<DOCUMENT>
<TYPE>10KSB
<SEQUENCE>1
<FILENAME>s200110k.txt
<DESCRIPTION>12-31-01 10-KSB
<TEXT>
                            UNITED STATES
                 SECURITIES AND EXCHANGE COMMISSION
                      Washington, D. C.  20549

                             FORM 10-KSB

[x]  ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
     ACT OF 1934

     For the fiscal year ended December 31, 2001

[ ]  TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
     EXCHANGE ACT OF 1934

                    Commission file number: 0-14731

                       HALLADOR PETROLEUM COMPANY

          COLORADO                               84-1014610
  (State of incorporation)            (IRS Employer Identification No.)


   1660 Lincoln Street, Suite 2700, Denver, Colorado      80264-2701
      (Address of principal executive offices)            (Zip Code)

Issuer's telephone number: 303.839.5504            Fax: 303.832.3013

Securities registered under Section 12(b) of the Exchange Act:  NONE

Securities registered under Section 12(g) of the Exchange Act: Common
Stock,$.01 par value

Check whether the issuer (1) filed all reports required to be filed by
Section 13 or 15(d) of he Exchange Act during the past 12 months (or for
such shorter period that the registrant was required to file such
reports), and (2) has been subject to the 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-B is not contained in this form, and no
disclosure will be contained, to the best of registrant's knowledge, in
definitive proxy or information statements incorporated by reference in
Part III of this Form 10-KSB or any amendment to this Form 10-KSB. []

Our revenue for the year ended December 31, 2001 was about $8 million.

At March 29, 2002, we had 7,093,150 shares outstanding and the aggregate
market value of such shares held by non-affiliates was about $1.4
million based on a price of $1.80, which was the last reported trade on
that date.


DOCUMENTS INCORPORATED BY REFERENCE: NONE


ITEM 1.  DESCRIPTION OF BUSINESS

General Development of Business
-------------------------------

Hallador Petroleum Company, a Colorado corporation, was organized by our
predecessor in 1949.

About five years ago, Yorktown Energy Partners II and affiliates (Yorktown)
invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited
liability limited partnership.  We are the general partner and received a
70% interest in the partnership in return for contributing our net assets,
and Yorktown represents the limited partners and received a 30% interest
for its $5,025,000 cash contribution.  As general partner, we consolidate
the activity of the partnership and present the 30% limited partners'
interest as a minority interest.

We and our principal operating subsidiaries, Hallador Production Company and
Hallador Petroleum, LLP, are engaged in the exploration, development and
production of oil and natural gas.  Our principal and administrative offices
are located at 1660 Lincoln Street, Suite 2700, Denver, Colorado 80264,
phone 303.839.5504, fax 303.832.3013.  The South Cuyama field office is
located in New Cuyama, California.  We have no website.

86% of our oil and gas revenue is attributable to the South Cuyama field
(the "SC Field") located in Santa Barbara County, California, approximately
75 miles southwest from Bakersfield, California.  We own 92% of Santa
Barbara Partners (SBP), an Oklahoma general partnership, which has a 93%
working interest (78% net revenue interest) in the SC Field.  The
SC Field's oil reserves consist of light oil at 29 degree gravity.

We operate oil and natural gas properties for our own account and for the
account of others.  We also review and evaluate producing oil and natural
gas properties, companies, or other entities, which meet certain guidelines
for acquisition purposes.  In addition, we engage in the trading and
acquisition of non-producing oil and gas mineral leases and fee-simple
minerals.

Markets
-------

Our products are sold to various purchasers in the geographic area of the
properties.  Natural gas, after processing, is distributed through pipelines.
Oil and natural gas liquids (NGLs) are distributed through pipelines or
hauled by trucks.  The principal uses for oil and natural gas are heating,
manufacturing, power, and transportation.

At March 27, 2002, we were receiving $23.11 per barrel for our California
oil production, which is $1.24 more than the average price received during
2001 and $6.63 above the December 31, 2001 price.  The SC Field's oil is sold
to Pacific Marketing and Transportation LLC (an affiliate of Anschutz
Exploration Company), pursuant to a "spot market" contract, which can be
cancelled by either party with 30 days notice.  The contract pays a $.20 per
barrel premium to "spot market" postings.

The SC Field's natural gas is sold to Coral Energy (an affiliate of Shell
Oil Corporation), pursuant to a "spot market" contract, which can be
cancelled by either party with 30 days notice.

NGLs are sold to EOTT Energy Corp. pursuant to a "spot market" contract,
which can be cancelled by either party with 30 days notice.

Competition
-----------

The oil and gas industry is highly competitive.  We encounter competition
from major and independent oil companies in acquiring economically desirable
producing properties, drilling prospects, and even the equipment and labor
needed to drill, operate and maintain our properties.  Competition is intense
with respect to the acquisition of producing and partially developed
properties.  We compete with companies having financial resources and
technical staffs significantly larger than our own. We do not own any refining
or retail outlets and have minimal control over the prices of our products.
Generally, higher costs, fees and taxes assessed at the producer level cannot
be passed on to our customers.

We also face competition from imported products as well as alternative sources
of energy such as coal, nuclear, hydro-electric power, and a growing trend
toward solar. We could incur delays or curtailments of the purchase of our
available production.  We may also encounter increasing costs of production
and transportation while sale prices remain stable or decline.  Any of these
competitive factors could have an adverse effect on our operating results.

Environmental and Other Regulations
-----------------------------------

Our operations are affected in varying degrees by federal, state, regional and
local laws and regulations, including, but not limited to, laws governing
allowable rates of production, well spacing, air emissions, water discharges,
endangered species, marketing, prices and taxes.  We are further affected by
changes in such laws and by constantly changing administrative regulations.

Most natural gas pricing is presently deregulated and the remaining regulation
has no material impact on our prices.  We cannot predict the long-term impact
of future natural gas price regulation or deregulation.

We are subject to various federal, state, regional and local laws and
regulations relating to discharge of materials into, and protection of, the
environment.  These laws and regulations may, among other things, impose
liability on the owner or the lessee for the cost of pollution clean-up
resulting from operations, subject the owner or lessee to liability for
pollution damages, require suspension or cessation of operations in affected
areas or impose restrictions on injection into subsurface aquifers that may
contaminate groundwater.  Such regulation has increased the resources required
in, and costs associated with, planning, designing, drilling, installing,
operating and abandoning our oil and natural gas wells and other facilities.
We spend a significant amount of technical and managerial time to comply
with environmental regulations and permitting requirements.

We have and will continue to make expenditures to comply with these
requirements, which we believe are necessary business costs.  Although
environmental requirements do have a substantial impact upon the energy
industry, generally these requirements do not appear to affect us any
differently or to any greater or lesser extent than other companies in
California.

Although we are not fully insured against all environmental and other risks,
we maintain insurance coverage, which we believe, is customary in the
industry.

During 2001, we incurred about $94,000 to comply with these recurring
environmental regulations.  We estimate that such expenditures for 2002 and
for each year thereafter, in the foreseeable future, will approximate
$98,000.  We will continue to use our best efforts to comply with all
applicable environmental laws and regulations.  See Item 6 - Management's
Discussion and Analysis (MD&A) for a discussion regarding idle wells in
the SC Field.

To the extent these environmental expenditures reduce funds available for
increasing our reserves of oil and natural gas, future operations could
be adversely impacted.  Despite the fact that all of our competitors have
to comply with similar regulations, many are much larger and have greater
resources with which to deal with these regulations.

Other
-----

We have no significant patents, trademarks, licenses, franchises or
concessions.

The oil business is not generally seasonal in nature; although unusual
weather extremes for extended periods may increase or decrease demand.
Natural gas prices tend to increase in the fall and winter months and to
decrease in the spring and summer.

