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, 1996
[ ] TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
Commission file number: 0-14731
HALLADOR PETROLEUM COMPANY
(Name of small business issuer in its charter)
COLORADO 84-1014610
(State or other jurisdiction of (I.R.S. Employer
corporation or organization) 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 to 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 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]
State issuer's revenues for its most recent fiscal year: $5,438,000
As of March 27, 1997, approximately 7,093,150 shares of the registrant's
common stock were outstanding and the aggregate market value of such common
stock held by non-affiliates was approximately $765,000 based on the closing
price of $1.75.
Exhibit table is on page 30. DOCUMENTS INCORPORATED BY REFERENCE: NONE
<PAGE> 1
TABLE OF CONTENTS
1996 FORM 10-KSB ANNUAL REPORT
HALLADOR PETROLEUM COMPANY
PART I:
Item 1. Description of Business. . . . . . . . . . . . . . . . . . . 3
Item 2. Description of Property. . . . . . . . . . . . . . . . . . . 6
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . 9
Item 4. Submission of Matters to a Vote of Security Holders. . . . . 9
PART II:
Item 5. Market for Common Equity and Related Stockholder Matters. . 9
Item 6. Management's Discussion and Analysis or Plan of Operation. . 10
Item 7. Financial Statements . . . . . . . . . . . . . . . . . . . . 15
Item 8. Changes In and Disagreements With Accountants on Accounting
and Financial Disclosure . . . . . . . . . . . . . . . . . . 26
PART III:
Item 9. Directors, Executive Officers, Promoters and Control Persons;
Compliance with Section 16(a) of the Exchange Act. . . . . . 26
Item 10. Executive Compensation . . . . . . . . . . . . . . . . . . . 28
Item 11. Security Onwership of Certain Beneficial Owners and
Management. . . . . . . . . . . . . . . . . . . . . . . . . 29
Item 12. Certain Relationships and Related Transactions . . . . . . . 30
PART IV:
Item 13. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . .30
SIGNATURES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
<PAGE> 2
ITEM 1. DESCRIPTION OF BUSINESS
GENERAL DEVELOPMENT OF BUSINESS
Hallador Petroleum Company, a Colorado corporation, is the successor to
Kimbark Oil & Gas Company (organized in 1949) and Hallador Exploration
Company (organized by its predecessor in 1979). Hallador Petroleum Company
and its principal operating subsidiaries, Hallador Exploration Company and
Hallador Production Company (collectively referred to as the "Company"), are
engaged in the exploration, development and production of oil and natural
gas. The principal and administrative offices of the Company are located at
1660 Lincoln Street, Suite 2700, Denver, Colorado 80264, phone 303.839.5504,
fax 303.832.3013. The Company's field office is located in New Cuyama,
California.
Substantially all of the Company's revenue and reserves are attributable to
the South Cuyama Field (the "Field") located in Santa Barbara County,
California, approximately 75 miles southwest from Bakersfield, California.
The Company owns 92% of Santa Barbara Partners (SBP), an Oklahoma general
partnership, which has an 84% working interest (69% net revenue interest) in
the Field subject to an 18% net profits interest, resulting in an approximate
63% working interest (52% net revenue interest). The Field's oil reserves
consist primarily of light oil at 31 degree gravity.
The Company operates oil and natural gas properties for its own account and
for the account of others. The Company also reviews and evaluates producing
oil and natural gas properties, companies, or other entities which meet
certain guidelines for acquisition purposes. In addition, the Company
engages in the trading and acquisition of non-producing oil and gas mineral
leases and fee-simple minerals.
MARKETS
The Company's 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.
Now that it is permissible to export Alaskan North Slope (ANS) crude oil to
foreign countries, the Company believes California crude prices more fairly
represent free market prices.
On February 10, 1996, the President signed into law a bill which authorizes
the sale, within two years, of the Elk Hills Naval Petroleum Reserve located
in Kern County, California. The Company believes the sale may result in a
significant concentration of the ownership of the light crude oil used as
blending stock for the heavy crude oil produced in the San Joaquin Valley.
If such concentrations occur, it is possible the Company will experience a
favorable impact on its oil prices.
The Field's natural gas is sold to Atlantic Richfield Company (ARCO) pursuant
to a "spot market" contract which runs through December 31, 1997; thereafter
it is expected the contract will revert to a 30-day evergreen. The average
price per MCF received during 1996 was $1.80; the year-end price was $4.17
and the March 27, 1997 estimated price was $1.90.
NGLs are also sold to ARCO pursuant to a "spot market" contract which can be
canceled by either party with 60 days notice. The average price per barrel
received during 1996 was $14.10; the year-end price was $21.00 and the March
27, 1997 estimated price was $16.80.
At the present time, there is only one pipeline in the area. The loss of
this outlet for the Company's natural gas could have an adverse affect on the
Company's operations. There are other purchasers for the NGLs production.
<PAGE> 3
The Field's oil is sold to KOCH Oil Company (KOCH) pursuant to a contract
which pays a $.30 per barrel premium, cancelable by either party upon 180
days notice. The average price per barrel received during 1996 was $19.51;
the year-end price was $22.18, and the March 27, 1997 price was $19.60. The
loss of KOCH would not have an adverse effect on the Company's operations as
there are several other companies competing to purchase the oil.
COMPETITION
The oil and gas industry is highly competitive. The Company encounters
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 its properties.
Competition is intense with respect to the acquisition of producing and
partially developed properties. The Company competes with companies having
financial resources and technical staffs significantly larger than its own.
The Company does not own refining or retail outlets and has minimal control
over the prices of its products. Generally, higher costs, fees and taxes
assessed at the producer level cannot be passed on to the Company's
customers.
The Company also faces competition from imported products as well as
alternative sources of energy such as coal, nuclear, hydro-electric power,
and a growing trend toward solar. The Company could incur delays or
curtailments of the purchase of its available production. It may also
encounter increasing costs of production and transportation while sales
prices remain stable or decline. Any of these competitive factors could have
an adverse affect on the operating results of the Company.
<PAGE> 4
ENVIRONMENTAL AND OTHER REGULATIONS
The operations of the Company 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.
