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, 2003
[ ] 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, 2003 was about $9.6 million.
At April 9, 2004, we had 7,093,150 shares outstanding and the aggregate market
value of such shares held by non-affiliates was about $1.9 million based on a
price of $1.55, which was the last reported trade on that date.
DOCUMENTS INCORPORATED BY REFERENCE: NONE
ITEM 1. DESCRIPTION OF BUSINESS
General Description of Business
-------------------------------
Hallador Petroleum Company, a Colorado corporation, was organized by our
predecessor in 1949.
About seven 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.
90% of our oil and gas revenue is attributable to the South Cuyama field (the
"Field") located in Santa Barbara County, California, about 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 Field. The Field's oil reserves consist of light oil at 29
degrees 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 April 5, 2004, we were receiving $32.11 per barrel for our California oil
production, which is $3.50 higher than the average price received during 2003
and $1.78 higher than the December 31, 2003 of $30.33. The 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 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 2003, we incurred about $88,000 to comply with these recurring
environmental regulations. We estimate that such expenditures for 2004 and
for each year thereafter, in the foreseeable future, will approximate $92,000.
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 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 32 employees; eight are located at our executive office in Denver and
24 are located at the 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 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 Field accounted for 90% of
2003 oil and gas revenue and San Juan Basin accounted for 4.5%.
We hold our working interests in oil and natural gas properties either through
recordable assignments, leases, or contractual arrangements such as operating
agreements. Consistent with industry practices, we do not make a detailed
examination of title when we acquire undeveloped acreage. Title to such
properties is examined by legal counsel prior to commencement of drilling
operations. This method of title examination is consistent with industry
practices.
In the acquisition and operation of oil and natural gas properties, burdens
such as royalty, overriding royalty, liens incident to operating agreements,
liens by taxing authorities, as well as other burdens and minor encumbrances
are customarily created. We believe that no such burdens materially affect
the value or use of our properties.
Proved Oil and Gas Reserves
---------------------------
Information concerning our reserve estimates is set forth in Note 6 to the
financial statements. The reserve estimates were prepared by a sole-proprietor
consulting petroleum engineer. All of our oil and gas reserves are located
onshore.
South Cuyama Field
------------------
Discovered in 1949 in the Cuyama Valley, Santa Barbara County, California, the
Field became the largest oil field found to date in the valley and is located
about 75 miles southwest from Bakersfield. By 1951, the Field contained 250
wells producing about 40,000 barrels of oil per day.
Since its discovery, the Field has produced over 223 million barrels of crude
oil. Current oil production to the 100% is about 800 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 12, 2004, we had a working interest in 64 gross (56 net) oil wells
and 35 gross (8 net) gas wells.
Leasehold Interests
-------------------
The following table sets forth our gross and net acres of undeveloped oil and
gas leases as of April 12, 2004:
Gross Net
------ ------
California 7,268 5,305
Montana 10,108 4,488
North Dakota 1,212 121
Utah 4,697 4,697
Wyoming 73,084 62,272
------ ------
Total 96,369 76,883
====== ======
We have an interest in 3,077 gross (2,707 net) developed acres in the Field.
Drilling Activity
-----------------
From January 1, 2004 through April 12, 2004, there has been no drilling
activity.
During 2003, we drilled six successful development gas wells in San Juan Basin.
Our WI in these wells is between 6% - 13% with NRIs between 5% - 11%.
During July 2003 we drilled three exploratory gas wells; two were dry holes and
one was marginal in two zones tested to date. Two additional zones will be
evaluated in the future.
During 2002 we drilled one successful development oil/gas well in the 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:
High Low
---- ----
2004
(January 1 through April 9, 2004) $1.55 $1.15
2003
First quarter 1.05 0.70
Second quarter 1.25 0.70
Third quarter 1.03 1.01
Fourth quarter 2.00 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
During the last two years no dividends were paid. We have no present intention
to pay any dividends in the foreseeable future.
At April 9, 2004 there were 411 holders of record of our common stock and the
last recorded sales price was $1.55.