We have 29 employees; seven are located at our executive office in Denver
and 22 are located at the SC Field.  When needed we also engage consulting
petroleum engineers, environmental professionals, geologists, geophysicists,
landmen, accountants and attorneys on a fee basis.

ITEM 2.  DESCRIPTION OF PROPERTY

Location and General Character
------------------------------

Our primary operating areas consist of (i) the SC Field located 75 miles
southwest from Bakersfield, California, (ii) South Texas - Bonus located
about 70 miles southwest of Houston, and (iii) the San Juan Basin, located
in the northwest corner of New Mexico.  Revenue from the SC Field accounted
for 86% of 2001 oil, gas and NGL revenue, South Texas accounted for 2%, and
San Juan Basin accounted for 4%.

We hold our working interests in oil and natural gas properties either
through recordable assignments, leases, or contractual arrangements such as
operating agreements.  Consistent with industry practices, we do not make a
detailed examination of title when we acquire undeveloped acreage.  Title to
such properties is examined by legal counsel prior to commencement of
drilling operations.  This method of title examination is consistent with
industry practices.

In the acquisition and operation of oil and natural gas properties, burdens
such as royalty, overriding royalty, liens incident to operating agreements,
liens by taxing authorities, as well as other burdens and minor encumbrances
are customarily created. We believe that no such burdens materially affect
the value or use of our properties.

Proved Oil and Gas Reserves
---------------------------

Information concerning our reserve estimates is set forth in Note 6 to the
financial statements.  The reserve estimates were prepared by a sole-
proprietor consulting petroleum engineer.  All of our oil and gas reserves
are located onshore.

South Cuyama Field
------------------

Discovered in 1949 in the Cuyama Valley, Santa Barbara County, California,
the SC Field became the largest oil field found to date in the valley and
is located approximately 75 miles southwest from Bakersfield.  By 1951,
the SC Field contained 200 wells producing approximately 40,000 barrels of
oil per day.

Since inception, the SC Field is estimated to have produced over 222
million barrels of crude oil.  Current oil production to the 100% is about
1,013 barrels per day.  Currently, there are 64 producing wells.  The wells
produce from a depth range of 3,400 to 4,800 feet.

Sales and Price Data
--------------------

See Item 6 - MD&A

Producing Wells
---------------

As of March 29, 2002, we had a working interest in 60 gross (53 net)
oil wells and 32 gross (7 net) gas wells.


Leasehold Interests
-------------------

The following table sets forth our gross and net acres of undeveloped oil and
gas leases as of March 29, 2002:

<TABLE>
<CAPTION>

                                         Gross            Net
                                         -----           -----
          <S>                            <C>             <C>
          South Cuyama, California       4,813           3,821
          Sac Basin, California            432             130
          North Dakota                  45,535           7,469
          Texas                          6,374             734
          Utah                           5,777           5,777
          Wyoming                       66,343          54,077
                                       -------          ------
                                       129,274          72,008
                                       =======          ======
</TABLE>

We have an interest in 3,077 gross (2,707 net) developed acres in the
SC Field.

Drilling Activity
-----------------

From January 1, through March 29, 2002, there has been no drilling activity.

During 2001 we drilled one successful exploratory gas/oil well and one
development oil well in the SC Field.  Two unsuccessful development wells
were drilled in the SC Field.  We have an 88% WI in the SC Field.  One
exploratory dry hole was drilled in the Sac Basin of northern California
where we have a 30% WI.  One exploratory dry hole was drilled in the South
Texas - Alleyton prospect where we have a 14% WI.  Four successful
development wells were drilled in the South Texas - Bonus field where we have
a 5.5% WI. One successful exploratory gas well was drilled in South Texas -
McFarland prospect where we have a 25% WI and one marginally successful
exploratory gas well was drilled in East Texas where we have a 25% WI.

During 2000, we drilled one successful development oil well in the SC Field.
In the Sac Basin, we drilled two exploratory gas wells that were dry.  In
South Texas - Alleyton prospect we drilled an exploratory gas well which was
dry.  In the San Juan Basin, we drilled three successful development gas
wells where we have a 6% WI in such wells.  We also participated in one
exploratory oil well in Noble County, Oklahoma that was dry in which we had
a 10% WI.

ITEM 3.  LEGAL PROCEEDINGS: None

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS: None


                                  PART II

ITEM 5.  MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Our common stock is traded on the OTC Bulletin Board under the symbol
"HPCO".  The following table sets forth the high and low sales price
for the periods indicated:

<TABLE>
<CAPTION>
                                                     High         Low
                                                     ----        ----
       <S>                                           <C>         <C>
       2002
          First quarter (through March 29, 2002)     $1.80       $1.50

       2001
          First quarter                               4.19        1.75
          Second quarter                              5.00        4.25
          Third quarter                               4.25        4.25
          Fourth quarter                              4.00        1.75

        2000
          First quarter                               1.38         .66
          Second quarter                              3.75        1.38
          Third quarter                               3.00        2.38
          Fourth quarter                              2.50        2.06


</TABLE>

During the last two years no dividends were paid.  We have no present
intention to pay any dividends in the foreseeable future.

As of March 29, 2002 there were 413 holders of record of our common
stock and the last recorded sales price was $1.80.

ITEM 6.  MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF OPERATION

Overview
--------

Our financial statements should be read in conjunction with this discussion.
Our primary operating areas consist of (i) the South Cuyama field (SC Field)
located 75 miles southwest from Bakersfield, California, (ii) the South Texas
- Bonus field located about 70 miles southwest of Houston, and (iii) the San
Juan Basin, located in the northwest corner of New Mexico.  Due to its
significance, our value depends on the estimated future cash flows from the
SC Field.  We intend to maximize cash flow by continuing to increase oil and
gas production and keeping operating expenses low.  Future operations will
also be affected by the results of the development and exploration activity
discussed below.

About five years ago, Yorktown Energy Partners II and affiliates (Yorktown)
invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited
liability limited partnership.  We are the general partner and received a 70%
interest in the partnership in return for contributing our net assets and
Yorktown represents the limited partners and received a 30% interest for its
$5,025,000 cash contribution.  As general partner, we consolidate the activity
of the partnership and present the 30% limited partners' interest as a
minority interest.

Our profitability in any particular accounting period will be directly related
to:  (i) prices, (ii) production, (iii) lifting costs, and (iv) exploration
activities.  Accordingly, operating results will fluctuate from period to
period based on these factors, among others.

What follows is a discussion of our primary operating areas.

     South Cuyama Field
     ------------------

During October 2000, we completed a 3-D project on adjoining acreage east of
the South Cuyama field (SC Field). The cost of this project was $350,000 to
the 100%. We have a 70% WI in this project. The data was evaluated in January
2001 and several drillable prospects were identified.

The first exploratory gas well (the Cox 41-5) was drilled in March 2001.
Currently, the well is producing 500 MCF per day and 275 barrels per day
from a depth of about 3,400 feet.  We are the operator and own a 70% WI
(60% NRI). The cost to drill and complete this well was about $300,000 to
the 100%. This well is an important step in validating our 3-D seismic
project. We are reviewing our 3-D seismic data to identify other locations
to drill. With the high gas prices we received during the second quarter,
the revenue from the Cox 41-5 recovered our drilling and seismic costs
($650,000) in less than two months.  Because of the California electricity
crisis natural gas prices were abnormally high during the first six months
of the year. During the second quarter we were selling the gas for as high
as $16 per MCF. Currently, the prices are around $3.