The Company is 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 prices received by the Company. It is
not possible to predict the long-term impact of future natural gas price
regulation or deregulation.
The Company, as an owner and operator of oil and natural gas properties, is
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 the Company's oil and natural gas wells and other facilities.
The Company spends a significant amount of technical and managerial time to
comply with environmental regulations and permitting requirements.
The Company has made and will continue to make expenditures to comply with
these requirements, which it believes are necessary business costs. Although
environmental requirements do have a substantial impact upon the energy
industry, generally these requirements do not appear to affect the Company
any differently or to any greater or lesser extent than other companies in
California.
Although it is not fully insured against all environmental and other risks,
the Company maintains insurance coverage which it believes is customary in
the industry. The Company is not aware of any environmental claims which
could have a material impact upon the Company's financial condition.
Compliance with federal, state, regional and local provisions relating to
protection of the environment have an impact on the Company. During 1996, the
aggregate amount incurred by the Company to comply with environmental
regulations was $151,000. The Company estimates that such expenditures for
1997 and for each year thereafter in the foreseeable future will be
approximately $158,000. The Company will continue to use its best efforts
to comply with all applicable environmental laws and regulations. See MD&A
for a discussion regarding possible electrification of the Field.
To the extent these environmental expenditures reduce funds available for
increasing the Company's reserves of oil and natural gas, future operations
could be adversely impacted. Despite the fact that all the Company's
competitors are having to comply with similar regulations, many are much
larger and have greater resources with which to deal with these regulations.
<PAGE> 5
OTHER
There are no significant patents, trademarks, licenses, franchises or
concessions held by the Company.
The oil and natural gas business is not generally seasonal in nature,
although unusual weather extremes for extended periods may increase or
decrease demand for oil and NGLs. Natural gas prices tend to increase in the
fall and winter months and to decrease in the spring and summer.
The Company has 23 employees; five are located at its executive office in
Denver and 18 are located at the Field in New Cuyama, California. The
Company also engages independent consulting petroleum engineers,
environmental professionals, geologists, geophysicists, landmen and attorneys
on a fee basis.
ITEM 2. DESCRIPTION OF PROPERTY
LOCATION AND GENERAL CHARACTER
The Company's principal producing area is in Santa Barbara County, California
with minor producing natural gas properties in the San Juan Basin of New
Mexico.
The Company holds its working interests in oil and natural gas properties
either through recordable assignments, leases or contractual arrangements
such as operating agreements. Consistent with industry practices, the
Company does not make a detailed examination of title when it acquires
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. The Company believes that
it holds satisfactory title to its properties.
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. The Company believes that no such burdens
materially affect the value or use of its properties.
PROVED OIL AND GAS RESERVES
Information concerning estimates of the Company's reserves is set forth in
Note 6 to the financial statements. The Company's reserve estimates for the
Field were prepared by the Midland, Texas office of Williamson Petroleum
Consultants, Inc. (Williamson). No independent reserve report was prepared
for the Company's other immaterial properties. All of the Company's oil and
gas reserves are located onshore.
<PAGE> 6
REVISIONS TO NATURAL GAS AND NGL RESERVES
See Item 6 - Management's Discussion and Analysis.
THE 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. The
Field is located 75 miles southwest from Bakersfield. By 1951, the field
contained 200 wells producing 40,000 barrels of oil per day. Gas production
peaked in 1963 at 125,000 MCFD.
Since inception, the Field is estimated to have produced and sold over 214
million barrels of crude oil. March 1997 production to the 100% averaged (i)
1,011 barrels per day (ii) 1,472 MCFD, of which 231 MCFD are being sold; the
difference of 1,241 MCFD is consumed in field operations and shrinkage
associated with NGL extraction and (iii) 119 barrels per day of NGLs.
Currently, there are 88 producing wells in the Field and 170 inactive wells.
The wells produce from a depth range of 3,900 to 4,700 feet.
The remaining recoverable oil reserves assigned to the Field are less than
2.5% of the original recoverable oil reserves in place. The current oil
production levels approximate less than 3% of the peak production levels
experienced in the 1950s. Due to the enormity of the original oil reserves
in place and the complexity of the reservoir, it is not unreasonable to
assume that the estimated remaining oil reserves could be understated by a
factor of 1% of the original recoverable oil reserves in place. If such were
the case, the Company's share of these additional oil reserves would
approximate 1 million barrels which translates to an additional $11 million
(using March 1997 prices) in PV10 value before income taxes. However,
caution is warranted in using this data because no such reserves have been
assigned in the accompanying reserves estimates prepared by Williamson.
<PAGE> 7
SALES, PRICE AND PRODUCTION COST
Product sales, average sales prices and average production
costs per equivalent barrel of production are shown in the following table
for each of the two years in the period ended December 31:
<TABLE>
<CAPTION>
1996 1995
---- ----
<S> <C> <C>
Sales:
Oil (MBLs). . . . . . . . . . . 220 225
Gas (MMCF). . . . . . . . . . 197 325
NGLs (MBLs) . . . . . . . . . 39 44
Average Sales Price:
Oil (per BBL) . . . . . . . . $19.55 $15.87
Gas (per MCF) . . . . . . . . 1.77 1.42
NGLs (per BBL). . . . . . . . 13.61 11.10
Average Production Cost (1). . .. $ 9.18 $ 8.29
</TABLE>
(1) Operating costs, including production tax, per equivalent barrel (six
MCF of gas is equivalent to one barrel of oil). Lower gas production
caused the increase in the average production cost.
PRODUCING WELLS IN THE FIELD
As of December 31, 1996, the Company has a working interest in 77 gross (49
net) oil wells and 11 gross (7 net) gas wells.
LEASEHOLD INTERESTS
The following table sets forth the gross and net acres of undeveloped oil and
gas leases and lease options held by the Company as of March 27, 1997:
<TABLE>
<CAPTION>
STATE GROSS NET
------- ----- ------
<S> <C> <C>
Northern
California 4,504 4,365
Montana 48,702 33,405
North Dakota 34,201 20,495
Wyoming 31,153 30,237
------- ------
Total 118,560 88,502
======= ======
</TABLE>
The Company has an interest in 2,504 gross (2,001 net) developed acres in the
Field.
