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<SEC-DOCUMENT>0000788965-03-000004.txt : 20030415
<SEC-HEADER>0000788965-03-000004.hdr.sgml : 20030415
<ACCEPTANCE-DATETIME>20030415164848
ACCESSION NUMBER:		0000788965-03-000004
CONFORMED SUBMISSION TYPE:	10KSB
PUBLIC DOCUMENT COUNT:		2
CONFORMED PERIOD OF REPORT:	20021231
FILED AS OF DATE:		20030415

FILER:

	COMPANY DATA:	
		COMPANY CONFORMED NAME:			HALLADOR PETROLEUM CO
		CENTRAL INDEX KEY:			0000788965
		STANDARD INDUSTRIAL CLASSIFICATION:	CRUDE PETROLEUM & NATURAL GAS [1311]
		IRS NUMBER:				841014610
		STATE OF INCORPORATION:			CO
		FISCAL YEAR END:			1231

	FILING VALUES:
		FORM TYPE:		10KSB
		SEC ACT:		1934 Act
		SEC FILE NUMBER:	000-14731
		FILM NUMBER:		03650958

	BUSINESS ADDRESS:	
		STREET 1:		1660 LINCOLN ST STE 2700
		CITY:			DENVER
		STATE:			CO
		ZIP:			80264
		BUSINESS PHONE:		3038395505

	MAIL ADDRESS:	
		STREET 1:		1660 LINCOLN STREET
		STREET 2:		SUITE 2700
		CITY:			DENVER
		STATE:			CO
		ZIP:			80264

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	KIMBARK INC
		DATE OF NAME CHANGE:	19860624

	FORMER COMPANY:	
		FORMER CONFORMED NAME:	KIMBARK OIL & GAS CO /CO/
		DATE OF NAME CHANGE:	19900102
</SEC-HEADER>
<DOCUMENT>
<TYPE>10KSB
<SEQUENCE>1
<FILENAME>s10k123102.txt
<DESCRIPTION>12/31/02 FORM 10-KSB HALLADOR PETROLEUM
<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, 2002

[ ]  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 the 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

Check if there is no disclosure of delinquent filers in response 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.[x]

Our revenue for the year ended December 31, 2002 was about $7.8 million.

At April 4, 2003, we had 7,093,150 shares outstanding and the aggregate
market value of such shares held by non-affiliates was about $1.2
million based on a price of $1.01, which was the last reported trade on
that date.


DOCUMENTS INCORPORATED BY REFERENCE: NONE

ITEM 1.  DESCRIPTION OF BUSINESS

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

About six 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 representing the limited partners, 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.

88% 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( 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.  Occasionally, 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, 2003, we were receiving $27.51 per barrel for our California
oil production, which is $3.79 more than the average price received during
2002 and $1.44 less than the December 31, 2002 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.

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 2002, we incurred about $122,000 to comply with these recurring
environmental regulations.  We estimate that such expenditures for 2003 and
for each year thereafter, in the foreseeable future, will approximate $134,000.
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 and the
ARCO Indemnity.

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, and (ii) the San Juan Basin, located
in the northwest corner of New Mexico.  Revenue from the SC Field accounted for
88% of 2002 oil and gas revenue and San Juan Basin accounted for 2%.

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 7 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 1,031
barrels per day.  Currently, there are 67 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 April 4, 2003, we had a working interest in 63 gross (55 net) oil wells
and 30 gross (6 net) gas wells.



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

The following table sets forth our gross and net acres of undeveloped oil
and gas leases as of April 4, 2003:

                                         Gross                 Net
                                      --------               ------

     South Cuyama, California            6,814                3,970
     Montana                            10,108                4,488
     North Dakota                        4,617                1,517
     Utah                                5,777                5,777
     Wyoming                            76,480               65,561
                                       -------              -------
          Total                        103,796               81,313
                                       =======              =======

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

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

From January 1, 2003 through April 4, 2003, there has been no drilling activity.

During 2002 we drilled one successful development oil/gas well in the SC Field.
Although drilling was limited, we spent over $1 million on the 3-D seismic
project.  Under the successful efforts method of accounting we follow, such
costs were expensed as incurred.



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>
       2003
          (January 1 through April 4, 2003)          $1.05       $0.70

       2002
          First quarter                               1.80        1.50
          Second quarter                              2.50        1.35
          Third quarter                               1.25        1.05
          Fourth quarter                              3.50        0.70

       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
 </TABLE>

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

At April 4, 2003 there were 411 holders of record of our common
stock and the last recorded sales price was $1.01.

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,
and (ii) the San Juan Basin, located in the northwest corner of New Mexico.
The PV10 for SC Field represents 91% of our total PV10 and the PV10 for
San Juan Basin represents 6%.  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 six 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 representing the limited partners, 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 two primary operating areas.

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

Two years ago the field's daily production averaged about 750 bopd.  During
the past two years, we have brought on new production through the
recompletion of two wells and the drilling of two wells all of which were
identified in our first 3-D seismic project which was completed in October
These wells raised our production to a peak of 1,190 bopd during  the
third quarter of 2002.  Current production is at 1,031 bopd.  The drop is due
to a fast decline in initial production from the new wells and the normal
decline rate from the old wells.

During October 2002, we completed our second 3-D seismic project and during
the first quarter 2003 we completed the processing of the data and we are
currently interpreting the data.  Several drillable prospects have been
identified.  The cost to the 100% was about $1.3 million and our share was
about $1 million.