We estimate the 100% reserves for the current producing zone for this well to
be about 500,000 MCF and the oil reserves to be about 235,000 barrels.  The
well has three pay zones, and we are currently producing from the lowest zone.
Rather than move up the hole and possibly disturb the currently producing
zone, we plan to drill an offset to this well in July 2002.  The estimated
cost to the 100% is $375,000.  Rather than assign behind-pipe reserves to the
Cox #41-5 we have assigned proved undeveloped reserves to the 100% of 1.5 BCF
to the offset well, the Cox #42-5.  The Cox #42-5 well will be drilled 400
feet deeper than the Cox #41-5 well to test a previously untested zone in the
3-D area.

This fall we plan to commence another 3-D seismic project.  This project will
cover the entire SC Field and land north of the SC Field.  The cost to the
100% is estimated to be $1 million, our share would be $800,000.  We should
know the results of the shoot by the spring of 2003.

Our electricity costs have increased significantly. During 2000 our average
monthly electricity cost in the SC Field was $70,000 compared to our costs
this year of $120,000.  We are continuing to develop the proper strategy to
optimize the cash flow from the SC Field considering these high electricity
costs.

Currently gas sales in the SC Field are limited to 1,150 MCF/day due to
pipeline capacity and pressures. We are selling about 550 MCF/day to the 100%.
After we drill the Cox #42-5 this summer we expect to be selling about
2,300 MCF/day to the 100% assuming arrangements can be made with Southern
California Gas Company (SOCAL), the owner of the pipeline, to increase the
capacity. If the capacity is not increased, our future sales will be
adversely affected.

Due to high electricity costs we are exploring the possibility of generating
our own electricity.  Based on a preliminary study, the capital costs to do
so would be in the $1.5 million range.  Instead of selling our gas we would
burn the gas to generate electricity.

This concept may come to fruition if we conclude that California electrical
costs are going to remain high for the next three years and if we are unable
to market our gas due to pipeline capacity.

     South Texas - Bonus
     -------------------

During the third and fourth quarter, we participated with Forest Oil Company
of Denver in a four-well developmental gas prospect in Wharton County, Texas
located about 70 miles southwest of Houston.  These wells are deep (about
14,000 feet) and expensive; the costs to drill and complete were about $5
million per well.  We have a 5.5% WI (4.3% NRI).  Our net book value in the
prospect is about $1.4 million.  Using March 2002 prices of $3.40 per MCF we
estimate future net revenue from these four wells to be about $1.4 million.

     San Juan Basin
     --------------

This gas field is located in the northwest corner of New Mexico in San Juan
County.  We have an interest in 20 wells and are the operator. These wells
have long-lived reserves. Our WI in this field ranges from 5%-15% with NRIs
between 5%-13%. Our net book value in this prospect is about $120,000.  We
may participate in the drilling of a development gas well in late 2002.  The
cost to the 100% to drill and complete this well will be about $700,000.
Questar, a Salt Lake City company, will be the operator during the drilling
phase.  Using March 2002 prices of $3.00 per MCF we estimate future net
revenue from this field to be about $1.7 million.

Catalytic Solutions Investment
------------------------------

During 1998, we invested $62,000 for a small ownership in Catalytic Solutions,
Inc. (CSI), a private company, located in Oxnard, California (a Los Angeles
suburb).  CSI manufactures catalytic converters that reduce toxic emissions
from internal combustion engines.  During 2000, we invested another $113,000
in CSI.  Our current ownership is about .006.

Environmental and Regulation
-----------------------------
We are directly affected by changing environmental rules and regulations.
Although we believe our operations and facilities are in compliance with
applicable environmental regulations, risk of substantial cost and liabilities
resulting from an unintentional breach of environmental regulations are
inherent to oil and gas operations.  It is possible that other developments,
such as increasingly strict environmental laws, regulations, and enforcement
policies or claims for damages could result in significant costs and
liability in the future.

In January 1999, the California legislature passed a bill, which increased
our operator's bond from $100,000 to $250,000 over a five-year period.  In
addition, an idle well bill was passed to ensure that funds would be available
to properly plug and abandon (P&A) California wells upon their depletion.
Over the next ten years, we as the SC Field's operator, are required to place
in an interest-bearing escrow account $500 per year for each idle well in the
SC Field until such well is plugged and abandoned or until $5,000 has been
deposited.  Through June 30, 2001 we have made three installments totaling
$196,000.  We estimate that after ten annual installments we will have met
the current funding obligation of $700,000 considering the interest to be
earned.  As the SC Field depletes, and more wells move from the producing
category to the idle-well category we will have to make additional annual
payments.  Presently, there are 280 wells in the SC Field, 140 of which are
classified as "idle".

During 1999, we began amortizing, using the units-of-production method, our
share of the estimated future costs ($1,207,000) to P&A the SC Field's 280
wells.  Included in the DD&A expense for 2000 and 2001 was $113,000 and
$154,000, respectively, associated with these estimated future costs.

ARCO Indemnity
--------------

The SC Field was purchased from ARCO (Atlantic Richfield which is now part of
BP p.l.c.) in May 1990. ARCO assumed certain environmental liabilities
connected with their 40-year ownership of the SC Field (hereafter, referred
to as the "Indemnity".)  During 2002, we plan to remove and clean up portions
of the old gas plant, which has not been in operation for at least 25 years.
Some of this old equipment has evidence of asbestos.  It is our position as
set forth in the Indemnity that the old gas plant and a good portion of other
clean up liability will be covered by the Indemnity.

Trend Acreage
-------------

We have been leasing undeveloped acreage on state and federal lands in
Wyoming.  From October 2001 to March 2002 we have invested about $165,000.
These leases have a ten-year term.  We expect to sell or farm-out these
leases to third parties.  During 2001 and 2000 we realized gains of $67,000
and $147,000, respectively from such sales.  We always retain an overriding
royalty interest in the oil and gas lease we sell.

Self-insurance for Employee Medical Costs
-----------------------------------------

Due to the rising costs in providing health care coverage for our employees
we changed from a standard type of policy to a self-insured policy.  We are
responsible for the first  $5,700 of health care costs for each employee and
their dependents.  Our maximum exposure in any given year is about $100,000.
Starting April 2002 we will begin accruing $3,000 per month for our
estimated claims.

Liquidity and Capital Resources
-------------------------------

Cash and cash to be provided from operations are expected to enable us to
meet our obligations as they become due during the next several years.

The SC Field, our principal asset, is pledged to U. S. Bank National
Association under a $2,000,000 revolving line of credit. Presently, we owe
$31,000 under this line.

We have never entered into hedging activities and at this time do not expect
to.

We have no special purpose entities and no off-balance sheet debt nor did
we enter into any related party transactions during the two years ended
December 31, 2001.

RESULTS OF OPERATIONS

YEAR-TO-DATE COMPARISON
-----------------------

The table below (in thousands) provides sales data and average prices for the
period.

<TABLE>
<CAPTION>
                               2001                       2000
                     ------------------------    ----------------------
                      Sales   Average            Sales  Average
                      Volume   Price  Revenue    Volume  Price  Revenue
                     -------  -------  ------    ------  -----  -------
<S>                   <C>     <C>      <C>       <C>    <C>      <C>
Oil - barrels
  South Cuyama field   215    $22.09   $4,749     233   $27.74   $6,464
  Cox #41-5 (1)         15     19.47      292
  South Texas-Bonus    1.4     18.57       26
  Other                1.7     24.71       42       *        *       30

Gas - mcf
  South Cuyama field    53      8.81      467      41     3.90      160
  Cox #41-5 (1)        121      7.79      942
  South Texas - Bonus   47      2.85      134
  San Juan-New Mexico   51      3.90      199      56     3.45      193
  Merlin Prospect(2)    56      7.59      425     111     3.89      432
  Other                 40      4.17      167      74     3.26      241

NGLs - barrels
  South Cuyama field    13     18.77      244      16    21.50      344
  San Juan-New Mexico    5     15.00       75       5    19.60       98
  Other                  *         *        1       *        *        4
------------------------
* Not meaningful

(1) This well is part of the SC Field, due to its significance we present it
    separately.