<PAGE> 8
DRILLING ACTIVITY
See Item 6 - MD&A for a discussion of current drilling activity.
No significant drilling activity occurred during 1996 and 1995.
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
The Company's common stock is traded on the OTC Bulletin Board under the
symbol "HPCO." The following table sets forth the high and low closing price
for the periods indicated. In early June 1996, the Company reversed its
stock 10 for 1. All prices shown below consider the split.
<TABLE>
<CAPTION>
High Low
<S> <C> <C>
1997
First quarter (through March 27) $2.25 $1.38
1996:
First quarter .78 .78
Second quarter 1.50 .78
Third quarter 1.38 .75
Fourth quarter .75 .75
1995:
First quarter 1.88 .63
Second quarter 1.80 .94
Third quarter .94 .63
Fourth quarter 1.00 .63
</TABLE>
The quotations reflect inter-dealer prices, without retail mark-up, mark-
downs or commissions and may not represent actual transactions.
During the last two years no dividends have been paid. The Company's Board
of Directors has no present intention to pay dividends in the foreseeable
future.
As of March 27, 1997 there were approximately 500 holders of record of the
Company's common stock and the closing price was $1.75.
<PAGE> 9
ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OR PLAN OF
OPERATION
The consolidated financial statements and the notes thereto contain detailed
information that should be referred to in conjunction with this discussion.
Substantially all of the Company's operations are attributable to the South
Cuyama Field. The value of the Company depends ultimately on the estimated
future cash flows from the Field. Management intends to maximize cash flow
by increasing oil production and keeping operating expenses low. Future
operations will also be affected by the results of the prospect development
and exploration activity discussed below.
The profitability of the Company's operations in any particular accounting
period will be directly related to: (i) prices, (ii) production, and (iii)
lifting costs. Accordingly, the results of operations of the Company may
fluctuate from period to period based on these factors, among others.
PROSPECT DEVELOPMENT AND EXPLORATION ACTIVITY
During 1996, management began purchasing undeveloped oil and gas properties.
Substantially all of the leases have been purchased based on geological leads
generated by consulting geologists and geophysicists.
Through December 31, 1996 and March 27, 1997, the Company has invested
$711,000 and $1,400,000, respectively, in these activities. These costs,
most of which represent high-risk, high-reward investments may or may not
prove successful.
SACRAMENTO BASIN - CALIFORNIA
The Company owns a 60% working interest (48% revenue interest) in a northern
California joint venture operated by Colorado-based Sharon Energy, Ltd.
Sharon trades on the Boston Stock Exchange (SHA) and the Vancouver Stock
Exchange (SHY). The joint venture contracted with Kemp Geophysical of
Houston, Texas to undertake the acquisition of approximately 14 square miles
of 3-D seismic on the Merlin Prospect in Glenn County. Initial
interpretation indicates there are up to six drillable prospects. The
Company expects to spud the first well during May 1997. Operators in the
area have achieved a better than 75% success rate using 3-D technology.
Management believes each well has the potential for two to four BCF.
BIG HORN BASIN - WYOMING
The Company operates a second joint venture designed to build exploration
prospects and acquire existing production in the Big Horn Basin of Wyoming.
Blackstone Energy, Inc. of Red Lodge, Montana is providing technical support
in exchange for an overriding royalty position. The 600-acre Hand Creek
Field (currently shut in) in Hot Springs County was purchased in October
1996. The Company has a 100% WI (80% NRI) in this prospect. Existing wells
within the field are currently being evaluated, and a new horizontal well or
a horizontal kick off from an existing wellbore is planned for late summer.
Oil in place is estimated to be 9.5 million barrels and recovery of oil to
date from the vertical wells is 119,000 barrels or 1.4%. A reservoir of this
type with horizontal drilling could recover an additional 10% (950,000
barrels) of the original oil in place.
<PAGE> 10
Several additional development and wildcat prospects are in various stages
of development in the Big Horn Basin. Seismic has been purchased on several
prospects, and the Company plans to shoot additional 2-D and 3-D seismic to
further define the drillable locations on each prospect area.
SOUTH CUYAMA FIELD
COLGROVE PROJECT
During March 1997, the Company completed a drilling project in the Field.
The 84-35 well (previously shut in) was deepened 500 feet to 4,700 feet into
the Colgrove formation. Production from the well commenced on March 15, 1997
and is producing 55 barrels of oil per day with no water. The cost to drill
and complete the well to the 100% was $140,000. The Company is evaluating
other infield locations and expects to deepen three to four additional
Colgrove wells during 1997. Pending the success of these deepening projects,
two new additional wells may be drilled at a cost of $300,000 per well. The
Company has an 80% working interest (63% net revenue interest), subject to
an 18% net profits interest to TCW.
3-D
The Company is evaluating shooting 3-D seismic over the Field and certain
nearby lands which could prove helpful in the Field's future development
including water flooding and deeper drilling. The Company also believes
other drillable prospects could be generated on undeveloped property which
adjoins the Field. Pending evaluation, the Company plans to form a joint
venture whereby an industry partner would pay a substantial cost of the
project.
WILLISTON BASIN, NORTH DAKOTA AND MONTANA
The Company is involved in several lease plays "on trend" with production in
the Williston Basin. The leasehold is being purchased on geological and
seismic leads with the intent of turning the acreage at a profit and
retaining an overriding royalty or carried interest.
<PAGE> 11
LIQUIDITY AND CAPITAL RESOURCES
TCW DEBT
The South Cuyama Field (the "Field"), the Company's principal asset, is
pledged by non-recourse debt to TCW. Eighty-five percent of the Company's
share of cash flow from the property is pledged to service the TCW debt.
Interest, at 9%, and principal are paid monthly. Using March 1997 prices,
the Company expects to receive approximately $30,000 per month of the cash
flow after payment to TCW.
Cash, short-term investments and cash to be provided from operations is
expected to enable the Company to meet its obligations as they become due
during the next several years.
RESULTS OF OPERATIONS
1996 vs. 1995
Higher prices explain the revenue increase and more than offset the decline
in gas sales resulting from lower production levels. Other than the expected
natural decline in the Field's gas production, management does not expect
further substantial downward revisions in gas reserves. See "Revisions to
Natural Gas and NGL Reserves" below.
