SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
------- EXCHANGE ACT OF 1934 (FEE REQUIRED)
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
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or
------- Transition Report Pursuant To Section 13 or 15 (d) of the Securities
Exchange Act of 1934
(No Fee Required)
Commission file number 1-8975
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PLAINS PETROLEUM COMPANY
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(Exact name of registrant as specified in its charter)
Delaware 84-0928792
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
12596 West Bayaud
P.O. Box 281306, Lakewood, Colorado 80228
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (303) 969-9325
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
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Common stock, par value $.01 per share New York Stock Exchange
Rights pursuant to preferred stock rights New York Stock Exchange
purchase agreement
Securities registered pursuant to Section 12(g) of the Act: NONE
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(Title of Class)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports, and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
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State the aggregate market value of the voting stock held by non-affiliates of
the registrant.
_______________ $222,200,000 as of March 15, 1995 _________________
Indicate the number of shares outstanding of each of the registrant's classes of
common stock, as of the latest practicable date.
_______________ 9,815,826 as of March 15, 1995 _________________
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not 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-K or any amendment to this
Form 10-K. X
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PLAINS PETROLEUM COMPANY
INDEX TO FORM 10-K
PART I PAGE
Item 1: Business 3-8
Item 2: Properties 8-13
Item 3: Legal Proceedings 13
Item 4: Submission of Matters to a Vote of 14-15
Security Holders
PART II
Item 5: Market for Registrant's Common Equity 15
and Related Stockholder Matters
Item 6: Selected Financial Data 16
Item 7: Management's Discussion and Analysis of 17-20
Financial Condition and Results of Operations
Item 8: Financial Statements and Supplementary Data 21-42
Item 9: Disagreements on Accounting and Financial 43
Disclosure
PART III
Item 10: Directors and Executive Officers of the 43-44
Registrant
Item 11: Executive Compensation 45-49
Item 12: Security Ownership of Certain Beneficial 50-51
Owners and Management
Item 13: Certain Relationships and Related Transactions 52
PART IV
Item 14: Exhibits, Financial Statement Schedules, and 53-60
Reports of Form 8-K
Signatures 61
PART I
ITEM 1: BUSINESS
(A) GENERAL DEVELOPMENT OF BUSINESS
Plains Petroleum Company (Plains) was incorporated as a wholly-owned
subsidiary of K N Energy, Inc. (K N) in 1983. Plains was formed to own and
operate substantially all of K N's then remaining gas and oil producing
properties. In 1985, K N distributed its Plains stock to the K N shareholders
which resulted in K N no longer holding an ownership position in Plains and in
the trading of Plains' stock on the New York Stock Exchange as a separate and
distinct entity. In 1986, Plains Petroleum Operating Company (PPOC) was formed
as a wholly-owned subsidiary of Plains. Plains Petroleum Gathering Company
(PPGC) was incorporated in 1992 as a wholly-owned subsidiary of PPOC. Plains,
PPOC and PPGC are hereinafter referred to collectively as the "Company".
During the latter part of 1994, another oil and gas firm, Cross
Timbers Oil Company, acquired 6.6 percent of the Company's outstanding stock and
announced it was considering, among other things, a business combination with
the Company. To assure the best possible result to shareholders in such an
event, the Board of Directors authorized its financial advisors, Goldman,
Sachs & Co. and Batchelder & Partners, to study the alternative of a stock-
for-stock merger with a select group of public companies in the energy industry.
Although discussions with a number of possible merger partners have taken place,
the Board has not received a proposal that it is prepared to recommend to the
Company's shareholders. As a result, the study of possible business
combinations was expanded on February 28, 1995 to increase the group of
possible merger partners and to consider transactions involving the acquisition
of the Company for cash or a combination of cash and securities. The expanded
study process is expected to be concluded by late spring. If the process does
not yield a proposal that the Board of Directors believe is in the
shareholders' best interests, then the Company will continue to pursue its
independent strategy of growth through acquisition, exploration and
development.
In 1994, the Company acquired proved natural gas reserves of 20.3
billion cubic feet (Bcf) and 2-1/2 million barrels of oil. The most significant
acquisition during the year was completed on November 1 with the purchase of 15
Bcf of proved natural gas reserves and 2.3 million barrels of proved oil
reserves located in Colorado, Wyoming, Montana, North Dakota and Utah for
approximately $22 million. In addition, the Company purchased interests in an
oil pipeline and 50,000 undeveloped acres for approximately $2 million.
Other smaller 1994 acquisitions included a March purchase for $1.7
million of interests in seven producing natural gas wells with approximately
2-1/2 Bcf of natural gas proved reserves in Wyoming's Washakie Basin. This
acquisition was in connection with PPOC's participation in a natural gas
development program. In September, a $1.825 million acquisition was completed
of nine natural gas wells located in Oklahoma, with estimated net proved
reserves of 2.35 Bcf.
During 1994, the Company added proved reserves, excluding the
acquisitions noted above, of approximately 16.6 Bcf of natural gas and 3 million
barrels of oil through its exploitation and exploration programs.
3
Item 1 (continued)
In 1993, the Company acquired interests in certain producing oil and
gas properties principally located in Wyoming's Powder River Basin for
approximately $1.7 million. In addition, an estimated obligation of $2-1/2
million for contingent consideration related to a 1990 merger transaction was
recognized in the 1993 property costs. The contingent provisions of the
transaction were completed in May 1994 with the issuance of the Company's common
stock and cash valued at $2-1/4 million.
In 1992, the Company acquired producing oil properties located in
Wyoming for approximately $12 million, adding estimated proved reserves of
approximately 2 million barrels of oil.
In 1991, the Company acquired certain oil and gas properties located
in the Permian Basin of west Texas and southeast New Mexico for $17 million.
The purchase, together with additional interests acquired in certain west Texas
oil properties, resulted in total spending of approximately $19 million for
estimated proved reserves of nearly 5 million equivalent barrels of oil.
In 1990, the Company acquired McAdams, Roux and Associates, Inc. (MRA)
by issuing common stock and assuming MRA's bank debt, liabilities and deferred
income taxes in exchange for all of the outstanding common stock of MRA. During
1990 the Company also acquired oil and gas properties in west Texas and
southeastern New Mexico and additional operating interests in west Texas and
Wyoming. These acquisitions added estimated proved reserves of 4.8 million
barrels of oil and 8.7 Bcf of gas.
(B) FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS
The Company's business, as conducted through December 31, 1994, is in
a single industry segment.
(C) NARRATIVE DESCRIPTION OF BUSINESS
(1) GENERAL
The Company is an oil and gas exploration, development and production
company with interests in 653 producing gas wells and 853 producing oil wells
located on approximately 344,500 gross (240,500 net) acres held by production
with proved reserves of 312 Bcf of gas and 11 million barrels of oil at
December 31, 1994. The reserves are located in the lower 48 states, principally
in the Kansas and Oklahoma portions of the Hugoton field, the Permian Basin of
west Texas and southeastern New Mexico and in the Powder River and Green River
Basins of Wyoming. See "Properties" in Item 2. In 1994, approximately 47% of
the Company's gas revenues (approximately 34% of total revenues) came from sales
made to K N, its principal purchaser, under a long-term natural gas purchase
contract. See "Marketing" in section (3) below.
The Company is headquartered in Lakewood, Colorado with additional
offices in Midland, Texas; Lakin, Kansas; and Gillette, Wyoming. Annual rent
expense for office and storage facilities was $544,000, $515,000 and $507,000
for 1994, 1993 and 1992, respectively. See Note Six of the Notes to
Consolidated Financial Statements in Part II, Item 8 of this report on Form 10-K
for further information on lease terms and annual rental commitments. As of
March 15, 1994, the Company employed 82 people.
4
Item 1 (continued)
On February 17, 1995, the Company entered into a new credit agreement
for a $150 million unsecured, revolving bank line, replacing the previous $60
million line of credit. The new bank line has an initial borrowing base
limitation of $110 million, which will be redetermined annually. Under the new
agreement, outstanding borrowings at the end of the revolving period in January
1997 convert to a term loan. See Note Three of the Notes to Consolidated
Financial Statements in Part II, Item 8 of this report on Form 10-K for further
information on the line of credit terms.
(2) OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
The Company's oil and gas development and production operations are
conducted principally on-shore in the geographic locations indicated in
"General", section (1) above. In addition, primary exploration areas include
the Green River Basin of Wyoming, the Gulf Coast region and west Texas.
Prospects are identified for acreage acquisition and for exploratory
or developmental drilling primarily through in-house staff geologists,
geophysicists, landmen and petroleum engineers. This staff directs various
seismic and other geological and geophysical tests on prospective oil and gas
properties and, based on its analysis of the data provided by such tests,
evaluates such properties and directs the acquisition of oil and gas leases or
interests in drilling prospects. Prospects are acquired by purchasing oil and
gas leasehold interests from other companies or directly from landowners in
areas considered favorable for oil and gas exploration and by participating in
projects and prospects that permit the Company to earn an ownership interest in
leases owned by others in consideration for performing or participating in
certain drilling operations.
The Company typically conducts drilling activities with other
companies as joint working interest owners in order to increase its
participation in different prospects and to reduce the concentration of risk
through diversification. Under the terms of these joint operating arrangements,
one of the working interest owners acts as the operator in charge of the day-to-
day management of the properties and is paid a fee and certain expenses by the
other working interest owners. The Company is generally the operator of
properties in which it generates interests. Where it acts as operator, the
engineering staff directs the drilling of test wells and supervises the
development and operation of properties for the production of oil and gas. It
contracts with independent drilling contractors to perform the actual drilling
and completion of the wells.