This project covered about 36 square miles.  The October 2000 3-D seismic
project covered 10 square miles.  When we purchased this field from ARCO
twelve years ago, 3-D seismic was in its infancy and very expensive.  We are
very excited about the possibilities this second 3-D seismic project brought
to us.

SOCAL
- -----

Currently gas sales in the SC Field are 1,000 MCF per day.  Southern
California Gas Company (SOCAL), the pipeline company and our only outlet to
sell gas has imposed a 1,000 MCF per day maximum limit.  If it weren't for
this limit, we believe we could sell substantially more than 1,000 MCF per
day.  If we are unable to sell more gas, we will have to curtail our
exploration and development plans.

In late August 2002 we were notified by SOCAL that they would start
enforcing stricter quality standards on our gas.  Historically, SOCAL had
accepted gas containing up to 6% inert gases and now they only accept gas
containing up to 4% inert gases.  Consequently, we had to install equipment
costing approximately $376,000 in order to remove CO2 from our gas stream.
The majority of this cost was incurred in the first quarter of 2003.  While
the equipment was being installed, SOCAL would not allow us to sell gas during
a 50-day period.  This resulted in lost gas revenue of about $54,000 during the
first quarter of 2003.

Hedging
- ------

Through mid February 2003, we had never entered into any commodity
derivative agreements since acquiring the SC Field.  During mid February 2003
oil prices in the field reached an unprecedented level of about $36 per
barrel.  For the first time we purchased puts on 23,000 barrels of oil for the
month of June 2003 (strike price of $29.00 per barrel) and 16,500 barrels of oil
for the month of July 2003 (average strike price of $30.48 per barrel).  As of
April 4, 2003 the value of these puts was $170,000.

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

The SC Field was purchased from ARCO (Atlantic Richfield which is now part
of BP p.l.c.) in May 1990.  As part of the Purchase and Sale Agreement,  ARCO
agreed to indemnify us for certain environmental liabilities connected with
their 40-year ownership of the field and gas plant ("ARCO Indemnity").  Part
of the gas plant has not been operational during the past twenty-five years.
There is evidence of asbestos in the non-operational part of the gas plant.
It is our position, and the opinion of our legal counsel, that the ARCO
Indemnity covers future abandonment and clean-up costs associated with this
gas plant.  We have had several discussions with BP regarding this matter and
have retained a San Francisco law firm to assert our rights under the ARCO
Indemnity.

The costs to abandon and clean up the gas plant area and other oil and gas
areas at the field will be significant.  There is a chance, depending on the
negotiations and legal proceedings with BP, that some or all of the costs could
be borne by us.  At this time we are unable to estimate what these costs could
ultimately be but we expect that such costs could have a material adverse effect
on our financial condition, results of operations and cash flows.

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%.  At December 31, 2002, our net book value in this prospect is
about $113,000.  Three development wells are planned for 2003.  The cost to
the 100% to drill and complete each well will total about $600,000.  Questar,
a Salt Lake City company, will be the operator during the drilling phase.

Less Significant Operating Area
- -------------------------------

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

During the third and fourth quarter of 2001, we participated in a four-well
developmental gas prospect in Wharton County, Texas.  These wells are deep
(about 14,000 feet) and expensive; the costs to drill and complete each well
was about $5 million to the 100%.  We have a 5.5% WI (4.3% NRI).  At December
31, 2001, our net book value in the prospect was about $1.3 million.  During
the second quarter of 2002, production from the prospect began to drop
unexpectedly.  As a result we reduced the proved reserves for these wells and
based on a future net cash flow analysis determined that the property had been
impaired.  As such, we recorded an impairment of $840,000 to reduce the net
book value of these wells to estimated fair market value.

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 less than 1%.  Our average per share cost is
about $8.20.  CSI is in the process of raising additional capital and expects
to sell shares at $13.

Partial Self-insurance for Employee Medical and Dental Costs
- ------------------------------------------------------------

Due to the rising costs in providing health care coverage for our employees
we changed from a standard type of policy to a partially self-insured policy.
For each year we are responsible for the first  $5,700 of health care and
$1,500 dental costs for each employee and their dependents.  Our maximum
exposure in any given year is about $130,000.  Through December 31, 2002 we
paid approximately $14,500 in claims and have accrued an additional $5,000.

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, as the SC Field's operator, we 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 December 31, 2002 we have made
four installments totaling $270,000.  We estimate that after ten annual
installments we will have met the current funding obligation 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 increase our
idle well deposits.  Presently, there are 280 wells in the SC Field,
approximately 151 are classified as "idle".

During 1999, we began amortizing, using the units-of-production method, our
share of the estimated future costs ($2,200,000) to P&A the SC Field's 280
wells.  Included in the DD&A expense for 2002 and 2001 was $310,000 and
$154,000, respectively, associated with these estimated future costs.

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 accreted to expense.  The statement is effective
January 1, 2003.   Based on current estimates, upon adoption of SFAS 143, we
expect to record an additional $400,000-$500,000 for these asset retirement
obligations.  Under our current accounting policy we have already recorded
$650,000 for such obligations.  These obligations relate to the projected cost
to plug and abandon oil and gas wells.

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.

At December 31, 2002, we had borrowings of $251,000 outstanding under a
revolving reserve-based credit facility that bore interest at a rate of
3.652%.  The borrowing base has been established at $2,200,000.  The
borrowing base is scheduled to be redetermined on May 1 and November 1 of each
year.