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 (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
Field represents 75% of our total PV10 and the PV10 for San Juan Basin
represents 20%. Due to its significance, our value depends on the estimated
future cash flows from the 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 seven 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 are considering purchasing Yorktown's 30% interest in Hallador Petroleum
LLP; about 3,000,000 of our shares would be issued for consideration. The
effect of this transaction would be that all of the assets of Hallador
Petroleum LLP would be owned 100% by Hallador Petroleum Company, the public
entity. This transaction is being considered to simplify our operating and
capital structure.
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
------------------
A year ago the Field's daily production to the 100% averaged about 1,000 BOPD.
Current production is about 800 BOPD. The drop in production is due to
mechanical problems with the 53-6 well which was the best well in the Field.
It was producing 250 BOPD and is now producing 70 BOPD. We are evaluating
several work-over projects in the Field and plan to spend over $250,000 during
the rest of 2004 and hope to increase production by 200 BOPD. Our consulting
reservoir engineer estimates that the Field will decline about 10% per year and
that the Field could be fully depleted in 2017. Eighty percent of the Field's
future cash flow is estimated to occur during the next five years.
Based on the results of our 2002 3-D project we have identified six wildcat
sites located outside the Field's boundaries. Also, we have identified
drilling opportunities within the boundaries of the Field. During July 2003
we drilled three exploratory gas wells; two were dry holes and one was marginal
in two zones tested to date. Two additional zones will be evaluated in the
future.
Of the six wildcat sites located outside the Field's boundaries (about four
miles from the Field) we plan to drill one well this summer; the remaining five
may be drilled over the next two to three years. Dry hole costs for this 4,000
foot well to the 100% will be about $200,000 and completion costs about
$200,000. Our WI in this well is about 58% (NRI 48%). If significant gas
reserves are discovered, no gas sales will occur until we resolve the meter
limit issue with SOCAL and the pipeline issue with BP/SOCAL as discussed below.
Santa Barbara County has asked us to perform an endangered species survey
before we commence drilling. We hope to have this survey completed by May 15,
2004; but dealing with government agencies sometimes proves frustrating and
Santa Barbara County could delay the drilling. If this well proves successful,
additional development wells will be drilled.
Currently, of the 64 oil wells in the Field, eight account for 63% of the oil
production. Two gas wells account for 77% of the gas production. Due to air
quality regulations in Santa Barbara County we began a project to electrify
the field. This project began seven years ago, and all but one oil and gas well
is electrified. Although we have higher electricity costs, the repairs and
maintenance expenses are lower because electrical engines are much cheaper to
maintain than combustion engines.
SOCAL
-----
Currently gas sales in the Field are about 900 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 meter limit. If it weren't
for this meter limit, we could sell 1,500 MCF per day. If we are unable to
sell more gas, we may have to curtail our exploration and development plans.
We have to stay about 7% under the meter limit to insure that we don't exceed
the limit as SOCAL could shut us in for limit violations.
We have been negotiating with SOCAL to increase the capacity from 1,000 MCF per
day to 3,000 MCF per day. Recent negotiations with SOCAL have proved
fruitless, and we don't know when and if our capacity will increase.
Considering the time value of money, we would much rather be producing at a
much higher rate.
The pipeline we use to sell our gas is owned by BP, but leased by SOCAL. There
have been rumors that SOCAL will not renew the lease which comes up for renewal
in May 2004. If SOCAL does not renew the lease, the line could switch from a
carrier line to a proprietary line. If it becomes a proprietary line there is
no guarantee that we will have an outlet to market our gas. This situation has
no effect on our oil sales. Monthly gas sales, net to us, are about $80,000.
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 about
$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.
ARCO Indemnity
--------------
As discussed in previous filings, the 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"). Most 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 and a Los
Angeles law firm to assert our rights under the ARCO Indemnity. BP continues
to deny any responsibility.
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 26 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, 2003, our net book value in this prospect
is about $415,000. Two successful development gas wells were drilled
during April. During the third quarter four more successful development gas
wells were drilled. These six wells cost about $3.6 million to the
100%. We have an approximate 10% WI in these six wells. We assigned
proved developed gas reserves of about 500,000 MCF to our interest. Our
net revenue interest in these wells is about 7%. No more drilling is
planned for the near future.