Historically, the Company has directed most of its expenditures toward
drilling development wells; that is, wells located in fields having proved oil
or gas reserves. Drilling development wells generally involves fewer risks and
meets with a higher degree of success than exploratory drilling. Cash provided
by operations is expected to sufficiently fund the Company's 1995 capital
spending program, which includes approximately $7-1/2 million for exploration
activities.
The Company continues to seek additional acquisition opportunities.
Supported by its $150 million bank credit line and its market capitalization,
the Company has the financing capability to pursue such opportunities as they
become available. For 1995, the Company has targeted acquiring $25 million of
oil and gas properties. See "Competition" in section (4) below.
5
Item 1 (continued)
(3) MARKETING
(i) GAS
Approximately one-half of the Company's total gas revenues were
generated under a long-term contract for sales from the Hugoton field in
southwestern Kansas and a contract covering the Niobrara area of
northeastern Colorado. This production was sold at a wellhead price of $2.00
per million British Thermal Unit (MMBtu) for the five months (January through
March, November and December) of the 1994 heating season and $1.80 and $1.75
per MMBtu for the balance of the year for the Hugoton field and Niobrara field,
respectively. Gathering, transportation, dehydration, processing and other
similar costs of marketing are included in wellhead prices. Spot market sales
are burdened by these marketing costs, which range from 15 cents to 40 cents
per MMBtu in the Rocky Mountain and Mid-continent areas. A second major
customer purchased natural gas representing approximately 11% of total oil and
gas revenues. No other single customer purchased gas which accounted for more
than 10% of the Company's total revenues.
In the annual price redetermination of its long-term gas sales
contract with its principal purchaser, the Company negotiated a two-tier
seasonal price arrangement for 1995. Under this agreement, the Company will
sell 14 Bcf of natural gas to K N at a weighted average wellhead price for 1995
of $1.80 per MMBtu. Another 2-1/2 Bcf will be sold to K N on a spot market
basis. In 1994, the Company negotiated the release of 66 Hugoton field wells
connected to Company-owned gathering lines covered by this contract. Another 37
wells were released for 1995. The contract covering Niobrara production was
not renewed for 1995. The gas from these wells will be sold on the spot
market to third parties. Negotiations with the principal purchaser for 1996
prices under the long-term contract will begin in late 1995.
Through its marketing department, the Company sells the balance of its
gas supplies to various purchasers under percentage of proceeds, short-term or
spot sales and limited term contracts of up to one year in duration. Prices for
these sales are negotiated between the buyer and seller and depend upon the
length of the term during which the supplies are committed and the supply-demand
conditions in both the geographic area where the gas is produced and the market
area where it is consumed.
Federal price controls of natural gas expired on January 1, 1993
pursuant to the Natural Gas Wellhead Decontrol Act of 1989.
(ii) OIL AND CONDENSATE
Oil, including wellhead condensate production, is generally sold from
the leases at currently posted field prices. Due to its increased oil
production, the Company has negotiated with purchasers prices with bonuses in
excess of the posted price. In 1994, these bonuses added a total of $1.6
million in revenues. Marketing arrangements are made locally with purchasers,
who are various petroleum companies. The Company sells its oil production to
numerous customers. No customer's total 1994 oil purchases represented more than
10% of total Company revenues. Oil revenues totaled $17.2 million for 1994 and
represented 28% of the Company's total revenues for the year.
6
Item 1 (continued)
(4) COMPETITION
The Company faces strong competition in all phases of its operations
from major oil and gas companies, independent operators and other entities,
particularly in the areas of acquisition of oil and gas properties and
undeveloped leases and marketing of crude oil and natural gas. Many of these
competitors have financial resources, operating staffs, geological and
geophysical data and facilities substantially greater than those of the Company.
Furthermore, there exists many factors which may impact the production, process-
ing and marketing of crude oil and natural gas that are beyond the control of
the Company and cannot be accurately predicted. One of many factors is the
significant influence of foreign producers on the production and pricing of
crude oil. The demand for viable prospects available for exploration and
development of oil and gas reserves as well as the necessary supportive servic-
ing equipment and experienced personnel continues to be intense. Although the
Company believes it has adequate financial and operating resources to remain
competitive, there is no assurance of the continued availability of these
resources, and consequently, it may be at a significant disadvantage with its
competitors.
(5) OPERATING HAZARDS
The Company's operations are subject to all the risks normally
incident to the exploration for and production of oil and gas, including
blowouts, encountering formations with abnormal pressure, cratering, pollution
and fires. Any of these events could result in damage to, or destruction of,
oil and gas wells or producing facilities, suspension of operations, damage to
property or the environment, and injury to persons. Losses and liabilities
arising from such events could reduce revenues and increase costs to the extent
the Company is liable and such loss or liability is not covered by insurance.
The Company maintains insurance which it believes is customary in the industry
against some, but not all, of these risks. There is no assurance that such
insurance will continue to be available in the future at a reasonable cost.
(6) ENVIRONMENTAL, PRODUCTION AND PRICE REGULATION
The states where the Company operates control production from oil and
gas wells. State conservation statutes or regulations require drilling permits,
establish the spacing of wells, allow the pooling and unitization of properties
and limit the rate of allowable production. Such conservation regulations have
not had a material adverse effect on the Company's operations in the past, and
management does not anticipate that they will in the future.
The Company, as an owner and operator of oil and gas properties, is
subject to various federal, state and local laws and regulations relating to the
protection of the environment. These laws and regulations may, among other
things, impose liability on an oil and gas lessee for the cost of pollution
clean-up and pollution damages to the property of others, require suspension or
cessation of operations in affected areas and impose restrictions on the
injection of liquids into subsurface aquifers that may contaminate groundwater.
7
Item 1 (continued)
The Company has made and will continue to make expenditures to comply
with these requirements, which are necessary costs of doing business in the oil
and gas industry. As part of the Company's commitment to environmental
responsibility, it has adopted a corporate environmental policy, and retained
the services of an independent consulting firm to conduct an initial audit of
Company properties and train operations and professional employees in environ-
mental awareness, as well as in preventative and remedial work, when appropri-
ate. Environmental requirements have a substantial impact upon the energy
industry; however, these requirements do not appear to affect the Company any
differently or to any greater or lesser extent than other companies in the
industry as a whole.
At present, there are no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. The Company believes that
expenditures for compliance with current federal, state or local provisions
regulating the discharge of materials into the environment, or otherwise
relating to the protection of the environment, will not have a material adverse
effect in the future upon the capital expenditures, earnings or competitive
position of the Company.
ITEM 2: PROPERTIES
(A) LOCATION AND CHARACTER OF PROPERTIES
The Company had an interest in 1,506 wells as of December 31, 1994 and
operated 772 of those wells.
Number of Wells Gross Net
--------------- ----- ---
Gas 653 471
Oil 853 292
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Total 1,506 763
----- ---
----- ---
Most of the Company's wells and associated reserves are located in the
Hugoton field in southwest Kansas and the Oklahoma panhandle, the Permian Basin
of west Texas and southeastern New Mexico and the Powder River and Green River
Basins of Wyoming. The wells are located on leases held by production.
Gross acres are the total number of acres in which the Company owns a
working interest; net acres are the sum of the fractional working interests
owned by the Company in gross acres. Acreage is deemed to be developed if it is
either held by existing production or is part of a unit held by existing
production. At yearend, 344,455 gross and 240,548 net acres were held by
production, and 229,412 gross and 99,974 net acres were held for exploration.
KANSAS
The majority of gas production is generated from the Company's
interest in wells (394 gross, 322 net) located in two fields in Kansas.
Approximately 71% of the Company's total proved producing gas reserves are
located in the Hugoton field, the larger of the two fields. The Company
operates 275 wells of the 323 Hugoton wells in which it has an interest.
8
Item 2 (continued)
The Kansas Corporation Commission ruled in 1986 that optional infill
drilling is permitted in the Chase group of the Hugoton field. Infill drilling
allows a second well to be drilled in each unit. Units are generally 640 acres
in size. The Company has participated in or drilled 121 infill wells, all of
which are currently producing.
Recently, the Company drilled two horizontal legs to an old Hugoton
field well with relatively weaker deliverability. Should this effort prove
successful, it could enhance the economics of drilling on 55 of the Company's
remaining potential infill locations and provide opportunities of adding
horizontal legs on a number of the older wells.
WYOMING
The Company has an interest in 406 gross wells (86 net wells) located
in the Powder River, Washakie and Greater Green River Basins of Wyoming. In
addition to the acquisition of Wyoming properties described in Item 1, the
Company participated in various exploitation and exploration projects.
In November 1994, the Snowbank No. 1, an Almond formation discovery
in the Washakie Basin in Carbon County, was completed. It was connected to a
temporary pipeline in late January 1995 and is currently producing 1.12 MMcf of
natural gas per day. The Company operates this well and has a 50 percent
working interest. Approximately 12,000 acres surrounding this well are con-
trolled by the Company and its co-venturers. Further development of this
acreage will begin after evaluation of the discovery well's production.
Under a development program commenced in 1993, the Company
participated as a 50% working interest owner in the drilling of fourteen natural
gas wells to the Almond-Mesaverde formation in Washakie Basin. Eight wells were
completed and four are on production. Five wells are awaiting completion or a
pipeline connection. One well was unsuccessful. In March 1994, the Company
acquired, for $1.7 million, interests in seven wells drilled in the Washakie
Basin prior to 1994. Due to current low natural gas prices, the 1995 drilling
program with the co-owner has been reduced to four wells.
TEXAS
As of December 1994, the Company had an interest in 323 gross wells
(213 net wells) located in Texas. During 1994, the Company's exploitation and
exploration activities included the participation in five successful exploratory
wells located in Dawson County. These prospects were identified through the use
of three-dimensional seismic technology. Drilling of a second offset well
commenced in late January 1995. The Company has a 10 percent working interest
in this project. In 1995, the Company plans to drill six additional west Texas
exploratory prospects.