<TABLE>
<CAPTION>
1996 1995 1996 1995
<S> <C> <C> <S> <C> <C>
Sales: Average Sales Price:
Oil (MBBLs) 220 225 Oil (per BBL) $19.55 $15.87
Gas (MMCF) 197 325 Gas (per MCF) 1.77 1.42
NGLs (MBLs) 39 44 NGLs (per BBL) 13.61 11.10
</TABLE>
General and administrative expenses increased due to annual meeting expenses
of $15,000, non-recurring expenses of $16,000, state taxes of $18,000, and
higher deferred bonus expense of $23,000. The Company did not have an annual
meeting in 1995 and state taxes were insignificant. No annual meeting is
planned for 1997.
Interest expense decreased due to the conversion of the convertible debt in
November 1995.
NONRECURRING ITEM RECORDED DURING THE 1995 FOURTH QUARTER
During the fourth quarter 1995, the Company accepted an offer for $150,000
from an insurance company representing the two hunters who were responsible
for starting a brush fire in the Field during July 1994. The fire required
the Company to close the Field for a few days, resulting in lost production,
and to repair or replace certain damaged equipment. In December 1995 the
Company received a $36,000 prepayment with the balance paid in January 1996.
The $150,000 is reflected as a reduction in 1995 lease operating expense.
Excluding the $150,000, the Company would have incurred a loss of $145,000
for 1995 as compared to a small profit of $5,000.
<PAGE> 12
1997 OUTLOOK
Assuming no success from the current exploration projects, the Company
projects 1997 net income to be substantially lower than 1996 reported net
income due to declining prices and production.
CALIFORNIA OIL PRICES
Now that it is permissible to export Alaskan North Slope (ANS) crude oil to
foreign countries, the Company believes California crude prices more fairly
represent free market prices.
On February 10, 1996, the President signed into law a bill which authorizes
the sale, within two years, of the Elk Hills Naval Petroleum Reserve located
in Kern County, California. The Company believes the sale may result in a
significant concentration of the ownership of the light crude oil used as
blending stock for the heavy crude oil produced in the San Joaquin Valley.
If such concentrations were to occur, it is possible the Company will
experience a favorable impact on its oil prices. As of March 27, 1997, the
Company was receiving $19.60 for its California oil production, which may or
may not continue throughout 1997.
ENVIRONMENTAL
With gas prices generally trending up and electrical costs trending down (due
to competition) the Company is evaluating electrification of the Field. An
added benefit of electrifying the Field would be less regulations and fees
to Santa Barbara County.
The Company is directly affected by changing environmental rules and
regulations. Although the Company believes its operations and facilities are
in compliance with applicable environmental regulations, risk of substantial
cost and liability 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 cost and liability in the future.
REVISIONS TO NATURAL GAS AND NGL RESERVES
During 1994, the natural gas reserves were significantly reduced;
furthermore, during the 1995 second quarter management concluded to further
reduce the gas reserves by 20% and another 20% reduction in gas reserves was
taken during the 1995 fourth quarter. These changes in estimates resulted
in a total downward revision to gas reserves from January 1, 1994 through
December 31, 1995 of 60%.
<PAGE> 13
In preparing the 1996 report, natural gas reserves were again revised
downward by 56% compared to the January 1, 1996 reserve estimates. During
January 1997, management concluded that all future gas production will come
primarily from gas associated with oil production. Although some dry gas
from the original "gas cap" is being produced, the reserves associated with
the "gas cap" are minimal. In view of the reduction in gas reserves, it was
also concluded to reduce the NGL reserves by 38%.
HEDGING ACTIVITIES
The Company continues to evaluate hedging strategies for its oil production
but has never entered into such transactions and at this time does not expect
to.
INFORMATION PERTAINING TO THE COMPANY'S COMMON STOCK PRICE
Because of the limited trading of the Company's common stock on the OTC
Bulletin Board, such prices may or may not reflect the fair market value.
The following data is provided solely for informational purposes and is only
one of many considerations that could be used in an investment decision
relating to the Company's securities.
Due partially to the SEC's ceiling test under full-cost accounting rules, the
Company has an accumulated deficit. Companies are prohibited from increasing
or reinstating the carrying costs of their oil and gas properties when prices
improve. If the Company was allowed to reinstate the carrying value of its
oil and gas properties to the ceiling limit amount disclosed in Note 6 to the
financial statements of $14 million (based on March 1997 prices), the
Company's equity would increase by $6.5 million and the book value per share
would increase to $1.73 from $.82. The fair value of the Company's oil and
gas properties could vary significantly, either more or less, from the PV10
amount of $14 million.
<PAGE> 14
ITEM 7. FINANCIAL STATEMENTS
Report of Independent Public Accountants
To Hallador Petroleum Company:
We have audited the accompanying consolidated balance sheet of Hallador
Petroleum Company as of December 31, 1996 and 1995, and the related
consolidated statements of income, cash flows and changes in stockholders'
equity for each of the two years in the period ended December 31, 1996.
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 generally accepted auditing
standards. 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 consolidated financial position of Hallador
Petroleum Company as of December 31, 1996 and 1995, and the consolidated
results of its operations and its cash flows for each of the two years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles.
ARTHUR ANDERSEN LLP
/S/ ARTHUR ANDERSEN LLP
Denver, Colorado
March 18, 1997
<PAGE> 15
HALLADOR PETROLEUM COMPANY
Consolidated Balance Sheet
(in thousands)
<TABLE>
<CAPTION>
December 31,
1996 1995
------- -------
ASSETS
<S> <C> <C>
Current assets:
Cash and cash equivalents $ 2,898 $ 3,459
Short-term investments 900
Accounts receivable-
Oil and gas sales 505 419
Well operations 365 331
Insurance claim 114
------- -------
Total current assets 4,668 4,323
------- -------
Oil and gas properties (full cost accounting),
at cost:
Unproved properties 711 246
Evaluated properties 39,527 39,316
Less - accumulated depreciation,
depletion, amortization and impairment (32,691) (32,118)
------- -------
7,547 7,444
------- -------
Other assets 165 159
------- -------
$ 12,380 $ 11,926
======= =======
</TABLE>
See accompanying notes.