Borrowings under the Credit Agreement are secured by substantially all of our
producing properties.  Interest rates applied to borrowings under the Credit
Agreement are determined by reference to the prime rate, or to LIBOR, at our
election.  A varying spread of 1.75% to 2.25% is added to LIBOR, based upon
the loan usage ratio.  Borrowings under the Credit Agreement are revolving
loans until April 30, 2004, at which time all then outstanding borrowings are
due.  The Credit Agreement contains various financial covenants and other
restrictions.

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, 2002.

RESULTS OF OPERATIONS

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

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

<table>
<caption>
                               2002                       2001
                     ------------------------    ----------------------
                      Sales   Average            Sales  Average
                      Volume   Price  Revenue    Volume  Price  Revenue
                     -------  -------  ------    ------  -----  -------
<s>                   <c>     <c>      <c>       <c>    <c>      <c>
Oil - barrels
  South Cuyama field   282    $23.09   $6,512     243   $21.74   $5,284
  Other                  9     18.22      164       8    18.13      145

Gas - mcf
  South Cuyama field    96      3.38      324     175     8.05    1,409
  San Juan - New Mexico 48      2.27      109      51     3.90      199
  Other                216      2.97      642     142     5.11      726

</table>

Oil revenue is up in 2002 due to higher prices and production; and gas
revenue is down in 2002 primarily due to lower prices all as set forth in
the table above.

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

<table>
<caption>

                                                 2002          2001
                                                 ----          ----
<s>                                              <c>           <c>
South Cuyama field:
  LOE excluding electricity                    $2,883        $2,623
  Electricity                                   1,827         1,434
                                                -----         -----
                                                4,710         4,057

San Juan - New Mexico                              73            70
Other                                             175           100
                                                -----         -----
  Total                                        $4,958        $4,227
                                                =====         =====
</table>


LOE per equivalent barrel was $14.15 for 2002 and $13.41 for 2001.  LOE
increased due to higher electricity costs in the SC Field.

G&G costs relate to the October 2002 3-D seismic project in the SC Field; we
did no seismic project during 2001.

Impairment of proved properties more than doubled due to the $840,000
impairment charge related to the South Texas - Bonus prospect discussed
above.

DD&A increased due to a higher depletable base and to lower reserve estimates
utilized in the depletion calculation for the first three quarters of 2002.
In the fourth quarter of 2002 DD&A expense was $361,000 and DD&A expense for
each of the first three quarters of 2002 averaged $639,000.  This lower DD&A
expense for the fourth quarter of 2002 was due to higher reserve estimates at
December 31, 2002 compared to December 31, 2001.  This increase in reserves was
due to higher oil prices.

The $300,000 expense for the purchase of employee stock options was a one-time
event during 2001.

We do not expect to pay income taxes in the near term. In the United
States, the utilization of net operating loss carryforwards will reduce our
effective federal tax rate from approximately 40% to approximately 4%
in years we generate taxable income.  We have recorded a $4 million asset for
the future benefit of our United States carryforwards and other tax benefits.
As of December 31, 2002, this asset was completely offset by a valuation
allowance based upon our projection of realizability of the gross deferred tax
asset. Fluctuations in industry conditions and trends will require periodic
reviews of the recorded valuation allowance to determine if a decrease in the
allowance is appropriate.  A decrease in the allowance would result in an
income tax benefit and a subsequent increase in the valuation allowance would
decrease net income.

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
         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.

     5.  California is prone to earthquakes.  Certain types of earthquakes
         could shear the casing heads of our wells resulting in catastrophic
         damage to the SC Field.  Earthquake insurance is cost prohibitive,
         and we have none.

     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.  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.

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 an impairment
charge on this field.  Our net book value in the SC Field at December 31,
2002 was $5.7 million.  Future undiscounted cash flows using December 31, 2002
prices were $27 million.  If prices during 2003 decline below $20 per barrel
and we conclude these low oil prices are not reasonably likely to improve, we
could be required to take an impairment charge.

At December 31, 2001, our net book value in the South Texas - Bonus prospect
was about $1.3 million.  During the second quarter of 2002, production from
the prospect began to drop unexpectedly.  As a result we reduced our estimates
of the proved reserves for these wells and based on a future net cash flow
analysis determined that the property had been impaired.  As such, we recorded
an impairment of $840,000 to reduce the net book value of these wells to
estimated fair market value.

In June 2002 we received an offer to purchase our interest in the Fulton
Fuller exploratory gas well for $25,000 which we accepted in October 2002.
As such, we took an additional impairment charge of $79,000 during the quarter
ended June 30, 2002, to reduce the net book value to the estimated realizable
value of $25,000.

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.

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

We 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 through the
depletion calculations 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 $2.2 million, on an undiscounted
unescalated basis.  Based on reserve estimates we don't expect to begin
plugging and abandoning activities for at least 20 years.  See New Accounting
Pronouncements - SFAS No. 143 discussed below.

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

In December 2002 the Financial Accounting Standards Board issued SFAS No.
148,"Accounting for Stock-Based Compensation - Transition and Disclosure: an
amendment of FASB Statement No. 123." This statement amends SFAS No. 123,
"Accounting for Stock-Based Compensation", to provide alternative methods of
transition for a voluntary change to the fair value based method of
accounting for stock-based employee compensation. In addition, this
statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the effect
of the method used on reported results. The statement is effective for
financial statements for fiscal years ending after December 15, 2002. We will
continue to account for stock-based compensation using the methods detailed in
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees."