9
Item 2 (continued)
The Company acquired a working interest (80 percent before payout; 50
percent after payout) in a waterflood project in the Moss Grayburg San Andres
Unit located in Ector County. Six producing wells and six water injection wells
were drilled in 1994. Three other wells were recompleted as water injection
wells. The Company plans to join in two additional Ector County waterflood
projects in 1995.
LOUISIANA
The first of two exploratory prospects begun in 1994, the Patterson
Deep Prospect in St. Mary Parish, was completed as a dry hole in the first
quarter of 1995. The Company's share of dry hole costs approximated $600,000.
Drilling on a second prospect, South Perry Point in Acadia and Vermillion
Parish, is expected to reach its total depth in the second quarter of
1995.
The 1992 discovery well of the Ship Shoal Block 45 field in shallow
state waters offshore Louisiana was placed on production in September 1993 after
a second well was completed. Three additional wells were drilled in 1994, two
of which were placed on production in August and one in late December. The
Company has a 33 percent working interest (25 percent net revenue interest) in
this project. For 1995, the Company plans to continue its exploratory efforts
in the Gulf of Mexico.
OTHER ACTIVITIES
The Company joined in the drilling of a Morrow well located in Eddy
County, New Mexico and two Simpson-McKee wells and a Devonian well located in
the Teague field in Lea County. These wells were placed on production in 1994.
Other 1994 New Mexico exploitation projects included the recompletion of eight
wells to the P1 formation in the Bluitt area of Roosevelt County and the
drilling of four Niobrara wells in northeastern Colorado.
In a joint venture effort, the Company participated in a project to
develop infill locations identified using three-dimensional seismic technology
in the Eagle Springs field located in Nye County, Nevada. Two wells were
drilled and completed in 1994 and a third was placed on production in mid-
January 1995. The Company has a 40 percent working interest in the three new
wells and, after spending an additional $432,000 on drilling, will earn a 40
percent working interest in the remainder of the field. Four additional wells
are planned in 1995.
10
Item 2 (continued)
DRILLING ACTIVITY
The following table sets forth the Company's drilling activity for
each of the three years ended December 31, 1994.
Development Exploratory Total
Wells Wells Wells
----------- ----------- -------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
1994 - Total 46 27 16 3 62 30
- Successful (2) 36 23 6 1 42 24
1993 - Total 23 16 9 3 32 19
- Successful (2) 17 15 1 1/10 18 15
1992 - Total (1) 56 40 10 4 66 44
- Successful (2) 50 36 1 1/3 51 36
<FN>
(1) In addition, nine wells were successfully recompleted in new formations.
(2) A successful well is an exploratory or a development well found to be
capable of producing either oil or gas in sufficient quantities to justify
completion of the well for the production of oil or gas.
Proved reserves added from extensions, discoveries and other additions
in each year were as follows:
Gas (MMcf) Oil (MBbls)
---------- -----------
1994 19,639 2,297
1993 6,288 1,194
1992 1,993 171
<FN>
Note: MMcf = million cubic feet
MBbls = thousand barrels
(B) DISCLOSURE OF OIL AND GAS OPERATIONS (provided in accordance with
the Securities Act Industry Guide 2 and including information in
Item 2 (A) above))
(1) OIL AND GAS RESERVES
All of the Company's proved developed reserve quantities of 292 Bcf of
gas and 7.5 million barrels of oil were estimated at yearend 1994 by Netherland,
Sewell & Associates, Inc., an independent petroleum engineering firm. Proved
undeveloped reserves were estimated to be 20.1 Bcf and 3.5 million barrels by
the Company's petroleum engineers and amounted to approximately 11% of total
proved reserve equivalents at December 31, 1994. Proved developed reserve
quantities in prior years were estimated annually by independent petroleum
engineers. The Company's reserves are located in the lower 48 states, princi-
pally in the Kansas and Oklahoma portions of the Hugoton Field, the Permian
Basin of west Texas and southeastern New Mexico, and in the Powder River and
Green River Basins of Wyoming.
11
Item 2 (continued)
The report of the independent petroleum engineering firm provides
estimated proved developed reserves and future revenues as of December 31, 1994
and includes an estimate of proved developed reserves established by the
Company's infill drilling in the Kansas Hugoton Field. Reserve estimates for
infill wells are based upon the initial test results and the completion report
of each newly completed well rather than an extrapolation of field-wide data.
However, no proved undeveloped reserves for the Hugoton Field are included in
the Company's estimate.
The reserve quantities are estimates of the Company's net volumes
which can be expected to be recovered commercially at current prices and with
existing conventional equipment and operating methods. Proved developed
reserves are only those reserves expected to be recovered from existing wells.
Proved undeveloped reserves include those reserves expected to be recovered from
new wells and improved recovery projects where additional expenditures are
required.
At December 31, 1994, the Company believes that there are no material
estimated future dismantlement and abandonment costs for its properties. For
the purpose of computing the discounted future net cash flows, estimated future
dismantlement and abandonment costs are assumed to equal the estimated salvage
values of the properties.
For further information on the Company's reserves, see Note Eight of
the Notes to Consolidated Financial Statements in Part II, Item 8 of this report
on Form 10-K.
(2) RESERVES REPORTED TO OTHER AGENCIES
The Company will file the Annual Survey of Domestic Oil and Gas
Reserves with the Energy Information Administration (EIA) as required by law.
Only minor differences of less than five percent are anticipated in reserve
estimates, which were due to small variances in actual production versus yearend
estimates, and in certain classifications reported in Form 10-K as compared to
those in the EIA report.
(3) GAS PRODUCTION, SALES PRICES AND PRODUCTION COSTS
The following table sets forth the average sales price of gas and oil
produced and sold and the average production costs per thousand cubic feet
equivalent (Mcfe) of gas for each of the periods presented.
Average Average
Gas Sales Price Oil Average Production
Production Per Production Sales Price Cost Per
(MMcf) Mcf (MBbls) Per Bbl Mcfe(a)
---------- ----------- ---------- ----------- ----------
1994 23,925 $1.86 1,236 $13.91 $.79
1993 23,757 1.94 1,220 14.83 .88
1992 21,654 1.83 1,039 18.20 .91
<FN>
(a) Includes lease operations expense, production and property taxes, transpor-
tation and processing and net profit and gas trust payments. Mcfe is
calculated on the basis of 6 Mcf per 1 barrel of oil. Net profit and gas
trust payments are described in (5) and (6) below.
12
Item 2 (continued)
(4) FUTURE NET CASH FLOWS
At yearend 1994, the pre-tax present value (discounted at 10%) of
future net cash flows from proved reserves was $235 million, with gas represent-
ing 83% and oil 17% of proved reserves. Net cash flows from properties under
the K N contract were computed using (1) the price which was renegotiated with
KN for 1995 and (2) yearend costs. Net cash flows from other properties used
yearend prices or prices under production sales contracts and yearend costs.
The discount factor was applied on a year-by-year basis utilizing anticipated
sales over the life of the reserves. Additional information concerning the
future net cash flows from proved oil and gas reserves is presented in Note
Eight of the Notes to Consolidated Financial Statements in Part II, Item 8 of
this report on Form 10-K.
(5) NET PROFIT AGREEMENTS
The Company produces gas in the Oklahoma portion of the Hugoton field
under a "Dry Gas Agreement" with Chevron USA, Inc. (Chevron). This agreement
allows the Company to expend funds for the operation of the properties
(including the cost of drilling wells) and to recoup the funds so expended from
current production income. Eighty percent of net operating income generated by
the gas production (after operational costs are recouped, including the cost of
drilling and equipping wells) is then paid to Chevron. At December 31, 1994,
the Company had working interests in 21 Guymon-Hugoton wells and 43 Camrick
wells under the terms of this agreement.
The Company also produces gas in the Kansas Hugoton field under
various agreements similar to the Chevron agreement, except that net operating
income is allocated 15% to the Company and 85% to the other parties. At
December 31, 1994, the Company had working interests in 47 Chase wells and
eight Council Grove wells under such agreements.
Additional or replacement wells drilled on the properties, including
wells drilled under the infill drilling program in the Hugoton field, would be
operated under the same terms and conditions as existing wells, and would result
in the commencement of the 80/20 or 85/15 net operating income allocation after
the cost of the new wells is recovered.
(6) HUGOTON GAS TRUST AGREEMENT
Gas rights established in 1955 to some 50,000 partially developed
acres in Finney and Kearny Counties, Kansas were transferred by K N on
October 1, 1984 to the Company subject to a gas payment of six cents per Mcf
for gas produced from the acreage. Quarterly payments are made by the Company
to the Hugoton Gas Trust, a publicly-held trust created in 1955. Payments
terminate when the recoverable gas reserves decline to 50 Bcf or less. At
yearend 1994, the Company has working interests in 156 Chase wells and 42
Council Grove wells which are subject to such payments. Any additional gas
wells drilled on this acreage will also be subject to the six-cent payment per
Mcf of gas produced.
ITEM 3: LEGAL PROCEEDINGS
See Note Six of the Notes to Consolidated Financial Statements in Part II,
Item 8 of this report on Form 10-K.
13
ITEM 4: SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
ADDITIONAL ITEM -
EXECUTIVE OFFICERS OF THE REGISTRANT
The following information required by Item 401 of Regulation S-K
pertains to the executive officers who are not directors of the Registrant and
are not included with information under Item 10, Part III of this Form 10-K:
Darrel Reed: Vice President, Controller and
Treasurer
Age: 53
Term ends: April 1995
Period served: Since July 1985
Past five years - business experience: Vice President - Finance and Treasurer
and Chief Financial and Accounting
Officer from July 1985 through May
1994.