Predecessor Entity
------------------
Over the past 12 years we have paid about $250,000 to properly plug and
abandon 12 or so sites which were previously plugged and abandoned by Kimbark
Oil & Gas Company, our predecessor entity. For 2003, we spent $42,000 to
properly plug and abandon a well in southern Colorado, which was drilled by
our predecessor over 20 years ago. We do not expect any more notices from
state regulatory jurisdictions regarding improperly P&A wells, but it is
possible that there could be more.
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. During 2003, CSI completed a private stock offering for
$35,000,000 at $13.67 per share.
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, 2003 we paid about
$28,000 in claims.
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 Field's operator, we are required to place in an
interest-bearing escrow account $500 per year for each idle well in the Field
until such well is plugged and abandoned or until $5,000 has been deposited.
Through December 31, 2003 we have made five installments totaling $344,000 to
the 100%. We estimate that after ten annual installments we will have met the
current funding obligation. As the 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 Field, about 148 are
classified as "idle".
In July 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset and is effective for fiscal years beginning after June 15,
2002. We adopted SFAS 143 on January 1, 2003 and increased our liability for
asset retirement obligations by $264,000 (using an 8% discount rate) and
recorded a cumulative effect of change in accounting principle of $180,000.
For 2003 we recognized $77,000 of accretion on the liability as a component of
depletion expense. On October 1, 2003 we increased our liability by an
additional $300,000. Prior to 2003, the estimated costs of plugging and
abandoning wells were accrued using the units-of-production method and were
considered in determining DD&A expense.
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.
We have no bank debt, no special purpose entities and no off-balance sheet
arrangements nor did we enter into any related party transactions during the
two years ended December 31, 2003.
RESULTS OF OPERATIONS
YEAR-TO-DATE COMPARISON
The table below (in thousands) provides sales data and average prices for the
period.
2003 2002
------------------------ ----------------------
Sales Average Sales Average
Volume Price Revenue Volume Price Revenue
------- ------- ------ ------ ----- -------
Oil - barrels
South Cuyama field 259 $28.61 $7,410 282 $23.09 $6,512
Other 9 21.11 190 9 18.22 164
Gas - mcf
South Cuyama field 189 5.24 990 96 3.38 324
San Juan - New Mexico 66 4.44 293 48 2.27 109
Other 83 5.56 462 216 2.97 642
Oil and gas revenue increased due to higher prices. There was a significant
production decline in our South Texas - Bonus gas field, which is included in
the "Other" category in the above table. As previously disclosed, we took an
impairment charge of $840,000 in the second quarter of 2002 for this field.
During 1999 we agreed to participate in a class action suit against certain
purchasers of crude oil in the state of California covering 1986 through 1998.
The case was settled during the third quarter of 2003 and our share of the
judgment, after contingent legal fees, was about $155,000.
The table below (in thousands) shows lease operating expenses (LOE) for our
two primary fields.
2003 2002
---- ----
South Cuyama field:
LOE excluding electricity $3,517 $2,883
Electricity 1,720 1,827
Electricity refund (115)
----- -----
5,122 4,710
San Juan - New Mexico 130 73
Other 98 175
----- -----
$5,350 $4,958
===== =====
LOE per equivalent barrel was $16.49 for 2003 and $14.15 for 2002. LOE
in the Field increased due to higher operating expenses relating to the new
equipment we had to install in the first quarter of 2003 in order to remove
CO2 from our gas stream. Furthermore, when oil prices are high, we perform
more repair and maintenance in the field compared to when prices are low
(see the table above for 2003 and 2002 average oil prices).
The $426,000 in dry hole expense relates to the dry holes drilled in the
Field in the third quarter of this year. In addition we spent $42,000 to
properly plug and abandon a well in southern Colorado, which was drilled by
our predecessor over 20 years ago and another $61,000 to plug and abandon
several wells in South Texas. Delay rentals increased due to exploration
activity we are planning next year on leases we acquired near the Field.
These sites were identified by the 3-D project we performed last year.
DD&A decreased due to higher reserve estimates used throughout the year in
the DD&A calculation.