In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." This statement addresses financial
accounting and reporting for costs associated with exit or disposal
activities and requires recognition of a liability for a cost associated with
an exit or disposal activity when the liability is incurred, as opposed to when
the entity commits to an exit plan. SFAS No. 146 is to be applied
prospectively to exit or disposal activities initiated after December 31, 2002.
We do not have any pending or planned exit or disposal activities and do not
expect a material effect on our financial position or results of operations
from the adoption of this statement.

In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 requires that gains and losses from extinguishment
of debt be evaluated under the provisions of Accounting Principles Board
Opinion No. 30 and be classified as ordinary items unless they are unusual or
infrequent or meet the specific criteria for treatment as an extraordinary
item. This statement is effective for fiscal years beginning after
May 15, 2002. We do not anticipate that the adoption of this statement will
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 accreted to expense.  The statement is
effective January 1, 2003.   Based on current estimates, upon adoption of
SFAS 143, we expect to record an additional $400,000-$500,000 for these asset
retirement obligations.  Under our current accounting policy we have already
recorded $650,000 for such obligations.  These obligations relate to the
projected cost to plug and abandon oil and gas wells.

ITEM 7.  FINANCIAL STATEMENTS

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS




Report of Independent Public Accountants - AA                         17

Independent Auditors' Report - KPMG                                   18

Consolidated Balance Sheet, December 31, 2002                         19

Consolidated Statement of Operations,
  Years ended December 31, 2002 and 2001                              20

Consolidated Statement of Cash Flows,
  Years ended December 31, 2002 and 2001                              21

Notes to Consolidated Financial Statements                            22

                      Report of Independent Public Accountants
                      ----------------------------------------

THE FOLLOWING REPORT IS A COPY OF THE PREVIOUSLY ISSUED REPORT FROM ARTHUR
ANDERSEN LLP ("AA").   AA DID NOT PERFORM ANY PROCEDURES IN CONNECTION WITH
THIS ANNUAL REPORT ON FORM 10-KSB .  ACCORDINGLY, THIS REPORT HAS NOT BEEN
REISSUED BY AA.

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



Denver, Colorado
March 27, 2002





                                Independent Auditors' Report



The Board of Directors and Stockholders
Hallador Petroleum Company:

We have audited the 2002 consolidated financial statements of Hallador
Petroleum Company (a Colorado corporation) and subsidiaries as listed in
the accompanying index.  These consolidated financial statements are the
responsibility of the Company's management.  Our responsibility is to
express an opinion on these consolidated financial statements based on our
audit.  The 2001 consolidated financial statements of Hallador Petroleum
Company and subsidiaries as listed in the accompanying index were audited
by other auditors who have ceased operations.  Those auditors' report
dated March 27, 2002, on those consolidated financial statements was
unqualified.

We conducted our audit in accordance with auditing standards generally
accepted in the United States of America.  Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures
in the financial statements.  An audit also includes assessing the
accounting principles used and significant estimates made by management,
as well as evaluating the overall financial statement presentation.  We
believe that our audit provides a reasonable basis for our opinion.

In our opinion, the 2002 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Hallador
Petroleum Company and subsidiaries as of December 31, 2002, and the results
of their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States of America.

                                                KPMG



Denver, Colorado
April 4, 2003

                               Consolidated Balance Sheet
                                   December 31, 2002
                                    (in thousands)

<table>
<caption>

<s>                                                                <c>
ASSETS
Current assets:
   Cash and cash equivalents                                        $  1,647
   Accounts receivable-
      Oil and gas sales                                                  680
      Well operations                                                    146
                                                                     -------
           Total current assets                                        2,473
                                                                     -------
Oil and gas properties, at cost (successful efforts):
   Unproved properties                                                   247
   Proved properties                                                  25,058
   Less - accumulated depreciation,
      depletion, amortization and impairment                         (18,836)
                                                                     -------
                                                                       6,469
                                                                     -------
Oil and gas operator bonds                                               417
Investment in Catalytic Solutions                                        164
Other assets                                                              38
                                                                     -------
                                                                    $  9,561
                                                                     =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
   Accounts payable and accrued liabilities                         $    527
   Oil and gas sales payable                                             185
                                                                     -------
          Total current liabilities                                      712
                                                                     -------
Bank debt                                                                251
                                                                     -------
Key employee bonus plan                                                  209
                                                                     -------
Future site restoration - South Cuyama Field                             653
                                                                     -------
Minority interest                                                      4,763
                                                                     -------
Commitments and contingencies

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*                                                 (15,159)
                                                                     -------
                                                                       2,973
                                                                     -------
                                                                    $  9,561
                                                                     =======
</table>

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

                                See accompanying notes.

                          Consolidated Statement of Operations
                                   December 31, 2002
                                      (in thousands)


<table>
<caption>

                                                     Years ended December 31,
                                                       2002           2001
                                                      ------         ------
<s>                                                   <c>          <c>
Revenue:
   Oil                                               $ 6,676        $ 5,429
   Gas                                                 1,075          2,334
   Gain on prospect sale                                                 67
   Interest and other                                     43            130
                                                      ------         ------
                                                       7,794          7,960
                                                      ------         ------
Costs and expenses:
   Lease operating                                     4,958          4,227
   Exploration costs
       Geological and geophysical                      1,059
       Dry hole expense                                   15            123
       Delay rentals                                     112             82
   Impairment - proved properties                        918            436
   Impairment - unproved properties                       22            229
   Depreciation, depletion and amortization            2,279          1,300
   General and administrative                            951            909
   California income tax (refund)                        (34)            63
   Purchase of employee stock options                                   300
   Interest                                               23             41
                                                      ------         ------
                                                      10,303          7,710
                                                      ------         ------
Income (loss) before minority interest                (2,509)           250
Minority interest                                        753            (75)
                                                      ------         ------
Net income (loss)                                    $(1,756)       $   175
                                                      ======         ======
Basic and diluted income (loss) per share            $ (0.25)       $  0.02
                                                      ======         ======
Weighted average shares outstanding-basic              7,093          7,093
                                                      ======         ======
Weighted average shares outstanding-diluted            7,093          7,508
                                                      ======         ======
</table>


                              See accompanying notes.