Eugene A. Lang, Jr: Senior Vice President, General Counsel
and Secretary
Age: 41
Term ends: April 1995
Period served: Since October 1990
Past five years - business experience: Vice President, General Counsel and
Secretary from October 1990 through May
1994. Attorney at Law, Houston, Texas,
from September 1986 through September
1990.
Lee B. VanRamshorst: Senior Vice President - Business
Development of Plains Petroleum
Operating Company (PPOC), the
Registrant's operating subsidiary.
Age: 55
Term ends: May 1995
Period served: Since November 1985
Past five years - business experience: Vice President - Engineering of PPOC
from May 1988 through November 1991.
Robert A. Miller, Jr: Vice President - Law of PPOC
Age: 53
Term ends: May 1995
Period served: Since September 1985
Past five years - business experience: Vice President, General Counsel from
August 1987 through September 1990.
Robert W. Wagner: Vice President - Land and Marketing of
PPOC
Age: 54
Term ends: May 1995
Period served: Since May 1985
Past five years - business experience: Manager - Land of PPOC from May 1985
through April 1988.
14
Additional Item (Continued)
John N. Wood: Vice President - Information Systems of
PPOC
Age: 47
Term ends: May 1995
Period served: Since November 1990
Past five years - business experience: Vice President - Geoscience Systems of
PPOC from May through November 1991;
Manager - Geoscience Systems of PPOC
from November 1990 through April 1991;
Vice President - Exploration Computing,
McAdams, Roux and Associates, Inc. from
1988 through October 1990.
PART II
ITEM 5: MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
The common stock of Plains Petroleum Company was first listed on the
New York Stock Exchange on September 16, 1985. The reported high and low market
prices for the two most recent fiscal years and the most recent interim period
are shown below.
High Low
-------- -------
1995 First quarter (through March 15) 24 21 3/8
1994 (by quarter):
Fourth 27 7/8 23 1/8
Third 26 5/8 20 3/4
Second 22 5/8 19 1/2
First 27 7/8 21 3/8
1993 (by quarter):
Fourth 28 19 1/2
Third 30 3/8 25 3/8
Second 29 24 3/8
First 29 3/4 24 7/8
There are approximately 3,800 record holders as of March 15, 1995 of
the Company's common stock. In addition, Plains estimates that approximately
5,200 shareholders hold stock as beneficial owners in nominee accounts.
The Company paid quarterly dividends of 6 CENTS per share, or 24 CENTS
per annum, during each of the three years ending December 31, 1994. On
February 15, 1995 the Company declared a quarterly dividend of 6 CENTS per share
payable on March 31, 1995.
The Company has a rights plan designed to insure that stockholders
receive full value for their shares in the event of certain takeover attempts.
15
ITEM 6: SELECTED FINANCIAL DATA
(In thousands, except per share) 1994 1993 1992 1991 1990
------------------------------------------------------------------------------------------------------
OPERATING DATA
Revenues $61,693 $64,280 $58,541 $58,706 $48,791
Net earnings 6,650 1,727 (a) 9,134 16,659 16,796
Earnings per share .68 .18 .93 1.71 1.76
BALANCE SHEET DATA
Total assets $156,944 $126,792 $133,975 $120,474 $91,348
Long-term debt 37,000 13,500 20,000 15,000 3,000
Stockholders' equity 99,456 94,803 95,358 88,515 73,280
Cash dividends per common share .24 .24 .24 .24 .16
<FN>
(a) Includes an impairment charge of $9.3 million and a net credit of $1.3
million for two mandatory accounting changes.
16
ITEM 7: MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The Company achieved growth in oil and gas reserves of 11% through a
combined program of acquisitions, exploration and exploitation. In a highly
competitive market for a limited quantity of quality properties, the Company
successfully acquired 20 billion cubic feet (Bcf) of gas and 2.5 million barrels
of oil. Exploration and exploitation achievements added another 19.6 Bcf of gas
and 2.3 million barrels of oil. In a year marked by fluctuating and declining
prices resulting in production curtailments, the Company reported net earnings
of 68 CENTS per share as compared to 18 CENTS per share in the previous year.
Concentrated efforts to reduce operating costs and improve operating
efficiencies offset declines in revenues stemming from lower prices.
LIQUIDITY AND CAPITAL RESOURCES
At yearend 1994, the Company's working capital increased to $1.9 million,
as compared to $1 million the prior yearend. Cash provided by operations was
used principally to fund the Company's 1994 capital expenditures for development
drilling and exploration, totaling approximately $21 million and for production
facilities including gathering and automation facilities and compression units
in the Hugoton field of $1.3 million. Additionally, cash provided in excess of
funding operational requirements was used to repay a portion of the borrowings
and to fund dividend payments. Development drilling and production enhancement
projects in 1994 comprised approximately 63% of the capital expenditures. Of
the total expenditures, 1994 exploration projects represented approximately $7
million.
During 1994, the Company utilized a portion of its bank credit line to
finance acquisitions of properties in Colorado, Wyoming, Montana, North Dakota,
Utah and Oklahoma totaling approximately $27 million.
On February 17, 1995, the Company entered into a new credit agreement for a
$150 million unsecured, revolving bank line replacing the previous $60 million
line of credit. (See Note Three of Notes to Consolidated Financial Statements.)
Together with cash provided from operations, the Company believes that this new
bank line provides the financial strength to aggressively pursue acquisition
opportunities and to support an active development and exploration program, all
of which are necessary for growth.
The Company plans a 1995 capital spending program of approximately $34
million for exploitation, exploration and production enhancement projects. An
additional $25 million has been targeted for acquisition of oil and gas
properties. Approximately $16 million, or 46% of the capital spending program
will be directed toward development drilling projects located principally in
Wyoming, Nevada and offshore Texas and Louisiana. Secondary recovery projects
consisting of waterflood enhancement programs in the Cambridge, Rozet, N. Adon
Road and other Minnelusa fields of Wyoming and the Moss Grayburg San Andres Unit
located in Texas will require capital spending of approximately $8 million.
Exploration drilling efforts of approximately $3 1/2 million will focus on
projects in the Permian Basin of west Texas, the offshore Gulf Coast and the
Green River Basin of Wyoming. Other exploration capital spending efforts,
estimated to cost approximately $4 million will be directed toward the
development of prospects through lease acquisitions and utilization of seismic
and other geological studies.
17
In mid-February 1995, an exploratory test, the Patterson Deep Prospect in
Louisiana, was completed as a dry hole. The Company's investment in this well
approximated $600,000 and will be expensed in the first quarter of 1995.
For the three-year period ended December 31, 1994, the Company paid
quarterly dividends of 6 CENTS per share, or 24 CENTS per annum. It has
repurchased a total of approximately 48,000 shares of its common stock for use
in its employee benefit plans.
RESULTS OF OPERATIONS
During 1994, the Company generated net earnings of $6.6 million (68 CENTS
per share) compared to $1.7 million (18 CENTS per share) in 1993. In an effort
to improve profitability, the Company concentrated its efforts on improving the
efficiency of field operations while simultaneously reducing costs. Lower
production and exploration operating costs in 1994 offset increases in
depreciation, depletion and amortization expense and in general and
administrative expenses. Net earnings in 1993 were impacted by a $9.3 million
impairment charge on certain properties and a net credit of $1.3 million derived
from two mandatory accounting changes.
REVENUES
Revenues for 1994 were $62 million, 4% lower than 1993 revenues of $64
million, primarily due to lower average gas and oil prices. Revenues for 1993
increased 10% over 1992 as a result of higher volumes sold and increased average
gas prices. Gas revenues represented nearly 72% of the Company's total revenues
for 1994 and 1993.
Gas revenues declined 4% to $44 million from $46 million in 1993
principally due to declining prices. Average gas prices for 1994 ranged from
$2.08 per Mcf in the first quarter to $1.74 in the fourth quarter, resulting in
average prices for the year of $1.86, down 8 CENTS, or 4%, from 1993. Average
prices for 1993 were up 11 CENTS per Mcf from 1992.
One-half of the Company's total gas revenues were received from the
Company's principal purchaser for sales from the Hugoton field in southwestern
Kansas and the Niobrara area of northeastern Colorado. The Company received a
wellhead price of $2.00 per million British Thermal Unit (MMBtu) from this
purchaser for the five months of January through March, November and December.
For the months of April through October 1994, the Company received $1.80 and
$1.75 per MMBtu at the wellhead for the Hugoton field and the Niobrara field,
respectively. Under a two-tier seasonal pricing contract effective for 1995,
the Company will receive a weighted average wellhead price of $1.80 per MMBtu on
net sales volumes of 14 Bcf and spot market prices on another 5 Bcf (net). In
addition to the 1994 negotiated permanent release of 66 Hugoton field wells
connected to Company-owned gathering lines, an additional 37 wells were released
for 1995. Production from these wells will be sold on the spot market.
Negotiations with the purchaser for 1996 prices will commence in late 1995.
18
Wellhead prices include all transportation and marketing charges, whereas
spot market sales are burdened with these additional costs. These charges
currently range from 15 CENTS to 40 CENTS per MMBtu in the Rocky Mountain and
Mid-continent area. The balance of the Company's gas supplies are sold to
various purchasers under percentage of proceeds, short-term or spot sales
contracts.
Natural gas production volumes of 23.9 Bcf sold in 1994 increased 1% over
1993 volumes of 23.8 Bcf. This nominal increase was attributed to constraints
on the principal purchaser's gathering system in the Hugoton field for the first
quarter and curtailment of production due to low prices during the third
quarter.