G&G costs relate to the October 2002 3-D seismic project in the Field. G&G
costs during 2003 were not significant.
Impairment of proved properties in 2002 relates to the South Texas - Bonus
prospect discussed above. There was no impairment of proved properties in
2003.
We do not expect to pay federal income taxes in the near term. We have
recorded a $3.4 million asset for the future benefit of our United States
carryforwards and other tax benefits. 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, 2003. 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.
Risk Factors
------------
The seven 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 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 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 800 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 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.
7. If we are unable to obtain a higher meter limit with SOCAL or are unable
to continue to market our gas through the pipeline that SOCAL leases
from BP, we will have to curtail our exploration program.
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, 2003 oil prices in the Field were $30.33. If prices during
2004 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.
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.
New Accounting Pronouncements
-----------------------------
In July 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset and is effective for fiscal years beginning after
June 15, 2002. We adopted SFAS 143 on January 1, 2003 and increased our
liability for asset retirement obligations by $264,000 (using an 8% discount
rate) and recorded a cumulative effect of change in accounting principle of
$180,000. For 2003 we recognized $77,000 of accretion on the liability as a
component of depletion expense. On October 1, 2003 we increased our liability
by an additional $300,000. Prior to 2003, the estimated costs of plugging and
abandoning wells were accrued using the units-of-production method and were
considered in determining DD&A expense.
None of the other FASB pronouncements issued during the last two years had,
or will have, any effect on us.
ITEM 7. FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Independent Auditors' Report - EKSH
Independent Auditors' Report - KPMG
Consolidated Balance Sheet, December 31, 2003
Consolidated Statement of Operations, Years ended December 31, 2003 and 2002
Consolidated Statement of Cash Flows, Years ended December 31, 2003 and 2002
Notes to Consolidated Financial Statements
Independent Auditors' Report
----------------------------
The Board of Directors and Stockholders
Hallador Petroleum Company:
We have audited the 2003 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.
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 2003 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, 2003, 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.
As described in Note 1 to the consolidated financial statements, effective
January 1, 2003, the Company adopted SFAS 143 and changed its method of
accounting for asset retirement obligations.
Ehrhardt Keefe Steiner & Hottman PC
Denver, Colorado
April 2, 2004
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.
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 results of operations and cash
flows of Hallador Petroleum Company and subsidiaries for the year ended
December 31, 2002, in conformity with accounting principles generally
accepted in the United States of America.
KPMG
Denver, Colorado
April 4, 2003
Consolidated Balance Sheet
December 31, 2003
(in thousands)
ASSETS
Current assets:
Cash and cash equivalents $ 3,319
Accounts receivable-
Oil and gas sales 1,019
Well operations 543
-------
Total current assets 4,881
-------
Oil and gas properties, at cost (successful efforts):
Unproved properties 450
Proved properties 25,910
Less - accumulated depreciation,
depletion, amortization and impairment (19,749)
-------
6,611
-------
Oil and gas operator bonds 216
California plug and abandonment deposits 291
Investment in Catalytic Solutions 164
Other assets 49
-------
$ 12,212
=======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabiliti es $ 1,383
Oil and gas sales payable 598
-------
Total current liabilities 1,981
-------
Key employee bonus plan 253
-------
Future site restoration 1,294
-------
Minority interest 5,047
-------
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* (14,495)
-------
3,637
-------
$ 12,212
=======
*Net income (loss) has been the only change in stockholders' equity
during the past two years.
See accompanying notes.