                         Consolidated Statement of Cash Flows
                                   December 31, 2002
                                    (in thousands)


<table>
<caption>
                                                     Year ended December 31,
                                                       2002          2001
                                                      ------        ------
<s>                                                   <c>          <c>
Cash flows from operating activities:
  Net income (loss)                                  $(1,756)        $  175
  Depreciation, depletion, and amortization            2,279          1,300
  Minority interest                                     (753)            75
  Impairment                                             940            665
  Change in accounts receivable                           54            419
  Change in payables and accrued liabilities             (45)          (605)
  Other                                                  (36)             6
                                                       -----          -----
    Net cash provided by operating activities            683          2,035
                                                       -----          -----
Cash flows from investing activities:
  Properties                                          (1,052)        (2,181)
  Other assets                                           (62)           (65)
                                                       -----          -----
    Net cash used in investing activities             (1,114)        (2,246)
                                                       -----          -----
Cash flows from financing activities:
  Repayment of debt                                                    (200)
                                                       -----          -----
Net (decrease) in cash and cash equivalents             (431)          (411)

Cash and cash equivalents, beginning of year           2,078          2,489
                                                       -----          -----
Cash and cash equivalents, end of year                $1,647         $2,078
                                                       =====          =====
Supplemental disclosure of cash flow information:
  Cash paid out for interest                          $   18         $   32
                                                       =====          =====

</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, representing the limited partners, 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 proportionately consolidate our investment in SBP, which 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, and delay rentals are 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 based on the estimated fair
value of the field.

During the second quarter of 2002, production from the South Texas - Bonus
prospect began to drop unexpectedly.  As a result we reduced the proved
reserves for these wells and based on a future net cash flow analysis
determined that the property had been impaired.  As such, we recorded an
impairment of $840,000 to reduce the net book value of these wells to
estimated fair market value.  We recorded an additional impairment of $79,000
for the Fulton-Fuller exploratory gas well during the second quarter 2002.

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

Cash equivalents include investments (primarily commercial paper) with
maturities when purchased of three months or less.

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

Income taxes are provided based on the liability method of accounting pursuant
to SFAS 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 SFAS 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 shares of common stock were included in the
calculation of diluted earnings per share for the year ended December 31, 2001.
We excluded all 749,723 options in 2002 because they were anti dilutive.

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.

Revenue Recognition
- -------------------

We recognize oil and natural gas revenue from our interest in producing wells
as natural gas and oil is produced and sold from those wells.  We use the
sales method of accounting for our revenue.  Under the sales method, revenue
is recognized based on actual volumes sold to purchasers.  With natural gas
production operations, joint owners may take more or less than the production
volumes entitled to them under the governing operating agreement.  We record a
natural gas imbalance in other liabilities if our excess takes of natural gas
exceed our remaining proved reserves for the property.  No liability has been
recorded for any excess volumes taken, as they do not exceed our share of
remaining proved reserves.

Concentration of Credit Risk
- ---------------------------

Our revenues are derived principally from uncollateralized sales to customers
in the oil and gas industry.  The concentration of credit risk in a single
industry affects our overall exposure to credit risk because customers may be
similarly affected by changes in economic and other conditions.

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

During 1998, we invested $62,000 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 less than 1%.  This investment is accounted
for under the cost method.

Stock Based Compensation
- ------------------------

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 SFAS 123, Accounting for Stock-Based Compensation, we would have
estimated the fair value of each option grant using the Black-Scholes
option-pricing model, with the following assumptions used for the 2002
grants (there were no grants in 2001): (i) risk free interest rate of 4.14%;
(ii) expected life of 10 years; (iii) expected volatility of 120%; and (iv)
no dividend yield.  The average fair value of options granted during 2002
was $1.19.  Pro forma net loss for 2002 would have been $1,850,000, or $0.26
per share.  The effect on 2001 was immaterial.

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

In December 2002 the Financial Accounting Standards Board issued
SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure: an amendment of FASB Statement No. 123." This statement amends
SFAS No. 123, "Accounting for Stock-Based Compensation", to provide
alternative methods of transition for a voluntary change to the fair value
based method of accounting for stock-based employee compensation. In addition,
this statement amends the disclosure requirements of SFAS No. 123 to require
prominent disclosures in both annual and interim financial statements about
the method of accounting for stock-based employee compensation and the effect
of the method used on reported results. The statement is effective for
financial statements for fiscal years ending after December 15, 2002. We will
continue to account for stock-based compensation using the methods detailed in
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees."

In June 2002 the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities." This statement addresses financial
accounting and reporting for costs associated with exit or disposal activities
and requires recognition of a liability for a cost associated with an exit or
disposal activity when the liability is incurred, as opposed to when the
entity commits to an exit plan. SFAS No. 146 is to be applied prospectively to
exit or disposal activities initiated after December 31, 2002. We do not have
any pending or planned exit or disposal activities and do not expect a material
effect on our financial position or results of operations from the adoption of
this statement.