(2) This field located in northern California is near the end of its
    economic life.

</TABLE>

The table below (in thousands) shows lease operating expenses (LOE) for our
primary fields.

<TABLE>
<CAPTION>

                                                 2001          2000
                                                 ----          ----
<S>                                              <C>           <C>
South Cuyama field:
  LOE excluding electricity                    $2,623        $2,406
  Electricity                                   1,434           852
                                                -----         -----
                                                4,057         3,258

South Texas - Bonus                                12
San Juan - New Mexico                              70           117
Other                                              88           102
                                                -----         -----
  Total                                        $4,227        $3,477
                                                =====         =====
</TABLE>

LOE per equivalent barrel was $13.41 for 2001 and $11.59 for 2000.

Oil and NGL revenue is down compared to last year due to lower prices and
volumes.  The increase in gas revenue is due primarily to the Cox #41-5 and
to the abnormally high gas prices during the summer of 2001. LOE increased
due to higher electricity costs in the SC Field.

G&A increased due to bonuses paid to employees during the summer of 2001
when oil and gas prices were high.

Risk Factors
------------

The six issues that cause us worry are:

1.  OPEC deciding to significantly increase production, which would
    result in a free-fall of oil prices.

2.  Although the SC Field has a 50-year operating history, the reserve
    estimates could be overstated.

3.  We never know what adverse rules or regulations could be passed by
    our regulatory agencies such as the EPA (Environmental Protection
    Agency), BLM (Bureau of Land Management), DOG (California Division
    of Oil & Gas), and the SBAPCD (Santa Barbara County Air Pollution
    Control District).

4.  The SC Field is a high-water-cut oil field meaning that we move
    about 30,000 barrels of water per day in order to produce about 1,000
    barrels of oil per day.  Such fields have a high break-even point
    and consequently depend on a relatively high oil price to make
    money. Higher electricity costs will make it difficult to continue to
    operate the SC Field profitably. Oil prices hit a low of $15 and gas hit
    a low of $1.90 during the fourth quarter 2001.  At those low prices, our
    total monthly cash flow from all properties was $35,000; at current prices
    of $23 oil and $3 gas our monthly cash flow is $250,000.

5.  California is prone to earthquakes.  Certain types of earthquakes
    could shear the casing heads resulting in catastrophic damage to
    the SC Field.  Earthquake insurance is cost prohibitive.

6.  We have no succession plan for our CEO, Victor Stabio.  The loss of his
    services would have an adverse affect on us.  We do have a key man life
    insurance policy on Mr. Stabio in the amount of $2.5 million.

Critical Accounting Policies and Estimates
------------------------------------------

We believe the following critical accounting policies affect our more
significant judgments and estimates used in the preparation of our
financial statements.

Successful Efforts Method of Accounting
---------------------------------------

We account for our exploration and development activities utilizing the
successful efforts method of accounting. Under this method, costs of
productive exploratory wells, development dry holes and productive wells
and undeveloped leases are capitalized. Oil and gas lease acquisition costs
are also capitalized. Exploration costs, including personnel costs, certain
geological and geophysical expenses and delay rentals for oil and gas leases,
are charged to expense as incurred. Exploratory drilling costs are initially
capitalized, but charged to expense if and when the well is determined not
to have found reserves in commercial quantities. The sale of a partial
interest in a proved property is accounted for as a cost recovery and no
gain or loss is recognized as long as this treatment does not significantly
affect the unit-of-production amortization rate. A gain or loss is
recognized for all other sales of producing properties.

The application of the successful efforts method of accounting requires
managerial judgment to determine the proper classification of wells
designated as developmental or exploratory which will ultimately determine
the proper accounting treatment of the costs incurred. The results from a
drilling operation can take considerable time to analyze and the
determination that commercial reserves have been discovered requires both
judgment and industry experience. Wells may be completed that are assumed
to be productive and actually deliver oil and gas in quantities insufficient
to be economic, which may result in the abandonment of the wells at a later
date. Wells are drilled that have targeted geologic structures that are both
developmental and exploratory in nature and an allocation of costs is
required to properly account for the results. Delineation seismic incurred
to select development locations within an oil and gas field is typically
considered a development cost and capitalized but often these seismic
programs extend beyond the reserve area considered proved and management
must estimate the portion of the seismic costs to expense. The evaluation
of oil and gas leasehold acquisition costs requires managerial judgment to
estimate the fair value of these costs with reference to drilling activity
in a given area. Drilling activities in an area by other companies may also
effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on
the operational results reported when we enter a new exploratory area in hopes
of finding an oil and gas field that will be the focus of future development
drilling activity. The initial exploratory wells may be unsuccessful and will
be expensed. Seismic costs can be substantial which will result in additional
exploration expenses when incurred.

Reserve Estimates
--------------------------

Our estimates of oil and gas reserves, by necessity, are projections based on
geologic and engineering data, and there are uncertainties inherent in the
interpretation of such data as well as the projection of future rates of
production and the timing of development expenditures. Reserve
engineering is a subjective process of estimating underground accumulations
of oil and gas that are difficult to measure. The accuracy of any reserve
estimate is a function of the quality of available data, engineering and
geological interpretation and judgment. Estimates of economically recoverable
oil and gas reserves and future net cash flows necessarily depend upon a
number of variable factors and assumptions, such as historical production
from the area compared with production from other producing areas, the
assumed effects of regulations by governmental agencies and assumptions
governing future oil and gas prices, future operating costs, severance taxes,
development costs and workover costs, all of which may in fact vary
considerably from actual results. The future drilling costs associated with
reserves assigned to proved undeveloped locations may ultimately increase to
an extent that these reserves may be later determined to be uneconomic. For
these reasons, estimates of the economically recoverable quantities of oil
and gas attributable to any particular group of properties, classifications
of such reserves based on risk of recovery, and estimates of the future net
cash flows expected therefrom may vary substantially. Any significant variance
in the assumptions could materially affect the estimated quantity and value
of the reserves, which could affect the carrying value of our oil and gas
properties and/or the rate of depletion of the oil and gas properties.
Actual production, revenues and expenditures with respect to our reserves
will likely vary from estimates, and such variances may be material.

Impairment of Developed Oil and Gas Properties
----------------------------------------------

We review our oil and gas properties for impairment whenever events and
circumstances indicate a decline in the recoverability of their carrying
value. We estimate the expected future cash flows of our oil and gas
properties and compare such future cash flows to the carrying amount of our
oil and gas properties to determine if the carrying amount is recoverable.
If the carrying amount exceeds the estimated undiscounted future cash flows,
we will adjust the carrying amount of the oil and gas properties to their
fair value. The factors used to determine fair value include, but are not
limited to, estimates of proved reserves, future commodity pricing, future
production estimates, anticipated capital expenditures, and a discount rate
commensurate with the risk associated with realizing the expected cash flows
projected. There were no impairments of developed oil and gas properties
during 2001 and 2000.

At December 31, 2001 oil prices in the SC Field were $16.48.  At that price
cash flow from the SC Field is slightly positive.  During March 2002 oil
prices improved, if they had not improved, we would have taken a significant
impairment charge.  If prices during 2002 decline below $20 per barrel and
we conclude these low oil prices are not reasonably likely to improve, we
could be taking a significant impairment charge in the $1-$2 million
range.  Our net book value in the SC Field at December 31, 2001 was $6.1
million.  Future undiscounted cash flows using March 2002 prices are $7.7
million; future undiscounted cash flows using December 31, 2001 prices were
$2.4 million.