Oil revenues of $17 million declined 5% from 1993 primarily due to a 6%
drop in average prices. Oil revenues of $18 million for 1993 declined 4% as
compared to 1992 revenues. Average oil prices realized during 1994 were at a
five-year average low of $13.91 per barrel, in comparison to $14.83 for 1993 and
$18.20 for 1992. Oil production of 1.2 million barrels for 1994 was comparable
to 1993. However, due to the acquisition of primarily oil properties in
November 1994, average daily production by yearend was 4,602 barrels, an
increase of 34% from the beginning of the year.
OPERATING EXPENSES
Operating expenses for 1994 were relatively unchanged as compared with
1993, excluding the $9.3 million impairment charge in 1993. Operating expenses
in 1993, exclusive of the impairment charge, were 14% over 1992 due to increased
lease operating costs and higher depreciation, depletion and amortization
charges associated with acquired properties.
Production costs, including lease operating costs, production and property
taxes, transportation and processing fees and net profits payments, declined
$2.6 million to $24.7 million in 1994, a 10% decrease from 1993. Production
costs for 1994 approximated $4.73 per barrel of oil equivalent (BOE) compared to
$5.28 per BOE in 1993 and $5.48 per BOE in 1992.
A decline in lease operating costs of 14% from 1993 is directly attributed
to the Company's program to improve operating efficiencies, dispose of
marginally economic wells and reduce costs, particularly with respect to oil
field operations. Lease operating costs for 1993 were 9% over 1992 due to
increased operating costs associated with acquisitions, drilling programs and
production workovers and increased transportation and processing costs on spot
sales of natural gas.
Production and property taxes increased 10% over the prior year.
Production taxes for 1994 decreased 6% due to lower revenues. 1993 production
taxes were at a comparable level to 1992. Conversely, property taxes consisting
principally of ad valorem taxes increased 31% over 1993. This increase is
primarily attributable to rising rates and valuation methods utilized by Kansas
tax authorities for the Hugoton field properties.
Transportation and processing (T&P) costs decreased 6% from 1993 due to
lower average charges of 10 CENTS to 15 CENTS per MMBtu related to spot market
sales. Increased spot market sales volumes in 1993 resulted in a 41% increase
in T&P over 1992. Lower gas sales (down 7%) and an 11% decline in average
prices received for production from Oklahoma properties resulted in a 32%
decline in net profits expense as compared to 1993. In 1993, gas sales from
these same properties were higher as compared to 1992 resulting in an increase
in net profits expense of 4% above 1992.
19
Consistent with industry practices, certain general and administrative
costs attributed directly to other operating expense classifications of lease
operations, exploration and transportation were reclassified to the respective
operating expense categories for the years 1994, 1993 and 1992. Employee payroll
expenses declined by 10% in 1994 from 1993 as a result of a 14% staff reduction
in 1993. After reclassifications of $2.3 million and $3.4 million for 1994 and
1993, respectively, to the operating expense categories, general and
administrative costs were approximately $935,000, or 15%, above 1993, primarily
due to higher costs related to employee benefit plans. Termination of an
administrative overhead sharing arrangement in mid-1992 and reduction of
operating overhead reimbursement attributed to properties sold caused 1993
general and administrative costs to increase 15% above 1992.
Depreciation, depletion and amortization increased by 13% in 1994 primarily
due to an 11% increase in depletion rates over 1993. Depletion expenses for
1993 increased one-third over 1992. Higher cost-basis oil properties acquired
in previous years and revisions of oil reserves in 1993 and 1992 caused
depletion rates to increase for both periods. As recognition of the excess cost
basis over market value of certain Permian Basin properties in 1993, the Company
reduced the depletable basis through the recognition of an impairment provision
of $9.3 million.
Exploration expenses consisting of unsuccessful exploration drilling,
seismic costs and lease impairments and rentals, were 38% lower than 1993,
which, in turn, was 5% lower than 1992 due to reduced exploration activities.
Borrowings for property acquisitions in the latter half of 1994 and
increasing interest rates resulted in higher interest expense than in 1993.
Interest rates and debt balances were lower in 1993 than in 1992.
Other income was generated principally from third party utilization of the
Company's gathering and automation systems in the Hugoton field. Restructuring
and staff reduction costs and unsuccessful acquisition expenses contributed to
an increase in other expenses in 1993.
Effective January 1, 1993, the Company adopted the Financial Accounting
Standards Board Statement No. 106 on accounting for postretirement benefits
other than pensions. As a result of this adoption, the Company recognized a
one-time, cumulative charge of approximately $800,000 (pretax) in 1993 (see
Note Five of the Notes to Consolidated Financial Statements in Part II, Item 8
of this report on Form 10-K).
TAXES
The Company's effective income tax rates are considerably below the
statutory rate primarily due to the benefit of the Company's tax loss
carryforwards. The Company adopted Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes", effective January 1, 1993. A one-time,
cumulative benefit of $2 million for the effect of the accounting change on
prior years was recognized in 1993 (see Notes One and Four of the Notes to
Consolidated Financial Statements in Part II, Item 8 of this report on
Form 10-K).
20
ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PLAINS PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF EARNINGS
YEAR ENDED DECEMBER 31
-----------------------------------
In thousands, except per share 1994 1993 1992
---------------------------------------------------------------------
REVENUES
Gas sales $44,505 $46,189 $39,623
Oil and condensate sales 17,188 18,091 18,918
------ ------ ------
61,693 64,280 58,541
---------------------------------------------------------------------
OPERATING EXPENSES
Production -
Lease operations 10,810 12,537 11,503
Production and property taxes 8,161 7,406 7,514
Transportation and processing 2,476 2,640 1,875
Net profit payments 3,247 4,748 4,575
General and administrative 7,350 6,415 5,559
Depreciation, depletion & amortization 17,353 15,282 11,415
Exploration 2,861 4,623 4,865
Interest expense, net 762 643 690
Other (income) expense (563) 219 (203)
Property impairment 9,300
------ ------ ------
52,457 63,813 47,793
---------------------------------------------------------------------
EARNINGS BEFORE TAXES 9,236 467 10,748
-------------------------------------------------------------------
PROVISIONS FOR INCOME TAXES (Note Four)
Current 302 425 625
Deferred 2,284 (341) 989
------ ------ ------
2,586 84 1,614
---------------------------------------------------------------------
NET EARNINGS
Before accounting changes 6,650 383 9,134
Accounting changes:
Deferred income taxes (Note One) 2,000
Postretirement benefits, net of
tax (Note Five) (656)
------ ------ ------
$6,650 $1,727 $9,134
------ ------ ------
------ ------ ------
AVERAGE SHARES OUTSTANDING (Note One) 9,808 9,797 9,796
------ ------ ------
------ ------ ------
EARNINGS PER SHARE (Note One)
Before accounting changes $ .68 $ .04 $ .93
Accounting changes:
Deferred income taxes .20
Postretirement benefits (.06)
------ ------ ------
Net earnings $ .68 $ .18 $ .93
------ ------ ------
------ ------ ------
The accompanying notes are an integral part of these financial statements.
21
PLAINS PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
Successful Efforts Accounting Method
December 31
----------------
ASSETS In Thousands 1994 1993
-------------------------------------------------------------------------------
CURRENT ASSETS
Cash and equivalents $2,331 $2,660
Accounts receivable 7,057 5,422
Inventory, at lower of average cost or market 643 629
Prepaid expenses 422 614
------ -----
Total current assets 10,453 9,325
------ -----
------ -----
PROPERTY AND EQUIPMENT (Note One)
Oil and gas properties 221,337 180,923
Undeveloped leases 4,568 2,350
Other equipment and assets 8,627 7,883
Accumulated depreciation, depletion
and amortization (88,041) (73,689)
-------- --------
Net property and equipment 146,491 117,467
------- -------
$156,944 $126,792
------- -------
------- -------
The accompanying notes are an integral part of these financial statements.
22
PLAINS PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS
Successful Efforts Accounting Method
December 31
------------------
LIABILITIES AND STOCKHOLDERS' EQUITY In Thousands 1994 1993
-------------------------------------------------------------------------
CURRENT LIABILITIES
Accounts payable $2,245 $958
Undistributed production receipts 2,025 2,006
Accrued taxes 2,069 1,841
Accrued lease costs 994 780
Other accruals 1,199 2,795
------ ------
Total current liabilities 8,532 8,380
------ ------
LONG-TERM DEBT (Note Three) 37,000 13,500
DEFERRED INCOME TAXES (Notes One and Four) 10,012 7,728
POSTRETIREMENT BENEFITS (Note Five) 927 860
OTHER LONG-TERM LIABILITIES (Notes One and Five) 1,017 1,521
COMMITMENTS AND CONTINGENCIES (Note Six)
STOCKHOLDERS' EQUITY (Note One)
Common stock, $0.01 par value; 20 million
shares authorized; 9,813,055 and
9,800,618 shares outstanding 98 98
Additional paid-in capital 20,278 19,498
Retained earnings 79,713 75,417
Treasury stock, at cost (633) (210)
------ ------
Total stockholders' equity 99,456 94,803
------ ------
$156,944 $126,792
-------- --------
-------- --------
The accompanying notes are an integral part of these financial statements.