<PAGE> 16
HALLADOR PETROLEUM COMPANY
Consolidated Balance Sheet
(in thousands, except share data)
<TABLE>
<CAPTION>
December 31,
1996 1995
------- -------
LIABILITIES AND STOCKHOLDERS' EQUITY
<S> <C> <C>
Current liabilities:
Accounts payable and accrued liabilities $ 317 $ 185
Oil and gas sales payable 169 39
Debt with recourse only to the
South Cuyama Field 590 670
------- -------
Total current liabilities 1,076 894
------- -------
Debt with recourse only to the
South Cuyama Field 5,231 6,203
------- -------
Deferred Bonus Plan (Note 4) 178 127
------- -------
Other 110 65
------- -------
Stockholders' equity:
Preferred stock, $.10 par value;
10,000,000 shares authorized;
no shares issued
Common stock, $.01 par value;
100,000,000 shares authorized;
7,093,150 (post-split) shares
issued and 70,982,723 (pre-split) 71 710
Additional paid-in capital 18,061 17,428
Accumulated deficit (12,347) (13,501)
------- -------
5,785 4,637
------- -------
$ 12,380 $ 11,926
======= =======
</TABLE>
See accompanying notes.
<PAGE> 17
HALLADOR PETROLEUM COMPANY
Consolidated Statement of Income
(in thousands, except per share data)
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995
---- ----
<S> <C> <C>
Revenue:
Oil $4,295 $3,577
Gas 350 462
NGLs 531 493
Interest and other 262 46
----- -----
5,438 4,578
----- -----
Costs and expenses:
Lease operating, net of insurance proceeds
of $150 in 1995 2,678 2,684
Depreciation, depletion
and amortization 573 606
General and administrative 438 373
Interest 595 910
----- -----
4,284 4,573
----- -----
Net income $1,154 $ 5
===== =====
Net income per share $ .16 $ .001
===== =====
</TABLE>
See accompanying notes.
<PAGE> 18
HALLADOR PETROLEUM COMPANY
Consolidated Statement of Cash Flows
(in thousands)
<TABLE>
<CAPTION>
Year ended December 31,
1996 1995
---- ----
<S> <C> <C>
Cash flows from operating activities:
Net income $ 1,154 $ 5
Depreciation, depletion, and
amortization 573 606
Convertible debt interest paid in stock 223
Change in accounts receivable (13) (109)
Change in payables and accrued
liabilities 265 (127)
Other (2) (9)
------ ------
Net cash provided by operating activities 1,977 589
------ ------
Cash flows from investing activities:
Short-term investments (900)
Evaluated properties (113) (97)
Unproved properties (468) (113)
Proceeds from property sales 354
Other assets (5) 4
------ ------
Net cash provided by (used in)
investing activities (1,486) 148
------ ------
Cash flows from financing activities:
Repayment of borrowings (1,052) (484)
Issuance of common stock, net 2,768
------ ------
Net cash provided by (used in)
financing activities (1,052) 2,284
------ ------
Net increase (decrease) in cash
and cash equivalents (561) 3,021
Cash and cash equivalents, beginning of year 3,459 438
------ ------
Cash and cash equivalents, end of year $ 2,898 $ 3,459
====== ======
Interest paid $ 595 $ 687
</TABLE>
See accompanying notes.
<PAGE> 19
HALLADOR PETROLEUM COMPANY
Consolidated Statement of Changes in Stockholders' Equity
(in thousands)
<TABLE>
<CAPTION>
Additional
Common Paid-in Accumulated
Stock Shares Capital Deficit
----- -------- -------- -----------
<S> <C> <C> <C> <C>
Balance at December 31, 1994 $ 77 7,661 $9,995 $(13,506)
Net income 5
Issuance of shares
in lieu of interest 25 2,470 345
Issuance of shares
in November for cash
(less issuance cost of $32) 280 28,000 2,488
Issuance of shares in
November for debt conversion 328 32,851 4,600
----- ------- ------ -------
Balance at December 31, 1995 710 70,982 17,428 (13,501)
Net income 1,154
Other (6)
10-for-1 reverse split (639) (63,889) 639
----- ------- ------ -------
Balance at December 31, 1996 $ 71 7,093 $18,061 $(12,347)
===== ======= ====== =======
</TABLE>
See accompanying notes.
<PAGE> 20
HALLADOR PETROLEUM COMPANY
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, collectively referred to herein as the
"Company". All significant intercompany accounts and
transactions have been eliminated. The Company is engaged in
the exploration, development and production of oil and natural
gas primarily in California. The Company also engages in the
trading and acquisition of non-producing oil and gas mineral
leases and fee-simple minerals in the Rocky Mountain Region.
The Company is a 92% partner in Santa Barbara Partners (SBP),
a general partnership, and accounts for its investment using
the proportionate consolidation method.
REVERSE SPLIT
During June 1996, the Company declared a 10-for-1 reverse
stock split. All pertinent data has been retroactively
adjusted to reflect the split.
OIL AND GAS PROPERTIES
The Company accounts for its oil and gas activities using the
full-cost method of accounting. Accordingly, all costs
associated with property acquisition, exploration and
development of oil and gas reserves are capitalized in one
cost center. Such costs are limited as required by the SEC.
Depreciation, depletion and amortization of the cost center is
computed on a composite units-of-production method based on
estimated proved reserves attributable to the cost center.
The amount of such amortization per equivalent barrel for 1996
and 1995 was $1.96 and $1.87, respectively.
Unless a significant amount (generally 25% or more) of
reserves is involved, gain or loss upon sale or disposition of
proved oil and gas properties is not recognized; rather, the
sales proceeds are credited to the full cost center.
SHORT-TERM INVESTMENTS
These investments classified as available for sale, consist of
U.S. Treasury obligations for which costs approximates market
value.
<PAGE> 21
STATEMENT OF CASH FLOWS
Cash equivalents include investments (primarily commercial
paper) with maturities of three months or less from the date
of purchase.
Other than the 1995 related party debt conversion of $4.9
million, there were no significant non-cash activities during
1996 and 1995.