Impairment of Unproved Oil and Gas Properties
---------------------------------------------

We periodically assess individually significant unproved oil and gas
properties for impairment, on a project-by-project basis.  Our assessment of
the results of exploration activities, commodity price outlooks, planned
future sales or expiration of all or a portion of such projects impact the
amount and timing of impairment provisions.  During 2001 we took a $229,000
impairment.

Future Abandonment Costs
------------------------

We are required to make judgments based on historical experience and future
expectations on the future abandonment cost, net of salvage value, of our
oil and gas properties and equipment.  We review our estimate of the future
obligation periodically and accrue the estimated obligation monthly based
on the units-of-production method.  For properties other than the SC Field
we estimate that the future abandonment cost, net of salvage value, will not
be material.  For the SC Field we are estimating such future costs to be
$1.2 million.

New Accounting Pronouncements
-----------------------------

In June 2001 the Financial Accounting Standards Board issued SFAS No. 141,
"Business Combinations." Under this statement all business combinations must
be accounted for under the purchase method. The pooling method is no longer
allowed. The statement also establishes criteria to assess when to recognize
intangible assets separately from goodwill. SFAS No. 141 is effective for
business combinations initiated after June 30, 2001 and for all business
combinations using the purchase method for which the date of acquisition is
after June 30, 2001. At this time we have no pending business combinations
that would be affected by the adoption of this statement.

In June 2001 the FASB issued SFAS No. 142, "Goodwill and Other Intangible
Assets." This statement addresses the accounting for goodwill and other
intangible assets and provides specific guidance for testing goodwill and
other intangible assets for impairment. This statement is effective for
fiscal years beginning after December 15, 2001. The adoption of this
statement did not have a material effect on our financial position or
results of operations.

In July 2001 the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." This statement requires companies to recognize the fair value
of an asset retirement liability in the financial statements by capitalizing
that cost as part of the cost of the related long-lived asset. The asset
retirement liability should then be allocated to expense by using a
systematic and rational method. The statement is effective January 1, 2003.
We have not determined the impact of adoption of this statement but the
minimum liability would be at least $1 million on an undiscounted basis.

In August 2001 the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets." This statement provides a single
accounting model for long-lived assets to be disposed of and changes the
criteria that would have to be met to classify an asset as held-for-sale.
The statement also requires expected future operating losses from discontinued
operations to be recognized in the periods in which the losses are incurred,
which is a change from the current requirement of recognizing such operating
losses as of the measurement date. The statement is effective January 1, 2002.
The adoption of the statement did not have a material effect on our financial
position or results of operations.

 ITEM 7.  FINANCIAL STATEMENTS



                     REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS



To Hallador Petroleum Company:

We have audited the accompanying consolidated balance sheet of Hallador
Petroleum Company (a Colorado corporation) and subsidiaries as of December
31, 2001 and the related consolidated statements of operations and cash flows
for each of the two years in the period ended December 31, 2001.  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 auditing standards generally
accepted in the United States.  Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement.  An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements.  An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation.  We believe that
our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Hallador Petroleum
Company and subsidiaries as of December 31, 2001 and the results of their
operations and their cash flows for each of the two years in the period
ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.


 ARTHUR ANDERSEN LLP

/s/ARTHUR ANDERSEN LLP

Denver, Colorado
March 27, 2002

<PAGE>


                         Consolidated Balance Sheet
                             December 31, 2001
                              (in thousands)

<TABLE>
<CAPTION>
<S>                                                           <C>
ASSETS
Current assets:
  Cash and cash equivalents                                   $  2,078
  Accounts receivable-
    Oil and gas sales                                              706
    Well operations                                                174
                                                               -------
      Total current assets                                       2,958
                                                               -------
Oil and gas properties at cost (successful efforts):
  Unproved properties                                              204
  Proved properties                                             24,687
  Less - accumulated depreciation,
     depletion, amortization and impairment                    (16,497)
                                                               -------
                                                                 8,394
                                                               -------
Oil and gas operator bonds                                         366
Investment in Catalytic Solutions                                  175
Other assets                                                        44
                                                               -------
                                                              $ 11,937
                                                               =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
  Accounts payable and accrued liabilities                    $    833
  Oil and gas sales payable                                        180
                                                               -------
      Total current liabilities                                  1,013
                                                               -------
Key employee bonus plan                                            335
                                                               -------
Future site restoration - South Cuyama Field                       344
                                                               -------
Minority interest                                                5,516
                                                               -------
Commitments and contingent liabilities

Stockholders' equity:
  Preferred stock, $.10 par value;
    10,000,000 shares authorized; none issued
  Common stock, $.01 par value; 100,000,000
    shares authorized; 7,093,150 shares issued                      71
Additional paid-in capital                                      18,061
Accumulated deficit*                                           (13,403)
                                                               -------
                                                                 4,729
                                                               -------
                                                              $ 11,937
                                                               =======

*Net income has been the only change in stockholders' equity during
 the past two years.

</TABLE>


                            See accompanying notes.


                      Consolidated Statement of Operations
                               December 31, 2001
                                 (in thousands)


<TABLE>
<CAPTION>
                                               Years ended December 31,
                                                   2001         2000
                                                  ------       ------
<S>                                              <C>          <C>
Revenue:
  Oil                                            $5,109       $6,494
  Gas                                             2,334        1,026
  NGLs                                              320          446
  Gain on prospect sale                              67          147
  Interest and other                                130          159
                                                  -----        -----
                                                  7,960        8,272
                                                  -----        -----
Costs and expenses:
  Lease operating                                 4,227        3,477
  Exploration costs
    Geological and geophysical                                   296
    Dry hole expense                                123          319
    Delay rentals                                    82           72
    Impairment-proved properties                    436
    Impairment-unproved properties                  229
  Depreciation, depletion and amortization        1,300          976
  General and administrative                        909          777
  California income taxes                            63
  Purchase of employee stock options                300
  Interest                                           41           94
                                                  -----        -----
                                                  7,710        6,011
                                                  -----        -----
Income before minority interest                     250        2,261

Minority interest                                   (75)        (678)
                                                  -----        -----
Net income                                       $  175       $1,583
                                                  =====        =====
Basic and diluted income per share               $ 0.02       $ 0.22
                                                  =====        =====
Weighted average shares outstanding-basic         7,093        7,093
                                                  =====        =====
Weighted average shares outstanding-diluted       7,508        7,318
                                                  =====        =====

</TABLE>


                              See accompanying notes.

                        CONSOLIDATED STATEMENT OF CASH FLOWS
                                December 31, 2001
                                  (in thousands)

<TABLE>
<CAPTION>
                                                Years ended December 31,
                                                    2001         2000
                                                   ------       ------
<S>                                                  <C>          <C>
Cash flows from operating activities:
  Net income                                      $  175       $1,583
  Depreciation, depletion, and amortization        1,300          976
  Minority interest                                   75          678
  Impairment                                         665
  Change in accounts receivable                      419         (469)
  Change in payables and accrued liabilities        (605)         695
  Other                                                6
                                                   -----        -----
    Net cash provided by operating activities      2,035        3,463
                                                   -----        -----
Cash flows from investing activities:
  Properties                                      (2,181)      (1,715)
  Other assets                                       (65)        (216)
                                                   -----        -----
    Net cash used in investing activities         (2,246)      (1,931)
                                                   -----        -----
Cash flows from financing activities:
  Repayment of debt                                 (200)      (1,000)
                                                   -----        -----
Net increase (decrease) in cash and
  cash equivalents                                  (411)         532

Cash and cash equivalents, beginning of year       2,489        1,957
                                                   -----        -----
Cash and cash equivalents, end of period          $2,078        $2,489
                                                   =====        =====
Supplemental disclosure of cash flow information:
  Cash paid out for interest                      $   32       $   84
                                                   =====        =====

</TABLE>

                             See accompanying notes.