23
PLAINS PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Common Stock Additional Treasury Stock Total
-------------- Paid-in Retained ---------- Stockholders'
In Thousands Shares Amount Capital Earnings Shares Amount Equity
----------------------------------------------------------------------------------------------------------------
Balance, December 31, 1991 9,793 $98 $19,178 $69,258 (1) $(19) $88,515
Net earnings 9,134 9,134
Cash dividends (2,350) (2,350)
Exercised stock options 7 183 183
Treasury stock purchased (5) (158) (158)
TREASURY STOCK ISSUED 1 34 34
----------------------------------------------------------------------------------------------------------------
Balance, December 31, 1992 9,800 98 19,361 76,042 (5) (143) 95,358
Net earnings 1,727 1,727
Cash dividends (2,352) (2,352)
Exercised stock options 8 151 151
Treasury stock purchased (9) (263) (263)
TREASURY STOCK ISSUED (14) 7 196 182
----------------------------------------------------------------------------------------------------------------
Balance, December 31, 1993 9,808 98 19,498 75,417 (7) (210) 94,803
Net earnings 6,650 6,650
Cash dividends (2,354) (2,354)
Exercised stock options 2 45 45
Common stock issued 32 750 750
Treasury stock purchased (34) (740) (740)
TREASURY STOCK ISSUED (15) 12 317 302
----------------------------------------------------------------------------------------------------------------
BALANCE, DECEMBER 31, 1994 9,842 $98 $20,278 $79,713 (29) $(633) $99,456
----------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
24
PLAINS PETROLEUM COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31
---------------------------
In Thousands 1994 1993 1992
----------------------------------------------------------------------------
OPERATING ACTIVITIES
Net earnings $6,650 $1,727 $9,134
Adjustments to reconcile earnings to cash
provided by operations:
Depreciation, depletion and amortization 17,353 15,282 11,415
Property impairment 9,300
Deferred income taxes 2,284 (2,485) 989
Exploration expense 2,861 4,623 4,865
Postretirement benefits 67 800
Changes in components of working capital:
Accounts receivable (1,635) 1,591 100
Prepaid expenses 192 (95) 333
Accounts payable 1,287 (813) (1,283)
Undistributed production receipts 19 (219) (180)
Other liabilities (1,154) 1,721 2,126
------- ------- -------
Cash provided by operating activities 27,924 31,432 27,499
------- ------- -------
INVESTING ACTIVITIES
Capital expenditures - Exploration and production (20,525) (15,632) (18,043)
- Other (1,748) (3,713) (601)
Acquisition of oil and gas properties (27,414) (4,171) (12,162)
Proceeds from sale of properties 435 525 569
------- ------- -------
Cash used in investing activities (49,252) (22,991) (30,237)
------- ------- -------
FINANCING ACTIVITIES
Long-term borrowings 28,000 11,000
Repayments of long-term debt (4,500) (6,500) (6,000)
Dividends paid (2,354) (2,352) (2,350)
Exercised stock options 45 151 183
Treasury stock purchased (438) (81) (124)
Other 246 868 6
------- ------- -------
Cash provided by (used in) financing activities 20,999 (7,914) 2,715
------- ------- -------
(Decrease) increase in cash and equivalents (329) 527 (23)
Cash and equivalents at beginning of year 2,660 2,133 2,156
------- ------- -------
Cash and equivalents at end of year $2,331 $2,660 $2,133
------- ------- -------
------- ------- -------
The accompanying notes are an integral part of these financial statements.
25
PLAINS PETROLEUM COMPANY
Notes to Consolidated Financial Statements
NOTE ONE SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of Plains
Petroleum Company (Plains) and its wholly-owned subsidiaries, which are
hereinafter referred to collectively as the "Company". All significant
intercompany transactions have been eliminated. Certain reclassifications have
been made to 1992 and 1993 amounts to conform to the 1994 presentation.
OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for
its oil and gas exploration and development activities. Acquisition costs,
successful exploration costs and all development costs are capitalized.
Unsuccessful exploratory drilling costs, seismic costs, and lease impairments
and rentals are expensed. Generally, gains or losses from disposal of properties
are recognized currently. The estimated salvage value of a property on its
sale, disposal or abandonment generally approximates the estimated
dismantlement, site restoration and abandonment costs. As a result, the accrued
liability for any excess cost is not material and not separately disclosed in
the financial statements.
For certain oil properties located in the Permian Basin in west Texas
and southeastern New Mexico, a property impairment reserve of $9.3 million was
recorded in 1993 to adjust the net book value to an approximate net realizable
market value.
DEPRECIATION, DEPLETION AND AMORTIZATION
The unit-of-production method is used for computing depreciation,
depletion and amortization for oil and gas properties. The Company accrues for
estimated dismantlement and abandonment costs as a part of the
unit-of-production amortization. The accrued costs are classified as a
component of accumulated depreciation, depletion and amortization of the oil and
gas properties. Depreciation and amortization of other assets are provided for
using the straight-line method.
26
Note One (Continued)
INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109 (FAS 109), "Accounting for Income Taxes". FAS 109
utilizes the liability method, with deferred taxes determined on the basis of
estimated future tax effects of differences between the financial statement and
tax bases of assets and liabilities. A valuation allowance must be established
for a deferred tax asset if a tax benefit may not be realized from the asset.
In 1993, the Company recognized the one-time, cumulative benefit of the
accounting change on prior years of $2 million and established a valuation
allowance for its deferred tax assets (see Note Four).
STOCKHOLDERS' EQUITY
Quarterly dividend payments charged to retained earnings were
$2,354,000 in 1994, $2,352,000 in 1993 and $2,350,000 in 1992. During these
three years, the Company has repurchased a total of approximately 48,000 shares
of its common stock, primarily for use in its employee benefit plans.
Plains has a rights plan designed to insure that stockholders receive
full value for their shares in the event of certain takeover attempts.
EARNINGS PER SHARE
Earnings per share are computed based on the weighted average number
of common shares outstanding during each year. There are no other securities or
common stock equivalents which have a dilutive effect on earnings per share.
CONSOLIDATED STATEMENTS OF CASH FLOWS
The Company considers all highly liquid debt instruments purchased
with an original maturity of three months or less to be cash equivalents.
Supplemental disclosures of cash flow information:
In Thousands 1994 1993 1992
------------------------------- ------------------------
Cash paid during the year for:
Interest $624 $785 $652
Income taxes $207 $351 $503
27
Note One (Continued)
Supplemental information of noncash investing and financing activities:
In May 1994, the Company completed the contingent provisions of the
1990 McAdams, Roux and Associates, Inc. (MRA) Agreement and Plan of Merger, as
it related to the right of the MRA shareholders to receive additional shares of
the Company's common stock and cash ("Contingent Consideration"). The
Contingent Consideration was based on the determination that additional reserves
were attributed to certain property interests owned by MRA prior to the merger.
Under the Agreement, 31,873 additional shares of the Company's common stock
valued at $750,000 were issued to MRA's shareholders to satisfy a portion of the
Contingent Consideration. A cash payment of $1 1/2 million was made to the
MRA shareholders for the remainder of the obligation.
At yearend 1993, prior to the Contingent Consideration payments in
1994, an estimated current liability of $1,850,000 was reflected on the balance
sheet for the estimated cash payment, with the remainder of $650,000 related to
the common stock to be issued reflected as a long-term liability.
NOTE TWO ACQUISITIONS
The Company acquired interests in certain producing oil and gas
properties located in Colorado, Wyoming, Montana, North Dakota, Utah and
Oklahoma totaling approximately $27 million. Properties were acquired from
Anadarko Petroleum Corporation on November 1, 1994 for approximately $24
million. The acquisition was financed with a portion of the Company's bank line
of credit (see Note Three) and is reflected on the balance sheet using the
purchase method of accounting.
The accompanying Consolidated Statements of Earnings include the
operations of the acquired properties commencing with completion of the
purchases in 1994. The unaudited pro forma financial information which follows
represents condensed consolidated operating results as if the acquisitions had
been consummated as of January 1, 1993. Consequently, the unaudited pro forma
adjustments to historical information reflect the addition of the revenues and
direct operating expenses of the acquired properties for the respective periods
in addition to pro forma adjustments for depreciation, depletion and
amortization expense, interest expense, general and administrative expense and
related income tax effects. Earnings per share is based on the weighted average
number of common shares outstanding of Plains' stock during each year. The pro
forma financial information is provided for comparative purposes only and should
be read in conjunction with the historical consolidated financial statements of
the Company. The pro forma financial information presented is not necessarily
indicative of the combined financial results as they may be in the future, or
might have been during the periods presented had the acquisition been
consummated at the beginning of 1993.
28
As Pro Forma Pro Forma
In thousands, except per share (unaudited) Reported Adjustments Consolidated
---------------------------------------------------------------------------------------------------
For the year ended December 31, 1994
Revenues $61,693 $6,968 (1) $68,661
Net earnings 6,650 817 (1) 7,467
Earnings per share .68 .08 (1) .76
-------------------------------------------------------------------------------------------------
For the year ended December 31, 1993
Revenues $64,280 $9,298 $73,578
Net earnings 1,727 1,609 3,336
Earnings per share .18 .16 .34
<FN>
(1) REPRESENTS THE PORTION OF 1994 ACTIVITIES PRIOR TO CLOSING DATE.
NOTE THREE LONG-TERM DEBT
On February 17, 1995 (effective date), a new credit agreement was
entered into which replaced the previous $60 million unsecured, revolving line
of credit with a $150 million bank line. The new bank line has an initial
borrowing base limitation of $110 million, which will be redetermined annually.
Under the new agreement, outstanding borrowings at the end of the revolving
period in January 1997 convert to a term loan. The new agreement also provides
for a maximum of treasury stock purchases, which are not to exceed $75 million
during the eighteen-month period following the effective date. Subsequent to
that period, aggregate treasury stock purchases during the previous four fiscal
quarters may not exceed 50% of net earnings based upon the preceding two years.
Interest only payments are required during the revolving period;
thereafter, principal is to be repaid over six years in equal quarterly
installments beginning in April 1997. The outstanding principal balance shall
bear interest at the prime rate (8 1/2% per annum at yearend 1994) during
the revolving period. In addition, if the aggregate amount of treasury stock
purchases is greater than $50 million, and the principal outstanding is 80% or
greater of the borrowing base, then the interest rate margin is increased an
additional one-half of one percent per annum. The Company may also elect at any
time to borrow funds at more favorable rates offered by the interbank
eurocurrency market (LIBOR), which it utilizes frequently, or by domestic
certificates of deposit. LIBOR was elected for the entire outstanding debt
balance at yearend 1994 at an effective rate of 6.76% per annum.