INCOME TAXES
Income taxes are provided based on the liability method of
accounting pursuant to FAS 109, Accounting for Income Taxes.
The provision for income taxes is based on pretax financial
taxable income. Deferred tax assets and liabilities are
recognized for the future expected tax consequences of
temporary differences between income tax and financial
reporting and principally relate to differences in the tax
basis of assets and liabilities and their reported amounts,
using enacted tax rates in effect for the year in which
differences are expected to reverse. If it is more likely
than not that some portion or all of a deferred tax asset will
not be realized, a valuation allowance is recognized.
USE OF ESTIMATES IN THE PREPARATION OF FINANCIAL STATEMENTS
The preparation of financial statements in conformity with
generally accepted accounting principles requires management
to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent
assets and liabilities at the date of the financial
statements, and the reported amounts of revenue and expenses
during the reporting period. Actual amounts could differ from
those estimates.
(2) DEBT
TCW DEBT
The South Cuyama Field (the "Field"), the Company's principal
asset, is pledged by non-recourse debt to Trust Company of the
West (TCW). Eighty-five percent of the Company's share of
cash flow from the property is pledged to service the TCW
debt. Interest, at 9%, and principal are paid monthly.
(3) INCOME TAXES
The Company has the following tax carryforwards at December
31, 1996 (in thousands):
Statutory depletion $ 3,500
Tax net operating losses (NOLs), utilization
limited (expires in 1999-2003) 6,300
Tax NOLs, utilization not limited
(expires in 2005-2010) 3,900
The Company has fully reserved its net deferred tax asset of
approximately $3,200,000.
<PAGE> 22
(4) STOCK OPTIONS AND BONUS PLANS
STOCK OPTION PLAN
In December 1995, the Company granted 620,000 options to its
CEO and another 64,500 options to other employees at an
exercise price of $1.00. Under the plan, 750,000 may be
issued. The options vest 60% on grant date and the remainder
equally over three years, resulting in 502,000 and 410,700
options exercisable at December 31, 1996 and 1995,
respectively. Prior to the December 1995 grant, all options
outstanding were out-of-the-money and all such options were
canceled.
The Company accounts for its plans under APB 25, Accounting
for Stock Issued to Employees. Had compensation cost for the
plan been determined consistent with FAS 123, Accounting for
Stock-Based Compensation, the Company's 1995 net income and
earnings per share would have been reduced by $102,000 and
$.01, respectively; the 1996 effect was immaterial.
At December 31, 1996, six employees and the CEO held options
under the plan. During 1996, no options were granted,
exercised nor forfeited. Furthermore, during 1995, no options
were exercised nor forfeited.
The fair value of the options granted was $.24 per share using
the Black-Scholes option pricing model with the following
assumptions: risk-free rate of return of 5.4%, expected
average life of five years and an expected volatility of 10%.
401(K) PLAN
The Company maintains a 401(k) Plan which all full-time
employees are able to participate after six months of service.
The Company matches dollar-for-dollar up to 4% of all employee
contributions and vesting occurs immediately. The Company's
contributions for 1996 and 1995 were $27,000 and $24,000,
respectively.
DEFERRED BONUS PLAN
On October 1, 1996, the deferred bonus plan was amended. The
bonus compensation pool now accrues interest, based on a 30
day market rate. At present, Mr. Stabio, CEO, is the only
participant in the deferred bonus plan. Bonuses are computed
based on cash flow attributed to the South Cuyama Field.
Bonuses accrued for 1996 and 1995 were $51,000 and $25,000,
respectively. As of December 31, 1996, the amounts owing Mr.
Stabio are $178,000. The amounts owing will not be paid until
the earliest to occur of the following: (i) termination of
the participant's employment; (ii) the merger of the Company
into another entity or the sale by the Company of
substantially all of its assets; or (iii) the exercise by a
participant of any stock option issued by the Company which
requires a payment by the participant of more than $100,000.
The amounts accrued are unfunded and unsecured.
<PAGE> 23
(5) MAJOR CUSTOMERS
Over 96% of the Company's revenue is attributable to the
Field. For 1996 and 1995, the Field's oil production was sold
to KOCH and the gas and NGLs were sold to ARCO.
(6) OIL AND GAS RESERVE DATA (UNAUDITED)
The following reserve estimates were prepared by independent
petroleum engineers based on data supplied by management. The
Company cautions that there are many uncertainties inherent in
estimating proved reserve quantities and in projecting future
production rates. For each of the past two years, the gas
reserves had significant downward revisions.
Proved oil and gas reserves are the estimated quantities of
crude oil, natural gas and NGLs which geological and
engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved developed
oil and gas reserves are those reserves expected to be
recovered through existing wells with existing equipment and
operating methods.
The following reserve quantity and value information have been
reduced to reflect TCW'S 18% NPI.
<TABLE>
<CAPTION>
Analysis of Changes in Proved Reserves
(in thousands)
Oil Gas NGLs
(BBLs) (MCF) (BBLs)
------ ----- ------
<S> <C> <C> <C>
Balance at December 31, 1994 3,247 3,603 522
Revisions of previous estimates (9) (1,450) 5
Production (225) (325) (44)
----- ------ ----
Balance at December 31, 1995 3,013 1,828 483
Revisions of previous estimates 40 (1,026) (184)
Production (220) (197) (39)
----- ------ ----
Balance at December 31, 1996 2,833 605 260
===== ====== ====
</TABLE>
There are no significant proved undeveloped reserves.