                          NOTES TO FINANCIAL STATEMENTS


(1)  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
     ------------------------------------------

Basis of Presentation and Consolidation
---------------------------------------

The accompanying consolidated financial statements include the accounts of
Hallador Petroleum Company and its wholly owned subsidiaries.  All significant
intercompany accounts and transactions have been eliminated.  We are engaged
in the exploration, development, and production of oil and natural gas
primarily in California.

On July 21, 1997, Yorktown Energy Partners II and affiliates (Yorktown)
invested $5,025,000 in Hallador Petroleum, LLP, a newly formed limited
liability limited partnership.  We are the general partner and received a
70% interest in the partnership in return for contributing our net assets,
and Yorktown represents the limited partners and received a 30% interest for
its $5,025,000 cash contribution.  As general partner, we consolidate the
activity of the partnership and present the 30% limited partners' interest as
a minority interest.

We are a 92% partner in Santa Barbara Partners (SBP), a general partnership,
and account for our investment using the proportionate consolidation method.
SBP has a 93% working interest in the South Cuyama field.

Oil and Gas Properties
----------------------

We account for our oil and gas activities using the successful efforts method
of accounting.  Under the successful efforts method, the costs of successful
wells, development dry holes and productive leases are capitalized and
amortized on a units-of-production basis over the remaining life of the
related reserves.  Exploratory dry hole costs and other exploratory costs,
including geological and geophysical costs, are expensed as incurred.
Delay rentals are also expensed as incurred.  Cost centers for amortization
purposes are determined on a field-by-field basis.  Estimated future
abandonment and site restoration costs, net of anticipated salvage values,
are accrued based on units-of-production.  Unproved properties with
significant acquisition costs are periodically assessed for impairment in
value, with any impairment charged to expense.

The carrying value of each field is assessed for impairment on a quarterly
basis.  If estimated future undiscounted net revenues are less than the
recorded amounts, an impairment charge is recorded.

Statement of Cash Flows
-----------------------

Cash equivalents include investments (primarily commercial paper) with
maturities of three months or less from the date of purchase.

Income Taxes
------------

Income taxes are provided based on the liability method of accounting pursuant
to FAS 109, Accounting for Income Taxes.  The provision for income taxes is
based on pretax financial taxable income.  Deferred tax assets and liabilities
are recognized for the future expected tax consequences of temporary
differences between income tax and financial reporting and principally relate
to differences in the tax basis of assets and liabilities and their reported
amounts, using enacted tax rates in effect for the year in which differences
are expected to reverse.  If it is more likely than not that some portion or
all of a deferred tax asset will not be realized, a valuation allowance is
recognized.

Earnings per Share
------------------

We follow the provisions of FAS 128, Earnings Per Share.  Basic earnings per
share are computed based on the weighted average number of common shares
outstanding.  Diluted earnings per share are computed based on the weighted
average number of common shares outstanding adjusted for the incremental
shares attributed to outstanding stock options.  Under the treasury stock
method, options to purchase 415,000 and 225,000 shares of common stock were
included in the calculation of diluted earnings per share for the years
ended December 31, 2001 and 2000, respectively.

Use of Estimates in the Preparation of Financial Statements
-----------------------------------------------------------

The preparation of financial statements in conformity with generally accepted
accounting principles requires us 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 revenue and expenses during the reporting period.
Actual amounts could differ from those estimates.

(2)  INCOME TAXES
      ------------
We have the following tax carryforwards at December 31, 2001 (in
thousands):

     Statutory depletion                                          $ 3,500
     Tax net operating losses (NOLs), utilization limited
      (expires 2003)                                                1,500
     Tax NOLs, utilization not limited (expires in 2005-2020)       4,700

We have fully reserved our net deferred tax asset account of about
$2.2 million.

(3)  STOCK OPTIONS AND BONUS PLANS

Stock Option Plan
-----------------

In December 1995, we granted to our CEO 620,000 options and another 62,000
options to other employees at an exercise price of $1.00.  These options
are fully vested.  During 1999, we issued 68,000 options with an exercise
price of $1.00, which vested one-third upon grant date with the remainder
over the next two years.  No options were granted during 2001 and 2000.  At
December 31, 2000, there were 750,000 options outstanding of which 728,335
are exercisable at $1.00.  All options were granted at fair value.

On January 19, 2001, we purchased from certain employees 177,777 options at a
cost of $1.6875 per option (about $300,000), which was recorded as
compensation expense in January 2001. Since December 1995 no options have
been exercised.   At December 31, 2001, there were 572,223 exercisable and
outstanding options.

Options to purchase a 3% partnership interest in Hallador Petroleum, LLP are
outstanding as of December 31, 2001.  The exercise price for these options
was based on the fair market value on the date of grant.

We account for our option plans under APB 25, Accounting for Stock Issued to
Employees.  Had compensation costs for the plans been determined consistent
with FAS 123, Accounting for Stock-Based Compensation, the effect on 2000
and 2001 operations would have been immaterial.

401-(k) Plan
------------

We maintain a 401-(k) Plan, which all full-time employees are able to
participate after six months of service.  We match dollar-for-dollar up to 4%
of all employee contributions when oil prices are $13.00 or greater per
barrel; vesting occurs immediately.  Our contributions for 2001 and 2000 were
$44,000 and $37,000, respectively.

Key Employee Bonus Plan
---------------------

At present, Mr. Stabio, CEO, is the only participant in the key employee
bonus plan.  Bonuses are computed based on cash flow attributed to the SC
Field plus accrued interest on the bonus plan liability at 30-day risk free
rates.  Amounts accrued for 2001 and 2000 were $40,000 and $61,000,
respectively.  As of December 31, 2001, the liability to Mr. Stabio was
$335,000.  This liability will not be paid until the earliest of the following
events occur; (i) voluntary or involuntary termination of the participant's
employment; (ii) our merger or sale or a sale of substantially all of our
assets, or (iii) the exercise by a participant of any of our stock options
which requires a payment by the participant of more than $100,000.  The
amounts accrued are unfunded and unsecured.

Catalytic Solutions Investment
------------------------------

During 1998, we invested $62,000 for a small ownership in Catalytic Solutions,
Inc. (CSI), a private company, located in Oxnard, California (a Los Angeles
suburb).  CSI manufactures catalytic converters that reduce toxic emissions
from internal combustion engines.  During 2000, we invested another
$113,000 resulting in a total ownership of about .006.  This investment is
accounted for under the cost method.  Mr. Stabio and other employees own less
than a quarter percent (.0025) in CSI.

(4)  MAJOR CUSTOMERS
     ---------------

The SC Field's oil production is purchased by Pacific Marketing and
Transportation LLC and the gas by Coral Energy.

(5)  COMMITMENTS AND CONTINGENT LIABILITIES
     --------------------------------------

South Cuyama Field
------------------

In January 1999, the California legislature passed a bill, which increased
our operator's bond from $100,000 to $250,000 to be phased in over a
five-year period.  In addition, an idle well bill was passed to ensure
that funds would be available to properly plug and abandon (P&A) California
wells upon their depletion. Over the next ten years, we as the SC Field's
operator, are required to place in an interest-bearing escrow account $500
per year for each idle well in the SC Field until such well is plugged and
abandoned or until $5,000 has been deposited.  Through June 30, 2001 we
have made three installments totaling $196,000.  We estimate that after 10
annual installments we will have met the current funding obligation of
$700,000 considering the interest to be earned.  As the SC Field depletes,
and more wells move from the producing category to the idle-well category
we will have to make additional annual payments.  Presently, there are 280
wells in the SC Field, 140 of which are classified as "idle".