Consolidated Statement of Operations
(in thousands)
Years ended December 31,
2003 2002
------ ------
Revenue:
Oil $ 7,600 $ 6,676
Gas 1,745 1,075
Crude oil class action settlement 155
Interest and other 120 43
------ ------
9,620 7,794
------ ------
Costs and expenses:
Lease operating 5,350 4,958
Exploration costs
Geological and geophysical 52 1,059
Dry hole expense 426 15
Plug and abandonment 103
Delay rentals 107 112
Impairment - proved properties 918
Impairment - unproved properties 67 22
Depreciation, depletion and amortization 1,160 2,279
General and administrative 1,140 974
California income tax (refund) 85 (34)
------ ------
8,490 10,303
------ ------
Income (loss) before cumulative effect of change
in accounting principal 1,130 (2,509)
Cumulative effect of change in accounting principle (180)
------ ------
Income (loss) before minority interest 950 (2,509)
Minority interest (285) 753
------ ------
Net income (loss) $ 665 $(1,756)
====== ======
Income (loss) per share - basic and diluted:
Before cumulative effect of change in
accounting principle $ 0.11 $ (0.25)
Cumulative effect of change in
accounting principle (0.02)
------ ------
Net income (loss) $ 0.09 $ (0.25)
====== ======
Weighted average shares outstanding
basic and diluted 7,093 7,093
====== ======
See accompanying notes.
Consolidated Statement of Cash Flows
(in thousands)
Year ended December 31,
2003 2002
------ ------
Cash flows from operating activities:
Net income (loss) $ 665 $(1,756)
Depreciation, depletion, and amortization 1,160 2,279
Minority interest 285 (753)
Impairment 67 940
Change in accounts receivable (741) 54
Change in payables and accrued liabilities 845 (45)
Cumulative effect of SFAS 143 180
Other 51 (36)
----- -----
Net cash provided by operating activities 2,512 683
----- -----
Cash flows from investing activities:
Properties* (816) (1,052)
Other assets (91) (62)
----- -----
Net cash used in investing activities (907) (1,114)
----- -----
Cash flows from financing activities:
Debt retirement (251)
Cash calls from joint interest owners 318
----- -----
Net cash provided by financing activities 67
----- -----
Net increase (decrease) in cash and cash equivalents 1,672 (431)
Cash and cash equivalents, beginning of year 1,647 2,078
----- -----
Cash and cash equivalents, end of year $3,319 $1,647
===== =====
* Net non-cash additions to oil and gas properties were $386,000 due to the
adoption of SFAS 143.
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. Unproved properties with significant acquisition costs
are periodically assessed for impairment in value, with any impairment charged
to expense.
Prior to 2003, the estimated costs of plugging and abandoning wells were
accrued using the units-of-production method and were considered in determining
DD&A expense. However, in 2003 we adopted SFAS 143, Accounting for Asset
Retirement Obligations. Under this standard, we record the fair value of the
future abandonment as capitalized abandonment costs in Oil and Gas properties
with an offsetting abandonment liability. The capitalized abandonment costs
are amortized with other property costs using the units-of-production method.
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.
The FASB is currently evaluating the application of certain provisions of SFAS
141, Business combinations, and SFAS 142, Goodwill and other Intangible Assets,
to companies in the extractive industries, including oil and gas companies.
The FASB is considering whether the provision of SFAS 141 and 142 require us
to classify costs associated with mineral rights, including both proved and
unproved lease acquisition costs, as intangible assets in the balance sheet,
apart from other oil and gas property costs, and provide specific footnote
disclosures. At the present time, we continue to include these intangible
assets in our oil and gas properties.
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. Options were excluded for
2002 because they were anti-dilutive and for 2003 there was no dilutive
effect.
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 using the
entitlement method.
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 2003): (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. Pro forma net income for 2003 would have
been $615,000 and the per share amount did not change.
New Accounting Pronouncements
-----------------------------
In July 2001, the FASB issued SFAS 143, Accounting for Asset Retirement
Obligations. SFAS 143 requires entities to record the fair value of a
liability for an asset retirement obligation in the period in which it is
incurred and a corresponding increase in the carrying amount of the related
long-lived asset and is effective for fiscal years beginning after June 15,
2002. We adopted SFAS 143 on January 1, 2003 and increased our liability for
asset retirement obligations by $264,000 (using an 8% discount rate) and
recorded a cumulative effect of change in accounting principle of $180,000.
For 2003 we recognized $77,000 of accretion on the liability as a component of
depletion expense. On October 1, 2003 we changed our estimate and increased
our liability by an additional $300,000. Prior to 2003, the estimated costs of
plugging and abandoning wells were accrued using the units-of-production method
and were considered in determining DD&A expense; $653,000 had been accrued
under this method.
