reservoirs are considered proved if
economic producibility is supported by either actual production or conclusive
formation test. The area of a reservoir considered proved includes (a) that
portion delineated by drilling and defined by gas-oil and/or oil-water contacts,
if any, and (b) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of information on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir. Reserves which can be produced economically
through application of improved recovery techniques (such as fluid injection)
are included in the "proved" classification when successful testing by a pilot
project, or the operation of an installed program in the reservoir, provides
support for the engineering analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (a) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (b) crude oil, natural gas and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics or economic factors; (c)
crude oil, natural gas and natural gas liquids that may occur in undrilled
prospects;

and (d) crude oil, natural gas and natural gas liquids that may be
recovered from oil shales, coal, gilsonite and other such sources.

Proved properties. Properties with proved reserves.

Proved undeveloped reserves. Reserves that are expected to be recovered
from new wells on undrilled acreage or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units can be claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Proved undeveloped reserves may not include estimates attributable to any
acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir.

Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.

Service well. A well drilled or completed for the purpose of supporting
production in an existing field. Specific purposes of service wells include gas
injection, water injection, steam injection, air injection, salt-water disposal,
water supply for injection, observation, or injection for in-situ combustion.

Stratigraphic test well. A drilling effort, geologically directed, to
obtain information pertaining to a specific geologic condition. Such wells
customarily arc drilled without the intention of being completed for hydrocarbon
production. This classification also includes tests identified as core tests and
all types of expendable holes related to hydrocarbon exploration. Stratigraphic
test wells are classified as (a) "exploratory type," if not drilled in a proved
area, or (b) "development type," if drilled in a proved area.

Undeveloped acreage. Lease acreage on which wells have not been drilled
or completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether such acreage contains
proved reserves.

Unproved properties. Properties with no proved reserves.

Working interest. The operating interest that gives the owner the right
to drill, produce and conduct operating activities on the property and receive a
share of production.

ITEM 1A. Risk Factors

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

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

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

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

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

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

o commodity processing, gathering and transportation availability;

o domestic and global political and economic conditions;

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

o weather conditions, including hurricanes;

o technological advances affecting energy consumption;

o domestic and foreign governmental regulations; and

o the price and availability of alternative fuels.
Lower natural gas and oil prices may not only decrease our revenue on a per
share basis, but also may reduce the amount of natural gas and oil that we can
produce economically. This reduction may result in our having to make
substantial downward adjustments to our estimated proved reserves. For example,
during 2006, the previous oil and gas reserves quantities decreased by
approximately 63% primarily due to the decrease in oil and gas prices from
$59.87 per barrel and

$8.01 per mcf at December 31, 2005 to $45.53 per barrel and $4.47 per mcf at
December 31, 2006. The price per barrel of oil reflects our blend of oil and
condensate. If the estimated capital investment based on recent historical data
to drill and complete wells in this area is not reduced materially or if the
prices for oil and gas do not increase materially from year end 2006 prices we
will be unable to economically develop most of our acreage.

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

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

seasonal fluctuations in local demand for production;

local and national gas storage capacity;

interstate pipeline capacity; and

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 would materially and adversely affect our future business, financial
condition, results of operations, liquidity and ability to finance planned
capital expenditures. Further, oil prices and natural gas prices do not
necessarily move together.

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

Gasco's production is transported through a single intrastate pipeline and
therefore any constraints on the capacity of this pipeline could adversely
affect our ability to sell our production. Additionally, many pipelines,
particularly those connecting to higher - priced eastern markets, are operating
at or near capacity. Management believes that this situation could continue, at
least, into early 2008. In certain circumstances this may limit our ability to
sell any,

or all, of our natural gas production in a given period. As producers vie one
with another to sell their gas, this situation may also serve to reduce the
price at which we are able to sell the gas that does flow. A reduction in the
amount of natural gas that we can sell or the price at which such natural gas
can be sold could materially adversely affect our financial position and results
of operation.

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

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

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

The most accurate method of determining proved reserve estimates is based upon a
decline analysis method, which consists of extrapolating future reservoir
pressure and production from historical pressure decline and production data.
The accuracy of the decline analysis method generally increases with the length
of the production history. Since most of our wells had been producing less than
six years as of December 31, 2006, their production history was relatively
short, so other (generally less accurate) methods such as volumetric analysis
and analogy to the production history of wells of other operators in the same
reservoir were used in conjunction with the decline analysis method to determine
our estimates of proved reserves. As our wells are produced over time and more
data is available, the estimated proved reserves will be redetermined on an
annual basis and may be adjusted based on that data. These adjustments could
result in downward revisions of our reserve estimates. We have revised our
reserves downward by 36%, 32% and 63% in each of the previous three years.

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 base the estimated discounted future net cash flows from proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may be materially higher or lower than the prices and costs as of the
date of the estimate.

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

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

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

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

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

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

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

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

conditions. These restrictions could also limit our ability to obtain future
financings, make needed capital expenditures, withstand a downturn in our
business or the economy in general, or otherwise conduct necessary corporate
activities. Our credit facility and restrictions there under are described in
greater detail in "Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations - Credit Facility."