29
Note Three (Continued)
The margin on fixed interest rates and the commitment fee rates vary
depending upon the percentage of the loan principal outstanding in relation to
the borrowing base as determined under the agreement. The rates are on a
sliding scale from five-eighths of one percent to one and one-half percent per
annum. The commitment fee is from one-quarter of one percent to
seventeen-fortieths of one percent per annum.
The Company must also maintain a book net worth of at least $80
million and a ratio of current assets to current liabilities of at least 1 to 1.
In addition, the Company may pay cash dividends as long as the aggregate
payments during the previous four fiscal quarters do not exceed 50% of its net
earnings based upon the preceding two years.
NOTE FOUR INCOME TAXES
The effective tax rate on income from operations before taxes and
the cumulative effect of changes in accounting methods is different from the
prevailing federal income tax rate as follows:
Year Ended December 31,
-----------------------
1994 1993
------ ------
Statutory income tax rate 34% 34%
Tax rate effect (decrease) of:
Changes in valuation allowance (14) (24)
State income taxes 4 4
Alternative minimum tax 2 2
Other items 2 2
------ ------
28% 18%
------ ------
------ ------
For 1992, income tax expense differs from the amounts computed by
applying the statutory Federal income tax rate to earnings before income taxes.
The reasons for these differences are shown as a percent of earnings as follows:
1992
----
Statutory income tax rate 34%
Utilization of tax loss carryforward (25)
Alternative minimum tax 2
Other items, net
(includes state taxes)
4
----
15%
----
----
30
Note Four (Continued)
The tax effect of temporary differences giving rise to the Company's
consolidated deferred income tax asset (liability) at December 31, 1994, is as
follows:
(In thousands)
Long-term deferred tax assets:
Operating loss carryforwards $ 9,173
Depletion and other credit carryforwards 4,804
Deferred postretirement benefits and other 719
-------
$14,696
Valuation allowance (112)
-------
Subtotal $14,584
Long-term deferred tax liabilities:
Depreciation, depletion and amortization (24,596)
-------
Deferred income tax liability $(10,012)
-------
-------
The Company has established a valuation allowance to the extent that
it may not be able to utilize its deferred tax assets. As of December 31, 1994,
the Company's estimate of taxable income increased for future periods which
resulted in a decrease in the valuation allowance from the prior yearend.
As of December 31, 1994, the Company had estimated alternative minimum
tax loss carryforwards totaling $12 million. Such carryforwards are subject to
separate return limitation year provisions and they expire, if not utilized,
during the years 1998 through 2005. The Company has no loss carryforwards for
state income tax purposes. The Company also has available depletion and other
credit carryforwards which may be utilized upon expiration of the loss
carryforwards.
31
NOTE FIVE EMPLOYEE BENEFIT PLANS
The Company has a qualified, defined benefit retirement plan covering
substantially all of its employees. The benefits are based on a specified level
of the employee's compensation during plan participation. The Company's funding
policy is to contribute annually an amount that provides not only for benefits
attributed to service to date, but also for benefits expected to be earned in
the future. Plan assets consist of U.S. Treasury obligations, corporate stocks
and bonds, insured annuity contracts, cash and cash equivalents and accrued
interest. Contributions by the Company were $312,000, $341,000 and $239,000
for the 1994, 1993 and 1992 plan years, respectively.
The following table sets forth the plan's funded status:
DECEMBER 31,
---------------------------
In Thousands 1994 1993 1992
--------------------------------------------------------------------------------------
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested
benefits of $1,637,000, $1,290,000 and
$818,000, respectively $(1,666) $(1,383) $ (880)
-------- -------- --------
-------- -------- --------
Projected benefit obligation $(2,396) $(2,321) $(2,099)
Plan assets at fair value 2,205 1,977 1,504
----------------------------------------------------------------------------------------
Projected benefit obligation in excess of
plan assets (191) (344) (595)
Unrecognized net (gain) loss (141) 16 285
Prior service cost not yet recognized in
net periodic pension costs 93 64 70
Unrecognized net obligation being recognized
Over 9 1/2, 10 1/2 and 11 1/2 Years, respectively 132 146 160
----------------------------------------------------------------------------------------
Accrued pension cost $(107) $(118) $ (80)
-------- -------- --------
-------- -------- --------
Net pension cost included the following components:
Service cost - benefits earned $290 $346 $273
Interest cost on projected benefit obligation 157 150 128
Actual loss (return) on plan assets 70 (145) (130)
Net amortization of unrecognized obligation
And deferral (216) 28 55
----------------------------------------------------------------------------------------
Net periodic pension cost $301 $ 379 $ 326
-------- -------- --------
-------- -------- --------
The weighted average discount rate used in determining the
actuarial present value of the projected benefit obligation was 8%. The rate of
increase used for compensation levels was 5% in 1994 and 1993 and 6% in 1992.
The expected long-term rate of return on assets was 8 1/2%.
32
Note Five (Continued)
The Company also contributes the lesser of 10% of its net
earnings or 10% of employee compensation to a profit sharing plan of the
Company. For 1994, 1993, and 1992, the Company contributed $334,000, $188,000
and $471,000, respectively.
During 1993 and 1992, employees were allowed to defer from 1% to
10% of their salary under a 401(k) salary redirection plan. Effective January
1, 1994, three changes were made to the 401(k) plan. First, employee deferrals
are limited to 9% of current salary. Second, the Company began matching
deferrals with contributions equal to 50% of each deferral up to 6% of current
salary. Company contributions are invested in Company stock and are subject to
a vesting schedule. Third, the payroll-based employee stock ownership plan
(PAYSOP) was terminated and merged into the 401(k) plan. Prior to its
termination and merger with the 401(k) plan, PAYSOP contributions were based
upon 1/2 of 1% of compensation and amounted to $22,700 for 1993 and $23,500 for
1992.
Plains has established three incentive stock option plans for
employees and a non-qualified stock option plan for its non-employee directors.
Stock options are granted at not less than 100% of the market value of the stock
on the date of grant. Plains has reserved one million shares under the employee
plans and 50,000 shares under the non-employee directors' plan. Options
granted, exercised and outstanding are as follows:
Number of Option Price
Shares Per Share
--------- ----------------
Outstanding at December 31, 1991 280,728
Granted 100,848 $26.94 - $27.50
Exercised or canceled (27,300) 16.25 - 33.56
--------
Outstanding at December 31, 1992 354,276
Granted 14,755 27.25 - 28.94
Exercised or canceled (42,350) 16.25 - 33.69
--------
Outstanding at December 31, 1993 326,681
Granted 202,952 20.69 - 26.25
Exercised or canceled (12,605) 26.19 - 33.56
--------
Outstanding at December 31, 1994 517,028 16.25 - 33.69
--------
--------
33
Note Five (Continued)
The Company has established an executive deferred compensation
plan and a directors' deferred fee plan which permit the deferral of current
salary or directors' fees for the purpose of providing funds at retirement or
death for employees, directors and their beneficiaries. The total accrued
liability under these plans at December 31, 1994 and 1993 was $1,006,000 and
$838,000, respectively.
The Company provides postretirement healthcare benefits to
retiring employees and their spouses and a salary continuation (death) benefit
to certain eligible retirees. These benefits are subject to a medical cost
escalation limit, deductibles, co-payments, lifetime limits and other
limitations. The Company reserves the right to change or terminate the benefits
at any time.
Effective January 1, 1993, the Company adopted Statement No. 106
(FAS 106) issued by the Financial Accounting Standards Board on accounting for
postretirement benefits other than pensions. This statement requires the accrual
of the cost of providing postretirement benefits over the active service period
of the employee. FAS 106 requires recognition of the Company's accumulated
postretirement benefit obligation for its healthcare plan and salary
continuation plan existing at the time of adoption, as well as incremental
expense recognition for changes in the obligation attributable to each
successive fiscal period. The Company elected to immediately recognize the
accumulated liability as of the effective date, totaling approximately $800,000
(pretax). Prior to 1993, the Company recognized postretirement costs in the
year the benefits were paid.
As of yearend, the status of the obligation, after reflecting
anticipated changes in plan provisions, is as follows:
(In Thousands) December 31,
-------------- -------------
1994 1993
------ ------
Accumulated postretirement benefit obligation:
Active plan participants $(458) $(492)
Retirees (302) (320)
------ ------
(760) (812)
Plan assets 0* 0 *
------ ------
Net accumulated postretirement benefit obligation (760) (812)
Unrecognized net gain from past experience different from
that assumed and from changes in assumptions (167) (48)
------ ------
Accrued postretirement benefit cost $(927) $(860)
------ ------
------ ------
* THE COMPANY HAS SPECIFICALLY IDENTIFIED CERTAIN ASSETS, PRIMARILY
INSURANCE POLICIES OWNED BY THE COMPANY, TO FUND POSTRETIREMENT
BENEFIT OBLIGATIONS. HOWEVER, THESE ASSETS ARE NOT CONSIDERED "PLAN
ASSETS" AS DEFINED IN THE TAX REGULATIONS. AS OF DECEMBER 31, 1994
AND 1993, THE INSURANCE POLICIES HAVE A TOTAL CASH SURRENDER VALUE OF
APPROXIMATELY $860,000 AND $770,000, RESPECTIVELY.