Had SFAS 143 been adopted on January 1, 2002, the pro forma net loss would have
been $1,858,000, the pro forma net loss per share would have been $(.26) at
December 31, 2002 and the pro forma asset retirement obligation at January 1,
2002 would have been $850,000.
None of the other FASB pronouncements issued during the last two years had, or
will have, any effect on us.
(2) INCOME TAXES
------------
The net deferred tax asset at December 31, 2003 (in thousands) is comprised
of the following:
Deferred tax assets
Federal and state net operating loss carryforwards $ 2,000
Statutory depletion carryforwards 800
Oil and gas properties 500
Other 100
------
3,400
Valuation allowance (3,400)
------
$ 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, 2003. 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.
Our income tax 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:
2003 2002
------ ------
Expected amount $ 233 $(615)
Change in valuation allowance (210) 607
Other (23) 8
---- ----
$ 0 $ 0
==== ====
At December 31, 2003, we had U.S. net operating loss carryforwards of about
$5 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 our stock ownership during any three-year period. As of December 31, 2003,
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. No options were granted during 1996-1998. During 1999, we
issued 71,000 options with an exercise price of $1.00, which are also fully
vested. No options were granted during 2000, 2001 and 2003. In January 2001,
we purchased from certain employees 177,777 options. 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, 2003 were 749,723 of
which 690,553 are exercisable. The weighted average exercise price is $1.06
and the weighted average remaining life is about four years. All options were
granted at fair value.
Options to purchase up to 3% of the partnership interest in Hallador Petroleum,
LLP were issued in 1997 and 1998. As of December 31, 2003 2.692% are
outstanding and exercisable. 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 2003 and 2002 were about
$49,000 and $40,000, 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
Field plus accrued interest on the bonus plan liability at 30-day risk
free rates. Amounts accrued for 2003 and 2002 were $44,000 and $24,000,
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, 2003, the liability to Mr. Stabio
was $253,000. The amounts accrued are unfunded and unsecured.
(4) MAJOR CUSTOMERS
---------------
During 2003 and 2002, 100% of the Field's oil production was purchased by
Pacific Marketing and Transportation LLC.
(5) 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 Field's operator, are required
to place in an interest-bearing escrow account $500 per year for each idle well
in the Field until such well is plugged and abandoned or until $5,000 has been
deposited for each well. Through December 31, 2003 we have made five
installments totaling $344,000 to the 100%. We estimate that after 10
annual installments we will have met the current funding obligation. As the
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 Field, 148 of which are classified as "idle".
ARCO Indemnity
--------------
The 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"). Most
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 and a Los Angeles 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, 2003
we paid about $28,000 in claims.
(6) OIL AND GAS RESERVE DATA (UNAUDITED)
------------------------------------
The following reserve estimates for the years ended December 31, 2003 and
2002 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, 2003 or 2002.
Analysis of Changes in Proved Reserves
(in thousands)
Oil Gas
(BBLs) (MCF)
------- -------
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
Revisions of previous estimates 39 (429)
Discoveries 500
Production (268) (337)
------ ------
Balance at December 31, 2003 1,649 2,384
====== ======
Net of 30% minority interest 1,154 1,669
====== ======
(1) Due to low oil prices at December 31, 2001, we took a significant
downward revision for the 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, 2003 and 2002 product prices of
$30.33 and $29.00 for oil, and $5.73 and $4.02 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.
2003 2002
------ ------
Future Revenue
Oil $49,200 $53,600
Gas 10,700 9,200
------ ------
Future cash inflows 59,900 62,800
Future cash outflows -
production and abandonment costs (46,000) (35,200)
Future income taxes (4,000)
------ ------
Future net cash flows 13,900 23,600
10% discount factor (2,400) (7,100)
------ ------
SMOG $11,500 $16,500
====== ======
Net of 30% minority interest $ 8,050 $11,550
====== ======
The following table (in thousands) summarizes the principal factors
comprising the changes in SMOG:
2003 2002
------ ------
SMOG, beginning of year $16,500 $ 3,900
Sales of oil and gas, net of production costs (4,000) (2,793)
Net changes in prices and production costs (4,100) 15,093
Revisions (1,000)
Discoveries 800 1,400
Change in income taxes 1,500 (1,500)
Accretion of discount 1,800 400
------ ------
SMOG, end of year $11,500 $16,500
====== ======
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
ITEM 8A. 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.