In April 2002 the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." SFAS No. 145 requires that gains and losses from extinguishment
of debt be evaluated under the provisions of Accounting Principles Board
Opinion No. 30 and be classified as ordinary items unless they are unusual or
infrequent or meet the specific criteria for treatment as an extraordinary
item. This statement is effective for fiscal years beginning after
May 15, 2002. We do not anticipate that the adoption of this statement will
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 accreted to expense.  The statement is
effective January 1, 2003.   Based on current estimates, upon adoption of
SFAS 143, we expect to record an additional $400,000-$500,000 for these asset
retirement obligations.  Under our current accounting policy we have already
recorded $650,000 for such obligations.  These obligations relate to the
projected cost to plug and abandon oil and gas wells.



(2)  INCOME TAXES

The net deferred tax asset as of December 31, 2002 (in thousands) is comprised
of the following:

    Deferred tax assets
      Federal and state net operating loss carryforwards        $ 2,838
      Statutory depletion carryforwards                             802
      Property, plat and equipment                                  253
      Other                                                         109
                                                                 ------
                                                                  4,002
    Valuation allowance                                          (4,002)
                                                                 ------
        Net deferred tax asset                                  $     0
                                                                 ======

With our history of losses, we believe that sufficient uncertainty exists
regarding the realizability of our net deferred tax asset. We therefore
recorded a valuation allowance to offset the entire deferred tax asset at
December 31, 2002.  We will continue to evaluate our net deferred tax asset
and to the extent we may determine that it is more likely than not that an
asset will be realized, the valuation allowance will be reduced accordingly.

Income tax expense (benefit) is different than the expected amount computed
using the applicable federal statutory income tax rate of 35%. The reasons
for and effects of such differences (in thousands) are as follows for the year
ended December 31, 2002:



<table>
<caption>
                                                    Year ended December 31, 2002
                                                     ---------------------------
    <s>                                                       <c>
    Expected amount                                             $  (615)
    Increase (decrease) from:
      Increase in valuation allowance                               607
      Permanent differences between financial statement
        income and taxable income                                   148
      State taxes, net of federal benefit, and other               (140)
                                                                 ------
    Total income tax expense (benefit)                          $     0
                                                                 ======
</table>



At December 31, 2002, we had U.S. net operating loss carryforwards of
approximately $7 million to apply against future taxable income. Losses
expire within 15-20 years after the date incurred or at various times from
2003 to 2022.

We also have statutory depletion carryforwards and minimum tax credit
carryforwards which do not expire.  U.S. net operating loss carryforwards
would be subject to an annual limitation should there be a change of over 50%
in the stock ownership of the Company during any three-year period. As of
December 31, 2002, no such ownership change had occurred.


(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 are also fully vested.  No options were granted during 2000 and
2001.  In January 2001, we purchased from certain employees 177,777 options
leaving 572,223 options outstanding all of which were exercisable at $1.00 on
December 31, 2001.  In August 2002, the Company issued 177,500 incentive stock
options to certain employees at an exercise price of $1.25 per share.  These
options, which expire August 31, 2012, vested one-third at date of grant and
the remaining over two years.  Total issued and outstanding options at
December 31, 2002 were 749,723 of which 631,386 are exercisable.  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.

Options to purchase a 3% partnership interest in Hallador Petroleum, LLP are
outstanding as of December 31, 2002.  The exercise price for these options was
based on the fair market value on the date of grant.

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

We maintain a 401(k) Plan, in 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 2002 and 2001 were $40,000
and $44,000, 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 2002 and 2001 were $24,000 and $40,000, respectively.
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.  Upon
approval of the Board of Directors, in October 2002, Mr. Stabio received a
distribution from the plan in the amount of $150,000.  As of December 31, 2002,
the liability to Mr. Stabio was $209,000.  The amounts accrued are unfunded and
unsecured.

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

During 2002, 82% of the SC Field's oil production was purchased by Pacific
Marketing and Transportation LLC, and in 2001 they purchased 65%.

(5)  LONG-TERM DEBT:
     ---------------
At December 31, 2002, we had borrowings of $251,000 outstanding under a
reserve-based, revolving credit facility that bore interest at a rate of
3.652%.  The borrowing base has been established at $2,200,000.  The
borrowing base is scheduled to be redetermined on May 1 and November 1 of
each year.

Borrowings under the Credit Agreement are secured by substantially all of our
producing properties.  Interest rates applied to borrowings under the Credit
Agreement are determined by reference to the prime rate, or to LIBOR, at our
election.  A varying spread of 1.75% to 2.25% is added to LIBOR, based upon the
loan usage ratio.  Borrowings under the Credit Agreement are revolving loans
until April 30, 2004, at which time all then outstanding borrowings are due.
the Credit Agreement contains various financial covenants and other
restrictions.

(6)  COMMITMENTS AND CONTINGENCIES
     -----------------------------

Oil and Gas Operator Bonds - 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 for each well.  Through December 31, 2002 we have
made four installments totaling $270,000.  We estimate that after 10 annual
installments we will have met the current funding obligation 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 increase our idle
well deposits.  Presently, there are 280 wells in the SC Field, 151 of which are
classified as "idle".