During 1999, we began amortizing, using the units-of-production method,
our share of the estimated future costs ($1,207,000) to P&A the SC Field's
280 wells.  Included in the DD&A expense for 2000 and 2001 was $113,000 and
$154,000, respectively, associated with these estimated future costs.

Self-insurance for Employee Medical Costs
-----------------------------------------

Due to the rising costs in providing health care coverage for our employees
we changed from a standard type of policy to a self-insurance policy.  We are
responsible for the first $5,700 for each employee and their dependents
health costs.  Our ultimate exposure in any given year is about $100,000.
Starting April 2002 we will be accruing $3,000 per month for our estimated
claims.

(6)  OIL AND GAS RESERVE DATA (UNAUDITED)
     ------------------------------------

The following reserve estimates for the years ended December 31, 2000 and
2001 were prepared by a sole-proprietor consulting petroleum engineer based
on data we supplied.  Be cautious that there are many uncertainties inherent
in estimating proved reserve quantities and in projecting future production
rates.

Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas and NGLs which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.  Proved
developed oil and gas reserves are those reserves expected to be recovered
through existing wells with existing equipment and operating methods.  There
were no significant proved undeveloped reserves at December 31, 2000.

Oil prices in the SC Field at December 31, 2001 were $16.48.  Due to these
low oil prices the SC Field had an economic life of two years.  At
March 25, 2002 oil prices in the SC Field had increased to $22 which gave it
an estimated economic life of six years.  Due to this change, we are
presenting two sets of reserve estimates and SMOG data; one based on year
end prices and the other based on March 25, 2002 prices.



                            Analysis of Changes in Proved Reserves
                        (in thousands, using December 31, 2001 prices)

<TABLE>
<CAPTION>
                                        Oil         Gas       NGLs
                                       (BBLs)      (MCF)     (BBLs)
                                       -------    -------    -------
<S>                                    <C>         <C>         <C>
Balance at December 31, 1999           3,039       2,022       212
  Revisions of previous estimates       (693)        (77)       75
  Discoveries                                        223        13
  Production                            (234)      ( 287)      (22)
                                       -----       -----      ----
Balance at December 31, 2000           2,112       1,881       278
  Revisions of previous estimates (1) (1,492)       (584)     (175)
  Discoveries                             97       1,573
  Production                            (233)       (368)      (18)
                                       -----       -----      ----
Balance at December 31, 2001             484       2,502        85
                                       =====       =====      ====
Net of 30% minority interest             339       1,751        60
                                       =====       =====      ====
Proved producing                         484       1,760        85
                                       =====       =====      ====
Net of 30% minority interest             349       1,232        60
                                       =====       =====      ====

(1)  Due to low oil prices at December 31, 2001, we took a
     significant downward revision for the SC Field's reserves.

 </TABLE>


                            Analysis of Changes in Proved Reserves
                         (in thousands, using March 25, 2002 prices)

<TABLE>
<CAPTION>
                                      Oil         Gas       NGLs
                                     (BBLs)      (MCF)     (BBLs)
                                     -------    -------    -------
<S>                                  <C>         <C>         <C>
Balance at December 31, 1999         3,039       2,022       212
  Revisions of previous estimates     (693)        (77)       75
  Discoveries                                      223        13
  Production                          (234)      ( 287)      (22)
                                     -----       -----      ----
Balance at December 31, 2000         2,112       1,881       278
  Revisions of previous estimates     (988)       (300)     (143)
  Discoveries                          163       1,867
  Production                          (233)       (368)      (18)
                                     -----       -----      ----
Balance at December 31, 2001         1,054       3,080       117
                                     =====       =====      ====
Net of 30% minority interest           738       2,156        82
                                     =====       =====      ====
Proved producing                     1,054       2,195       117
                                     =====       =====      ====
Net of 30% minority interest           738       1,537        82
                                     =====       =====      ====

</TABLE>

The following table (in thousands) sets forth a standardized measure
of the discounted future net cash flows attributable to our proved
developed oil and gas reserves (hereinafter referred to as "SMOG").
Future cash inflows were computed using December 31, 2000 and 2001
product prices of $21.13 and $16.48 for oil, $28.73 and $9.60 for
NGLs and $7.19 and $2.29 for gas, respectively.  March 25, 2002 prices
were $22.10 for oil and $3 for gas.  Future production costs represent
the estimated future expenditures to be incurred in producing the
reserves, assuming continuation of economic conditions existing at
year-end.  Discounting the annual net cash inflows at 10%  illustrates
the impact of timing on these future cash inflows.

<TABLE>
<CAPTION>
                                           2001       2001      2000
                                          ------     ------     ------
                                                    (3/25/02
                                                     prices)
<S>                                        <C>       <C>        <C>
Future Revenue
  Oil                                     $ 8,000   $23,300    $45,000
  Gas                                       6,200     9,600     13,000
  NGLs                                        300     1,000      8,000
                                           ------    ------     ------
Future cash inflows                        14,500    33,900     66,000

Future cash outflows - production costs    (9,700)  (22,600)   (47,000)

Future income taxes                                             (1,000)
                                           ------    ------     ------
Future net cash flows                       4,800    11,300     18,000

10% discount factor                          (900)   (2,100)    (6,400)
                                           ------    ------     ------
SMOG                                      $ 3,900   $ 9,200    $11,600
                                           ======    ======     ======
Net of 30% minority interest              $ 2,730   $ 6,440    $ 8,120
                                           ======    ======     ======


</TABLE>

The following table (in thousands) summarizes the principal factors
comprising the changes in SMOG:

<TABLE>
<CAPTION>

                                                     2001         2000
                                                    ------       ------
 <S>                                                  <C>          <C>

 SMOG, beginning of year                          $11,600     $ 19,000
   Sales of oil and gas, net of production costs   (3,540)      (4,500)
   Net changes in prices and production costs      (9,060)         500
   Revisions                                         (300)     (10,400)
   Discoveries                                      3,900          900
   Change in income taxes                             200        1,800
   Changes in production rates and other                         2,200
   Acceleration of discount                         1,100        2,100
                                                   ------       ------
SMOG, end of year                                 $ 3,900      $11,600
                                                   ======       ======
</TABLE>

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE:  None

                              PART III

ITEM 9.  DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
         COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT

CORTLANDT S. DIETLER, 80, has been one of our directors since November
1995.  From April 1995 to October 1999 he was CEO of TransMontaigne Inc.
and is currently Chairman of the Board.  He also serves as a director of
Carbon Energy Corporation, Forest Oil Corporation and Key Production
Company.

DAVID HARDIE, 51, is the Chairman of the Board and has served as a
director since July 1989.  He is a General Partner of Hallador Venture
Partners LLC, the General Partner of Hallador Venture Fund II & III.
Mr. Hardie is also a director of Freedom Communications Company based in
Irvine, California and serves as a director and partner of other private
entities that are owned by members of his family.

STEVEN HARDIE, 47, has been a director since 1994.  He and David Hardie
are brothers.  For the last 16 years he has been a self-employed film
producer.  He also serves as a director and partner of other private
entities that are owned by members of his family.

BRYAN H. LAWRENCE, 59, has been one of our directors since November
1995.  He is a founder and senior manager of Yorktown Partners LLC that
manages investment partnerships formerly affiliated with Dillon, Read &
Co. Inc., an investment-banking firm (Dillon Read.)  He had been
employed with Dillon, Read since 1966, serving most recently as a
Managing Director until the merger of Dillon Read with SBC Warburg in
September 1997.  He also serves as a Director of Carbon Energy
Corporation, D&K Healthcare Resources, Inc., TransMontaigne, Inc., and
Vintage Petroleum, Inc. (each a United States public company), and
Cavell Energy Corp. (a Canadian public company) and certain non-public
companies in the energy industry in which Yorktown partnership holds
equity interests including PetroSantander Inc., Savoy Energy, L.P.,
Ricks Exploration, Inc., Athanor Resources Inc., Camden Resources,Inc.,
and Crosstex Energy Holdings, Inc., and ESI Energy Services, Inc.
He is a graduate of Hamilton College and also has a MBA from
Columbia University.