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

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

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

Certain of our officers and directors also serve as directors of other companies
or have significant shareholdings in other companies. Our chairman, Marc A.
Bruner, is the largest shareholder of Galaxy Energy Corporation ("Galaxy") and
Exxcel Energy. Mr. Bruner also serves as the Chairman and Chief Operating
Officer of Falcon Oil and Gas, Ltd. ("Falcon"). Falcon's current drilling
activities include projects in Romania and Hungary. Carl Stadelhofer, one of our
directors is a director of Falcon. In addition, another of our directors, C.
Tony Lotito, currently serves as the Executive Vice President, Chief Financial
Officer, Secretary-Treasurer and a member of the Board of Directors of
PetroHunter Corporation ("PetroHunter"), which is majority owned by Mr. Bruner.
Charles Crowell, one of our directors also serves on the Boards' of Directors of
PetroHunter and of Providence Resources, Inc. Richard S. Langdon, another one of
our directors, is President and Chief Executive Officer of Matris Exploration
Company, L.P., a private E&P company active in onshore California. Mr. Langdon
is also a member of the Board of Directors of Constellation Energy Partners LLC
("CEP"), a public limited liability company focused on the acquisition,
development and exploitation of oil and natural gas properties and related
midstream assets. CEP's activities are currently focused in the Black Warrior
Basin of Alabama. Another one of our directors, Richard Burgess is a director of
ROC Oil Company ("ROC"), a Limited Liability Corporation incorporated in
Australia. ROC has oil and gas activities in China, Australia, UK North Sea, and
West Africa. ROC has no activities in North or South America. The Company
estimates that all of its directors except Mr. Crowell spend approximately 10%
of their time on Company business and Mr. Crowell spends approximately 25% of
his time on Company business. Mark Erickson, our CEO, President and director has
direct private investments in certain Rocky Mountain oil and gas leases and has
a majority interest in a private oil and gas company with core assets in
Oklahoma and additional lease holdings in Colorado, Wyoming and Utah. Mr.
Erickson spends 100% of his time on Gasco business.

ITEM 6 - SELECTED FINANCIAL DATA

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

For the Year Ended December 31,
2006 2005 2004 2003 2002
---- ---- ---- ---- ----
Summary of Operations

Oil, gas and gathering revenue $22,980,231 $15,479,566 $3,267,214 $1,263,443 $ 164,508
General & administrative expense 9,415,787 5,987,019 4,191,978 2,819,675 5,080,287
Net loss (55,817,767) (37,635) (4,205,830) (2,526,525) (5,649,682)
Net loss per share (0.65) (0.00) (0.07) (0.07) (0.16)

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

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

Forward Looking Statements

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

Overview

Gasco is a natural gas and petroleum exploitation, development and production
company engaged in locating and developing hydrocarbon prospects, primarily in
the Rocky Mountain region. The Company's business strategy is to enhance
shareholder value by using technologies new to a specific area to generate and
develop high-potential exploitation resources in this area. The Company's
principal business is the acquisition of leasehold interests in petroleum and
natural gas rights, either directly or indirectly, and the exploitation and
development of properties subject to those leases. Gasco's preliminary budget
for our 2007 capital program reflects Gasco's commitment to build upon its
historical successes and continue its efforts to

demonstrate the economic viability of its resource in the Uinta Basin of Utah.
Economic viability of this resource play is a function of the price of natural
gas and oil, well investment, well operating cost and well performance. If the
estimated capital investment based on recent historical data to drill and
complete wells in this area is not reduced materially, if the estimated well
performance based on recent historical performance data in this area is not
increased materially or if the prices for oil and gas do not increase materially
from year end 2006 prices we will be unable to economically develop most of our
acreage in the Uinta Basin of Utah.

Gasco's preliminary budget for our 2007 capital program is not contingent upon
any material increases in the prices of oil and gas reflected at year end 2006.
In 2007, we plan to continue to prove the geological model, delineate the
resource and demonstrate additional operational efficiencies. During 2007 the
Company believes, based on historical experience in 2006, that it will be able
to demonstrate reduced well investment through operating efficiencies gained
through improved drilling and completion practices, introduction of new
technologies and economies of scale. In the last half of 2006 we experienced
reduced well investment due to reduced drilling days and lower service costs. We
believe well performance is likely to improve as knowledge increases with
additional well development and introduction of new technologies. Historically,
during periods of lower prices of natural gas and oil well investment has been
much lower and the Company believes that any prolonged period of prices similar
to those seen at year end 2006 would result in significantly lower well
investment in the future. However, the Company believes that commodity prices
reflected at the year end 2006 are not representative of the long term price for
natural gas and oil.

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

Recent Developments

Drilling Activity

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

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

Stock Based Compensation

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

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

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 it is determined whether or not proved reserves can be
assigned to the properties. The properties are reviewed quarterly for
impairment. During 2006, approximately $3,786,000 of unproved lease costs
related to expiring acreage in Wyoming was reclassified to proved property and
was included in the ceiling test and depletion calculations.

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

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

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

Capitalized Interest

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

Off Balance Sheet Arrangements

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

Revenue Recognition

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

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

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