During 1999, we began amortizing, using the units-of-production method, our
share of the estimated future costs ($2,200,000) to P&A the SC Field's 280
wells.  Included in the DD&A expense for 2002 and 2001 was $310,000 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.  As part of the Purchase and Sale Agreement, ARCO
agreed to indemnify us for certain environmental liabilities connected with
their 40-year ownership of the field and gas plant ("ARCO Indemnity").  Part
of the gas plant has not been operational during the past twenty-five years.
There is evidence of asbestos in the non-operational part of the gas plant.
It is our position, and the opinion of our legal counsel, that the ARCO
Indemnity covers future abandonment and clean-up costs associated with this
gas plant.  We have had several discussions with BP regarding this matter and
have retained a San Francisco law firm to assert our rights under the ARCO
Indemnity.

The costs to abandon and clean up the old gas plant area and other oil and
gas areas at the field will be significant.  There is a chance, depending on
the negotiations and legal proceedings with BP, that some or all of the costs
could be borne by us.  At this time we are unable to estimate what these costs
could ultimately be but we expect that such costs could have a material adverse
effect on our financial condition, results of operations and cash flows.

Partial Self-insurance for Employee Medical and Dental Costs
- ------------------------------------------------------------

Due to the rising costs in providing health care coverage for our employees
we changed from a standard type of policy to a partially self-insured policy.
For each year we are responsible for the first $5,700 of health care and
$1,500 dental costs for each employee and their dependents.  Our maximum
exposure in any given year is about $130,000.  Through December 31, 2002 we
paid approximately $14,500 in claims and have accrued an additional $5,000.

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

The following reserve estimates for the years ended December 31, 2002 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 and
natural gas 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, 2002.  Proved undeveloped gas
reserves at December 31, 2001 were 742 MMCF.  During 2002 these reserves
were reclassified to proved-developed behind pipe.

At December 31, 2002 the oil price in the SC Field was $29.00.  Based on
this price the field has an estimated economic life of 20 years.  At
December 31, 2001 the oil price in the SC field was $16.48.  Based on that
price the field had an estimated economic life of two years.



                       Analysis of Changes in Proved Developed Reserves
                                       (in thousands)

<table>
<caption>
                                                     Oil           Gas
                                                    (BBLs)        (MCF)
                                                   -------       -------
<s>                                                 <c>          <c>
Balance at December 31, 2000                         2,390        1,881
  Revisions of previous estimates (1)               (1,667)        (584)
  Discoveries                                           97        1,573
  Production                                          (251)        (368)
                                                    ------       ------
Balance at December 31, 2001                           569        2,502
  Revisions of previous estimates (1)                1,527          484
  Discoveries                                           73           24
  Production                                          (291)        (360)
                                                    ------       ------
Balance at December 31, 2002                         1,878        2,650
                                                    ======       ======
Net of 30% minority interest                         1,315        1,855
                                                    ======       ======
</table>

(1) Due to low oil prices at December 31, 2001, we took a significant
downward revision for the SC Field's reserves; such reserves were reinstated
at December 31, 2002 due to higher oil prices.

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, 2002 and 2001 product prices of $29.00 and
$16.48 for oil, and $4.02 and $2.29 for gas, respectively.  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>


                                                     2002         2001
                                                    ------       ------
<s>                                                  <c>          <c>
Future Revenue
  Oil                                              $53,600      $ 8,300
  Gas                                                9,200        6,200
                                                    ------       ------
Future cash inflows                                 62,800       14,500
Future cash outflows - production costs            (35,200)      (9,700)
Future income taxes                                 (4,000)
                                                    ------       ------
Future net cash flows                               23,600        4,800
10% discount factor                                 (7,100)        (900)
                                                    ------       ------
SMOG                                               $16,500      $ 3,900
                                                    ======       ======
Net of 30% minority interest                       $11,550      $ 2,730
                                                    ======       ======
</table>

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

<table>
<caption>
                                                     2002         2001
                                                    ------       ------
 <s>                                                  <c>          <c>

 SMOG, beginning of year                          $ 3,900     $ 11,600
   Sales of oil and gas, net of production costs   (2,793)      (3,540)
   Net changes in prices and production costs      15,093       (9,060)
   Revisions                                                      (300)
   Discoveries                                      1,400        3,900
   Change in income taxes                          (1,500)         200
   Accretion of discount                              400        1,100
                                                   ------       ------
SMOG, end of year                                 $16,500      $ 3,900
                                                   ======       ======

</table>

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
         FINANCIAL DISCLOSURE:  Not applicable.


                                      PART III

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

CORTLANDT S. DIETLER, 81, 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 Cimarex Energy Company.

DAVID HARDIE, 52 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, 48 has been a director since 1994.  He and David Hardie are
brothers.  For the last 17 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, 60, 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 Inc., PetroSantander Inc.,
Savoy Energy, L.P., Athanor B.V., Camden Resources, Inc., and Crosstex
Energy Holdings, Inc., ESI Energy Services Inc., Ellora Energy Inc.,
Dernick Resources Inc., Cinco Natural Resources Corp., Approach Resources
Inc. and Peak Energy Resources Inc.  Mr. Lawrence is a graduate of
Hamilton College, and also has a MBA from Columbia University.

VICTOR P. STABIO, 55, 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 30 years.


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     2002   $132,300   $ 24,000       $  6,000
                          2001    120,800     66,800        133,800 (3)
                          2000    110,500     94,700          5,900

</TABLE>

(1) Includes amounts, payments of which are deferred, pursuant to the Key
    Employee Bonus Plan.

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

(3) Includes the purchase of 75,000 stock options at a cost of $1.6875 per
    option or $126,500 during 2001.

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.