VICTOR P. STABIO, 54, is our President, CEO, CFO and a director.  He
joined us in March 1991 as our President and CEO and has been active in
the oil and gas business for the past 29 years.

Section 16(a) Beneficial Ownership Reporting Compliance
-------------------------------------------------------

Certain members of the Hardie family were delinquent in reporting
certain inter-family transactions on Form 4s.

ITEM 10.   EXECUTIVE COMPENSATION


<TABLE>
<CAPTION>
                                  SUMMARY COMPENSATION TABLE

                                     Annual Compensation
                          ---------------------------------------------
<S>                      <C>     <C>       <C>         <C>
Name and Principal                                       Other Annual
Position                  Year   Salary    Bonus (1)   Compensation (2)
---------------------     ----  ---------  ----------  ----------------
Victor P. Stabio, CEO     2001   $120,800   $193,300       $7,300
                          2000    110,500     94,700        5,900
                          1999    105,000     48,000        4,400
</TABLE>

(1)  Includes amounts, payment of which is deferred, pursuant to the
     Key Employee Bonus Plan and the purchase of 75,000 stock options
     at a cost $1.6875 per option or $126,500.

(2)  Our contribution to the 401(k) Plan.

During 1997, Mr. Stabio was granted an option to purchase 1.75% of
Hallador Petroleum, LLP for $294,000 that expires December 31, 2010.

No options were exercised during the last three years.

On January 19, 2001 we purchased 75,000 options from Mr. Stabio at a
cost of $1.6875 per option or $126,500.


At December 31, 2001 Mr. Stabio had 545,000 exercisable options and
in-the-money value $409,000.

Change in Control Arrangements
------------------------------

As of December 31, 2001, we have accrued $335,000 payable to Mr. Stabio
pursuant to the key employee bonus plan.  The $335,000 will become
payable upon our merger/sale or sale of substantially all of our assets
or his voluntary or involuntary termination.

ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table is as of March 29, 2002.

<TABLE>
<CAPTION>

      Name                            No. Shares (1)    % of Class (1)
------------------------------------  ---------------   -------------
<S>                                     <C>                  <C>
David Hardie and Steven Hardie as       3,791,259             53
Nominee for Hardie Family Members (2)

Victor P. Stabio (3)                      609,937              8

Cortlandt S. Dietler (4)                  100,000              1

Bryan H. Lawrence (5)                   2,328,500             33

SBC Warburg Dillion Read Inc. (6)         421,500              6

All directors and executive officer
 as a group (3)                         6,829,696             96

</TABLE>

(1)  Based on total outstanding shares of 7,093,150 if no options are
     held by the named directors, or based on a pro forma calculation of
     the total outstanding shares including shares issued upon exercise
     of options held by the named director or by members of the named
     group.  Beneficial ownership of certain shares have been, or is
     being, specifically disclaimed by certain directors in ownership
     reports filed with the SEC.

(2)  The Hardie family business address is 740 University Avenue, Suite
     110, Sacramento, California 95825.

(3)  Includes 545,000 shares issuable upon the exercise of options by
     Mr. Stabio.

(4)  Mr. Dietler's address is P. O. Box 5660, Denver, Colorado 80217.
     All shares are held by Pinnacle Engine Company LLC, wholly owned by
     Mr. Dietler.

(5)  Mr. Lawrence's address is  410 Park Avenue, 19th Floor, New York,
     NY 10022.  Mr. Lawrence owns 50,000 shares directly, and the
     remainder is held by Yorktown Energy Partners II, L.P., an
     affiliate.

(6)  SBC Warburg Dillon Read Inc.'s address is 535 Madison Avenue, New
     York, NY 10022.


ITEM 12.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.
                                PART IV

ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K

  (a) Exhibits

      3.1  Restated Articles of Incorporation of Kimbark Oil and Gas
           Company, effective September 24, 1987  (1)

      3.2  Articles of Amendment to Restated Articles of
           Incorporation of Kimbark Oil & Gas Company, effective
           December 14, 1989, to effect change of name to Hallador
           Petroleum Company and to change the par value and number
           of authorized shares of common stock (1)

      3.3  Amendment to Articles of Incorporation dated December 31,
           1990 to effect the one-for-ten reverse stock split (2)

      3.4  By-laws of Hallador Petroleum Company, effective November
           9, 1993 (4)

     10.1  Composite Agreement and Plan of Merger dated as of July 17,
           1989, as amended as of August 24, 1989, among Kimbark Oil &
           Gas Company, KOG Acquisition, Inc., Hallador Exploration
           Company and Harco Investors, with Exhibits A, B, C and D (1)

     10.2  Hallador Petroleum Company 1993 Stock Option Plan *(3)

     10.3  Not used

     10.4  Not used

     10.5  Hallador Petroleum Company Key Employee Bonus Compensation
           Plan *(3)

     10.6  Not used

     10.7  EOTT ENERGY NGL Contract (10)

     10.8  EOTT ENERGY OIL Contract (10)

     10.9  First Amendment to the 1993 Stock Option Plan *(6)

     10.10 First Amendment to Key Employee Bonus Compensation Plan *(6)

     10.11 Stock Purchase Agreement with Yorktown dated
           November 15, 1995 (6)

     10.12 Second Amendment to Key Employee Bonus Compensation Plan *(7)

     10.13 Hallador Petroleum, LLP Agreement (9)

     10.14 Hallador Petroleum, LLP Stock Option Agreement *(9)

     10.15 ARCO Indemnity - excerpt from the Purchase and Sale Agreement
           dated January 29, 1990 by and between Atlantic Richfield
           Corporation and Stream Energy, Inc. (11)

      21.1 List of Subsidiaries (2)

      99.a Letter regarding Arthur Andersen LLP (11)

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

    (1)  Incorporated by reference (IBR) to the 1989 Form 10-K.
    (2)  IBR to the 1990 Form 10-K.
    (3)  IBR to the 1992 Form 10-KSB.
    (4)  IBR to the 1993 Form 10-KSB.
    (5)  Not used.
    (6)  IBR to the 1995 Form 10-KSB.
    (7)  IBR to the September 30, 1996 Form 10-QSB.
    (8)  IBR to the September 30, 1997 Form 10-QSB.
    (9)  IBR to the December 31, 1997 Form 10-KSB.
   (10)  IBR to the December 31, 2000 Form 10-KSB.
   (11)  Filed herewith.
         *   Management contracts or compensatory plans.


  (b) No reports on Form 8-K were filed during the 2001 fourth quarter.


                               SIGNATURES


In accordance with Section 13 or 15(d) of the Exchange Act, the
Registrant caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.

                            HALLADOR PETROLEUM COMPANY

                             BY:/S/VICTOR P. STABIO
                                   VICTOR P. STABIO, CEO


Dated:  March 29, 2002

In accordance with the Exchange Act, this report has been signed below
by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.



/S/ DAVID HARDIE          Chairman                       March 29, 2002
    DAVID HARDIE


/S/ VICTOR P. STABIO      CEO, Principal Financial       March 29, 2002
    VICTOR P. STABIO      and Accounting Officer
                          and Director


/S/ BRYAN LAWRENCE        Director                       March 29, 2002
    BRYAN LAWRENCE



</TEXT>
</DOCUMENT>