<PAGE> 24
The following table sets forth a standardized measure of the
discounted future net cash flows attributable to the Company's
proved oil and gas reserves (hereinafter referred to as
"SMOG"). Future cash inflows were computed using December 31,
1996, 1995 and March 27, 1997 product prices. The Company is
currently receiving a $.30 per barrel premium in California
which management believes will continue indefinitely. This
agreement can be canceled by the purchaser with 180 days
notice. The $.30 premium was used in the preparation of the
SMOG data for the life of the property. 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>
March 1997 1996 1995
---------- ----- -----
(in millions, except prices)
<S> <C> <C> <C>
Future cash inflows $ 62 $ 72 $ 57
Future cash outflows -
production costs (38) (38) (40)
Future income taxes (2) (6)
----- ----- -----
Future net cash flows 22 28 17
10% discount factor (8) (11) (7)
----- ----- -----
SMOG $ 14 $ 17 $ 10
===== ===== =====
Year-end oil price $22.18 $15.91
Year-end gas price 4.17 1.61
Year-end NGLs prices 21.00 13.05
March 27, 1997 oil price $19.60
March 27, 1997 gas price (estimated) 1.90
March 27, 1997 NGLs price (estimated) 16.80
</TABLE>
The following table summarizes the principal factors
comprising the changes in SMOG:
<TABLE>
<CAPTION>
1996 1995
---- ----
(In millions)
<S> <C> <C>
SMOG, beginning of period $10 $13
Sales of oil and gas, net of production costs (2) (2)
Net changes in prices and production costs 13 1
Revisions of previous quantity estimates (4) (2)
Accretion of discount 1 1
Change in income taxes (3)
Changes in production rates and other 2 (1)
-- --
SMOG, end of period $17 $10
== ==
</TABLE>
<PAGE> 25
ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING -
FINANCIAL DISCLOSURE: None
PART III
ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS;
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
DAVID HARDIE, 46, is the Chairman of the Board and has served
as a director of the Company since July 1989. Mr. Hardie
serves as a director of Freedom Communications Inc., Irvine,
CA, a private company which publishes newspapers, magazines
and operates television stations. He serves as a director for
Pacific Grain Products, Inc., Woodland, CA, a private company
which manufactures rice and grain products. He is a General
Partner of Hallador Venture Partners, the General Partner of
Hallador Venture Fund II. He also serves as a director and
partner of other private entities which are owned by members
of his family.
VICTOR P. STABIO, 49, the Company's only executive officer, is
the President, Chief Executive Officer (CEO), Chief Financial
Officer and a director of Hallador Petroleum Company. Mr.
Stabio joined the Company on March 15, 1991 and was appointed
President and CEO on March 20, 1991. Mr. Stabio has been
active in the oil and gas business for the past 25 years.
STEVEN HARDIE, 43, was appointed to the Board of the Directors
on July 27, 1994. Mr. Hardie and David Hardie are brothers.
For the last 13 years Mr. Hardie has been a self-employed film
producer. He also serves as a director and partner of other
private entities which are owned by members of his family.
CORTLANDT S. DIETLER, 75, has been a Director of the Company
since November 1995. Since April 1995, he has been the
Chief Executive Officer of TransMontaigne Oil Company and is
Chairman of the Board. Mr. Dietler was the founder of Associated
Natural Gas Corporation and he served as its Chairman and Chief
Executive Officer until February 28, 1995. Mr. Dietler serves
as a director of Forest Oil Corporation, Key Production Company,
Grease Monkey Holding Corporation and PanEnergy
Corporation.
BRYAN H. LAWRENCE, 54, has been a Director of the Company
since November 1995. He has been employed by Dillon, Read &
Co. Inc., an investment banking firm (Dillon Read), since
January 1966; and is currently a Managing Director. Mr.
Lawrence also serves as a Director of Vintage Petroleum, Inc.,
D&K Wholesale Drug, Inc., Willbros Group, Inc., TransMontaigne
Oil Company (U.S. public companies), Benson Petroleum Ltd. and
Cavell Energy Corporation (Canadian public companies) and
certain non-public companies in which affiliates of Dillon
Read hold equity interests including Meenan Oil Co., Inc.,
Fintube Limited Partnership, Interenergy Corporation,
PetroSantander Inc., Strega Energy Inc., and Savoy Energy L.D.
<PAGE> 26
BOARD AND COMMITTEE INFORMATION
The Board of Directors of the Company held two meetings during
1996. Directors are not compensated for their services.
The Board of Directors has an Executive Committee consisting
of David Hardie, Bryan Lawrence and Victor Stabio; no meetings
were held during 1996. When the Board of Directors is not in
session, the Executive Committee may exercise all the powers
of the Board of Directors which may be delegated to a
committee under Colorado law.
The Board of Directors has an Audit Committee consisting of
David and Steven Hardie; no meetings were held during 1996.
The Audit Committee's purpose is to oversee the Company's
accounting and financial reporting policies and practices and
to assist the Board in fulfilling its fiduciary corporate
accountability responsibilities. The Company's independent
public accountants periodically meet with the Audit Committee
and always have unrestricted access directly to the Audit
Committee members.
The Board of Directors has a Compensation Committee consisting
of the two Hardie brothers and Mr. Lawrence; one meeting was
held in 1996. The Compensation Committee generally is charged
with administering, monitoring and evaluating the overall
compensation policies of the Company.
All meetings had full attendance.
<PAGE> 27
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
Long-term
Annual Compensation Compensation
-------------------------------------- -------------
Name and Other Annual Securities
Principal Compensation Underlying
Position (3) Year Salary Bonus (1) (2) Options
- ---------------- ---- -------- ------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Victor P. Stabio 1996 $103,000 $57,000 $3,600
President 1995 96,000 27,000 3,900 620,000
1994 86,000 36,000 3,400 5,746 (4)
</TABLE>
(1) Includes amounts, payment of which is deferred, pursuant to the Key
Employee Bonus Plan.
(2) Company's contribution to the 401(k) Plan.
(3) The Company has no other executive officers.
(4) These options were canceled in 1995.
No options were exercised during 1996. At December 31, 1996 Mr. Stabio had
455,000 exercisable and 165,000 unexercisable options; no options were
in-the-money. Using the March 27, 1997 closing price of $1.75, the
in-the-money exercisable options have a value of $341,000 and the
unexercisable options have a value of $124,000.
CHANGE-IN-CONTROL ARRANGEMENTS
As of December 31, 1996, Mr. Stabio has accrued $178,000 pursuant to the
Company's deferred bonus plan which on the merger of the Company into another
entity or the sale by the Company of substantially all of its assets will
become payable.