In October 2002, Mr. Stabio received a distribution in the amount $150,000
from the Key Employee Bonus Plan, as authorized by the Board of Directors.

At December 31, 2002 Mr. Stabio had 545,000 exercisable options of which
none were in-the-money.

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

As of December 31, 2002, we have accrued $209,000 payable to Mr. Stabio
pursuant to the key employee bonus plan.  The $209,000 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
          AND RELATED STOCKHOLDER MATTERS

The following table is as of April 4, 2003.

<table>
<caption>

      Name                            No. Shares (1)    % of Class (1)
- ------------------------------------  ---------------   -------------
<s>                                     <c>                  <c>
David Hardie and Steven Hardie as       3,346,069             47
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)                         6,384,506             89

</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 680 Washington Boulevard,
     7th Floor, Stamford, CT 06901


                         EQUITY COMPENSATION PLAN INFORMATION
<table>
<caption>

                                                            Number of securities
                 Number of Securities  Weighted-average     remaining available
                 to be issued upon     exercise price of    for future issuance
                 exercise of           outstanding options  under equity
Plan Category    outstanding options   warrants and rights  compliance plans
- -------------    ---------------------  -------------------  -------------------
<s>                         <c>                <c>                      <c>
Equity compensation
Plans approved by
Security holders            749,723             $1.06                   277

Equity compensation
Plans not approved
By security holders               0                 0                     0

</table>

ITEM 12.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Not applicable.

                                      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  Hallador Petroleum Company Key Employee Bonus Compensation Plan *(3)
    10.4  First Amendment to the 1993 Stock Option Plan *(6)
    10.5  First Amendment to Key Employee Bonus Compensation Plan *(6)
    10.6  Stock Purchase Agreement with Yorktown dated November 15, 1995 (6)
    10.7  Second Amendment to Key Employee Bonus Compensation Plan *(7)
    10.8  Hallador Petroleum, LLP Agreement (9)
    10.9  Hallador Petroleum, LLP Stock Option Agreement *(9)
    10.10 ARCO Indemnity - excerpt from the Purchase and Sale Agreement dated
          January 29, 1990 by and between Atlantic Richfield Corporation and
          Stream Energy, Inc. (10)
    21.1  List of Subsidiaries (2)
    99.1  SOX 906 Certification (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, 2001 Form 10-KSB.
   (11) Filed herewith.
     *  Management contracts or compensatory plans.
(b) No reports on Form 8-K were filed during the 2002 fourth quarter

ITEM 14.  CONTROLS AND PROCEDURES

We maintain a system of disclosure controls and procedures that are designed
for the purposes of ensuring that information required to be disclosed in our
SEC reports is recorded, processed, summarized and reported within the time
periods specified in the SEC's rules and forms, and that such information is
accumulated and communicated to our CEO as appropriate to allow timely
decisions regarding required disclosure.

Within the 90-day period prior to the filing of this report, we carried out
an evaluation, under the supervision and with the participation of our CEO
of the effectiveness of the design and operation of our disclosure controls
and procedures. Based upon that evaluation, our CEO, who is also our CFO,
concluded that our disclosure controls and procedures are effective for the
purposes discussed above. There have been no significant changes in our
internal controls or in other factors that could significantly affect
these controls subsequent to the date of the evaluation.

                               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:  April 14, 2003

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                       April 14, 2003
    DAVID HARDIE


/S/ VICTOR P. STABIO      CEO, Principal Financial       April 14, 2003
    VICTOR P. STABIO      and Accounting Officer
                          and Director


/S/ BRYAN LAWRENCE        Director                       April 14, 2003
    BRYAN LAWRENCE




                                  CERTIFICATION

I, Victor P. Stabio, certify that:

1.  I have reviewed this annual report on Form 10-KSB of Hallador Petroleum
Company;

2.  Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;

3.  Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;

4.  I am responsible for establishing and maintaining disclosure controls and
procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the
registrant and I have:

    a)  designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated subsidiaries,
is made known to me by others within those entities, particularly during the
period in which this annual report is being prepared;

    b)  evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and

    c)  presented in this annual report my conclusion about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;

5.  I have disclosed, based on our most recent evaluation, to the registrant's
auditors and the audit committee of registrant's board of directors (or persons
performing the equivalent function):

    a)  all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weakness in internal controls; and

    b)  any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6.  I have indicated in this annual report whether there were significant
changes in internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies
and material weaknesses.

Date:   April 14, 2003

        /S/VICTOR P. STABIO
        Victor P. Stabio
        Chief Executive Officer and Chief Financial Officer




</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99
<SEQUENCE>3
<FILENAME>exh9910ksb.txt
<DESCRIPTION>CERTIFICATION SECTION 906 SARBANES-OXLEY
<TEXT>
Exhibit 99.1

CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection  with the annual report of Hallador Petroleum Company (the
"Company"), on Form 10-KSB for the period ended December 31, 2002, as filed
with the  Securities and Exchange  Commission on the date hereof (the
"Report"), the undersigned, in the capacities and dates indicated below,
hereby  certifies  pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully
complies with the requirements of Section 13(a) or 15(d) of the Securities
Exchange Act  of 1934; and (2) The information contained in the Report fairly
presents, in all material respects, the financial condition and results of
operations of the Company.

Dated:  April 14, 2003              By:  /S/VICTOR P. STABIO
                                         Chief Executive Officer and
                                         Chief Financial Officer




</TEXT>
</DOCUMENT>
</SEC-DOCUMENT>
-----END PRIVACY-ENHANCED MESSAGE-----