As of the end of the period covered by 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.
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
CORTLANDT S. DIETLER, 82, 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 Forest Oil Corporation, Cimarex Energy Company and Nytis Exploration
Company.
DAVID HARDIE, 53 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, 50 has been a director since 1994. He and David Hardie are
brothers. For the last 20 years he has been an investor in common stock
and private equity. He also serves as a director and partner of other
private entities that are owned by members of his family.
BRYAN H. LAWRENCE, 61, 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 D&K Healthcare Resources, Inc., TransMontaigne, Inc., Vintage
Petroleum, Inc., Crosstex Energy, Inc. and Crosstex Energy, L.P. (each a
United States public company), and Cavell Energy Corp. (a Canadian public
company) and certain non-public companies in the energy industry in which
Yorktown partnership holds equity interests including, PetroSantander Inc.,
Savoy Energy, L.P., Athanor B.V., Camden Resources, Inc., ESI Energy
Services Inc., Ellora Energy Inc., Dernick Resources Inc., Cinco Natural
Resources Corp., Approach Resources Inc., Peak Energy Resources Inc., Nytis
Exploration Company, Compass Petroleum, Ltd. and Centurion Exploration
Company. Mr. Lawrence is a graduate of Hamilton College and has a MBA from
Columbia University.
VICTOR P. STABIO, 56, 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.
We do not have an audit committee financial expert serving on our audit
committee. We believe that the additional costs to recruit a financial
expert exceed the benefits, if any.
Our Code of Ethics is filed as Exhibit 14 to this Form 10-KSB.
ITEM 10. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
Annual Compensation
Name and Principal Other Annual
Position Year Salary Bonus (1) Compensation (2)
--------------------- ---- --------- ---------- ----------------
Victor P. Stabio, CEO 2003 $146,000 $73,500 $ 6,000
2002 132,300 24,000 6,000
2001 120,800 66,800 133,800 (3)
(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, nor granted, to Mr. Stabio during the last three
years.
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, 2003 Mr. Stabio had 545,000 exercisable options and the in-the-
money value was $109,000. Mr. Stabio has no unexercisable options.
Change in Control Arrangements
------------------------------
As of December 31, 2003, we have accrued $253,000 payable to Mr. Stabio
pursuant to the key employee bonus plan. The $253,000 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 12, 2004
..
Name No. Shares (1) % of Class (1)
------------------------------------ --------------- -------------
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
(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 3000 S Street, Suite 200, Sacramento,
California, 95816.
(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
Plan Category Number of Securities Weighted-average Number of securities
to be issued upon exercise price of remaining available
exercise of outstanding options, for future issuance
outstanding options, warrants and rights under equity
warrants and rights compensation plans
(excluding securities
reflected in column (a))
(a) (b) (c)
------------- --------------------- ------------------- -------------------
Equity compensation
Plans approved by
Security holders 749,723 $1.06 277
Equity compensation
Plans not approved
By security holders 0 0 0
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)
14. Code of Ethics (11)
21.1 List of Subsidiaries (2)
31 SOX 302 Certification (11)
32 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 fourth quarter
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The fees incurred for 2003 (EKSH) and 2002 (KPMG) were:
2003 2002
------ ------
Audit Fees $46,000 $39,000
Audit-related fees
Tax fees 11,500 20,000
All other fees
------ ------
Total fees $57,500 $59,000
====== ======
Pre-approval Policy
-------------------
In 2003 the Audit Committee adopted a formal policy concerning approval
of audit and non-audit services to be provided by EKSH. The policy requires
that all services EKSH provides to us be pre-approved by the Committee.
The Committee approved all services provided by EKSH during 2003.
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 12, 2004
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 12, 2004
DAVID HARDIE
/S/ VICTOR P. STABIO CEO, CFO, CAO and Director April 12, 2004
VICTOR P. STABIO
/S/ BRYAN LAWRENCE Director April 12, 2004
BRYAN LAWRENCE