<PAGE> 28
ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The following table sets forth certain information, as of March 27, 1997,
with respect to shares held or controlled by the Company's directors. This
table should be read with the understanding that the Company's only executive
officer is also a director and persons owning more than 5% of the outstanding
shares are affiliated with one or more of the Company's directors. Except
as noted below, all shares are owned directly, and the owner has sole voting
and investment power with respect to such shares.
<TABLE>
<CAPTION>
Name No. Shares % of Class (1)
______________________________ ____________ ______________
<S> <C> <C>
David Hardie and Steven Hardie 3,791,000 53
as Nominee for Hardie Family
Members (2)
Victor P. Stabio (3) 520,000 7
Cortlandt S. Dietler (4) 100,000 1
Bryan H. Lawrence (5) 2,700,000 38
All directors as a group 7,111,000 94
</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 of these shares has 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, CA 95825. Includes 2,157,098 shares held by David and Steven
Hardie as nominee for Hardie Family Members; 298,316 shares held by
Hallador, Inc., 392,871 shares held by Hardie Descendants Trust; 864,364
shares owned by the Intervivos Trust FBO Robert Hardie; and
78,610 shares owned by David Hardie.
(3) Includes 454,666 shares issuable upon the exercise of certain options
through May 27, 1997 held 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 Dillon, Read & Co. Inc., 535 Madison Avenue,
New York, New York 10022. Also includes 411,500 shares held by Yorktown
Energy Partners II, L.P., 10,000 shares owned by Lexington Partners, and
2,278,500 shares owned by Dillon, Read & Co. Inc. of which Mr. Lawrence
is affiliated.
<PAGE> 29
ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Mr. Lawrence, one of the Company's directors, is a Managing Director of
Dillon, Read & Co. Inc., an investment banking firm. On November 28, 1995,
the Company sold 2.7 million shares to an investor group affiliated with
Dillon, Read & Co. Inc. for $2.7 million. Concurrently, the convertible debt
and accrued interest due the Hardie family and certain others was converted
to common stock at $1.50 per share, resulting in 3.53 million shares being
issued. During 1995, the Company paid interest to the Hardie family and
their affiliates $329,000 in the form of common stock and $39,000 in cash.
The Hardie family and their affiliates own approximately 53% of the common
stock and the Dillon, Read group owns approximately 38%. Mr. Dietler, one
the Company's directors, also purchased 100,000 shares for $100,000 November
28, 1995. All data above has been adjusted to reflect the 1996 10-for-1
reverse split.
PART IV
ITEM 13. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits (Management contracts or compensatory plans are indicated by
an asterisk.)
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.
(6)
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. (5)
10.3 --Agreement, dated September 18, 1991, among Cuyama Oil & Gas
Company, Stream Energy, Inc. and Hallador Production Company,
including Exhibit A, Agreement Regarding Term Loan Agreement,
among Santa Barbara Partners, Hallador Production Company, Trio
Petroleum, Inc., and Trust Company of the West, and Exhibit B,
Assignment of Partnership Interest, between Cuyama Oil & Gas
Company and Hallador Production Company. (3)
<PAGE> 30
10.4 --Modifications to the TCW loan agreement were filed on a Form 8
Amendment dated April 24, 1992 to the 1991 Form 10-K. (4)
10.5 --*Hallador Petroleum Company Key Employee Bonus Compensation Plan.
(5)
10.6 --ARCO Gas Agreement. (7)
10.7 --ARCO NGL Agreement. (7)
10.8 --KOCH Oil Contract. (7)
10.9 --*First Amendment to the 1993 Stock Option Plan. (8)
10.10--*First Amendment to Key Employee Bonus Compensation Plan. (8)
10.11--Stock Purchase Agreement dated November 15, 1995. (8)
10.12--*Second Amendment to Key Employee Bonus Compensation Plan. (9)
21.1 --List of Subsidiaries. (2)
27.1 --Financial Data Schedule. (10)
(1) Incorporated by reference (IBR) to the 1989 Form 10-K.
(2) IBR to the 1990 Form 10-K.
(3) IBR to Form 8-K dated October 15, 1991.
(4) IBR to the 1991 Form 10-K, as amended.
(5) IBR to the 1992 Form 10-KSB.
(6) IBR to the 1993 Form 10-KSB.
(7) IBR to the 1994 Form 10-KSB.
(8) IBR to the 1995 Form 10-KSB.
(9) IBR to the September 30, 1996 Form 10-QSB.
(10) Filed herewith.
Stockholders may obtain a copy of any listed exhibit by writing to Teressa
Jones, Secretary of the Company. Reasonable expenses will be charged for
copies and postage. 1995 and 1996 exhibits can also be obtained via EDGAR
at the SEC's web site: www.sec.gov.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the 1996 fourth quarter.
<PAGE 31>
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, CEO
-------------------------
VICTOR P. STABIO, CEO
Dated: March 27, 1997
In accordance with the Exchange Act, this report has been signed below by the
following persons on behalf of the registrant and in the capacities and on
the dates indicated.
/S/ DAVID HARDIE Chairman March 27, 1997
- ----------------------
DAVID HARDIE
/S/ VICTOR P. STABIO CEO, Principal Financial March 27, 1997
- ----------------------- and Accounting Officer
VICTOR P. STABIO and Director
/S/ BRYAN H. LAWRENCE Director March 27, 1997
--------------------
BRYAN H. LAWRENCE
<PAGE> 32
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Balance Sheets and the Companys Statement of Income found in the
Company's Form 10-KSB for the year-to-date, and is qualified in its entirety
by
reference to such financial statements.
</LEGEND>
<CIK> 0000788965
<NAME> HALLADOR PETROLEUM COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-1-1996
<PERIOD-END> DEC-31-1996
<CASH> 2,898
<SECURITIES> 900
<RECEIVABLES> 870
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 4,668
<PP&E> 40,238
<DEPRECIATION> 32,691
<TOTAL-ASSETS> 12,380
<CURRENT-LIABILITIES> 1,076
<BONDS> 5,231
0
0
<COMMON> 71
<OTHER-SE> 5,714
<TOTAL-LIABILITY-AND-EQUITY> 12,380
<SALES> 0
<TOTAL-REVENUES> 5,438
<CGS> 0
<TOTAL-COSTS> 4,284
<OTHER-EXPENSES> 0
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