34
Note Five (Continued)
Net periodic postretirement benefit cost included the following components:
1994 1993
---- ----
Service cost of benefits earned $ 41 $ 36
---- ----
Interest cost on accumulated postretirement
benefit obligation 61 60
Net periodic postretirement benefit cost $102 $ 96
---- ----
---- ----
The Company has utilized independent actuaries to estimate the
expected costs of healthcare benefits using current data from the Company and
various assumptions. The estimates are subject to significant revisions based
on a number of factors, including possible changes in the assumed healthcare
cost trend rate and the discount rate used in the calculations.
The accumulated postretirement benefit obligation was computed
using an assumed discount rate of 8%. The future healthcare cost trend rate was
assumed to be 11 1/2%, then it declines by 1.5 percentage points for each
of three successive years and remains constant at 7% thereafter. If the
healthcare cost trend rate was increased one percent for all future years, both
the accumulated postretirement benefit obligation and the aggregate of service
and interest costs for 1994 would have increased 1%.
NOTE SIX COMMITMENTS AND CONTINGENCIES
The Company leases office facilities in Lakewood, Colorado; Midland, Texas;
Lakin, Kansas and Gillette, Wyoming under operating leases with 6 to 60 months
remaining on the lease terms as of December 31, 1994. The Company's computer
and phone system leases terminate in 2 to 31 months. Minimum annual rental
commitments amount to approximately $725,514 in 1995, $370,215 in 1996, $124,310
in 1997, $112,404 in 1998 and $3,800 in 1999.
On October 20, 1994, the Company issued a press release stating that it had
authorized its financial advisors to help the Company study strategic
alternatives in light of a recent Schedule 13-D filing by Cross Timbers Oil
Company. The press release stated that as part of the study, the financial
advisors would seek indications of interest from certain possible merger
partners. The press release also indicated that the Company's board had amended
its shareholder rights plan.
On November 2, 1994, a putative class action was filed in Delaware Chancery
Court. In that case, entitled MILLER V. CODY, et al., the plaintiff has alleged
that certain named directors and the Company have, among other things, breached
their fiduciary duties by unreasonably amending the Company's shareholder rights
plan and otherwise acting to entrench themselves in office. Plaintiff seeks
various forms of injunctive relief, damages and an award of plaintiff's costs
and disbursements.
35
Note Six (Continued)
The Company and the named directors deny the principal allegations of
wrongdoing in the complaint and intend to pursue a vigorous defense. A putative
class action entitled BEHRENS V. MILLER, et al., that was filed on October 21,
1994, was voluntarily dismissed without prejudice by the plaintiff. The
allegations and relief sought in the BEHRENS case were similar to those in the
MILLER action, described above.
At December 31, 1994, the Company was a party to certain legal proceedings
which have arisen out of the ordinary course of business. Based on the facts
currently available, in management's opinion the liability, individually or in
the aggregate, if any, to the Company resulting from such actions will not have
a material adverse effect on the Company's consolidated financial position or
results of operations.
ENVIRONMENTAL CONTROLS
At yearend 1994, there were no known environmental or other regulatory
matters related to the Company's operations which are reasonably expected to
result in a material liability to the Company. Compliance with environmental
laws and regulations has not had, and is not expected to have, a material
adverse effect on the Company's capital expenditures, earnings or competitive
position.
36
NOTE SEVEN COMPARATIVE QUARTERLY RESULTS (UNAUDITED)
1994
------------------------------------------------
IN THOUSANDS 1st 2nd 3rd 4th Year
---------------------------------------------------------------------------------------
Revenues $16,176 $14,705 $12,616 $18,196 $61,693
Direct operating expenses (a) 11,080 9,355 9,189 12,423 42,047
Other expenses 2,280 2,650 2,087 3,393 10,410
------ ------- ------ ------ -------
Earnings before taxes 2,816 2,700 1,340 2,380 9,236
Income tax provision 788 756 376 666 2,586
------ ------- ------ ------ -------
Net earnings $2,028 $1,944 $964 $1,714 $ 6,650
------ ------- ------ ------ -------
------ ------- ------ ------ -------
Earnings per share $ .21 $ .20 $ .10 $ .18 $ .68*
------ ------- ------ ------ -------
------ ------- ------ ------ -------
1993
---------------------------------------------------------------------------------------
IN THOUSANDS 1st 2nd 3rd 4th Year
---------------------------------------------------------------------------------------
Revenues $17,215 $16,487 $15,331 $15,247 $64,280
Direct operating expenses (a) (b) 13,975 10,203 10,328 17,407 51,913
Other expenses 3,149 3,295 2,891 2,565 11,900
------ ------- ------ ------ -------
Earnings (loss) before taxes 91 2,989 2,112 (4,725) 467
Income tax provision (benefit) 16 538 380 (850) 84
------ ------- ------ ------ -------
Earnings (loss) before accounting changes 75 2,451 1,732 (3,875) 383
Cumulative effect on prior years
of accounting changes 1,344 1,344
---------------------------------------------------------------------------------------
Net earnings (loss) $1,419 $2,451 $1,732 $(3,875) $ 1,727
------ ------- ------ ------ -------
------ ------- ------ ------ -------
Earnings per share
Earnings (loss) before accounting
changes $ .01 $ .25 $ .18 ($ .39) $ .04*
Accounting changes .13 .14*
------ ------- ------ ------ -------
Net earnings (loss) per share $ .14 $ .25 $ .18 $ (.39) $ .18
------ ------- ------ ------ -------
------ ------- ------ ------ -------
<FN>
* DIFFERENCE DUE TO ROUNDING.
(A) DIRECT OPERATING EXPENSES ARE THOSE ASSOCIATED DIRECTLY WITH OIL AND GAS
REVENUES AND INCLUDE LEASE OPERATIONS, PRODUCTION AND PROPERTY TAXES,
TRANSPORTATION AND PROCESSING, NET PROFIT PAYMENTS, AND DEPRECIATION,
DEPLETION AND AMORTIZATION. GROSS PROFIT WOULD BE COMPUTED AS THE EXCESS
OF REVENUES OVER DIRECT OPERATING EXPENSES.
(B) ALSO INCLUDED IN 1993 DIRECT OPERATING EXPENSES IS A $3.3 MILLION CHARGE IN
THE FIRST QUARTER AND $6 MILLION CHARGE IN THE FOURTH QUARTER FOR PROPERTY
IMPAIRMENT.
37
NOTE EIGHT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following disclosures concerning the Company's oil and gas
producing activities are presented in accordance with FAS No. 69, "Disclosures
about Oil and Gas Producing Activities".
December 31
----------------------------
IN THOUSANDS 1994 1993 1992
-------------------------------------------------------------------------
Capitalized Costs at Yearend
Oil and gas properties --
Producing $207,036 $166,626 $153,817
Proved undeveloped 14,301 14,297 14,242
-------- ------- -------
221,337 180,923 168,059
Undeveloped leases 4,568 2,350 2,252
-------- ------- -------
225,905 183,273 170,311
Accumulated depreciation,
depletion and amortization 85,353 71,848 49,512
-------- ------- -------
Net capitalized costs $140,552 $111,425 $120,799
-------- ------- -------
-------- ------- -------
Costs Incurred During the Year
(capitalized or expensed) --
Acquisition of properties:
proved $25,808 $ 4,171 $12,162
unproved 1,606
Exploration costs 6,898 3,567 4,034
Development costs 14,956 14,074 12,360
-------- ------- -------
Total costs incurred $49,268 $21,812 $28,556
-------- ------- -------
-------- ------- -------
ESTIMATED OIL AND GAS RESERVE QUANTITIES
All of the Company's proved developed reserve quantities were
estimated at yearend 1994 by Netherland, Sewell & Associates, Inc., an
independent petroleum engineering firm. Proved undeveloped reserves were
estimated by the Company's petroleum engineers and amounted to approximately 11%
of total proved reserve equivalents at December 31, 1994. Proved developed
reserve quantities in prior years were also estimated annually by independent
petroleum engineers.
38
Note Eight (Continued)
The reserve balances presented below are estimates of net quantities
which can be expected to be recovered commercially at current prices and with
existing conventional equipment and operating methods. Proved developed
reserves are only those reserves expected to be recovered from existing wells.
Proved undeveloped reserves, estimated to be 20.1 Bcf of gas and 3.5 million
barrels of oil at yearend 1994, include those reserves expected to be recovered
from new wells and improved recovery projects where additional expenditures are
required. The Company's reserves are in the lower 48 states, principally in the
Kansas and Oklahoma portions of the Hugoton Field, the Permian Basin of West
Texas and southeastern New Mexico, and in the Powder River and Green River
Basins of Wyoming.
Gas Oil
(MMcF) (MBbls)
-------- -------
Proved developed and undeveloped reserves --
Balance, December 31, 1991 338,309 11,122
Extensions, discoveries and other additions 1,993 171
Acquisitions 769 2,193
Production (21,654) (1,039)
Revisions (3,652) (2,406)
Sales of reserves ( 177) (36)
------- -------
Balance, December 31, 1992 315,588 10,005
Extensions, discoveries and other additions 6,288 1,194
Acquisitions 1,537 216
Production (23,757) (1,220)
Revisions (38) (3,444)
Sales of reserves ( 130) (66)
-------- -------
Balance, December 31, 1993 299,488 6,685
Extensions, discoveries and other additions 19,639 2,297
Acquisitions 20,277 2,461
Production (23,925) (1,236)
Revisions (2,958) 828
Sales of reserves (42) (62)
-------- -------
Balance, December 31, 1994 312,479 10,973
-------- -------
-------- -------
Proved Developed Reserves
December 31, 1992 307,262 6,945
December 31, 1993 293,814 5,286
December 31, 1994 292,321 7,466
39
Note Eight (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
AND CHANGE THEREIN RELATING TO PROVED RESERVES (UNAUDITED)
December 31
---------------------------------------
IN THOUSANDS 1994 1993 1992
-------------------------------------------------------------------------------
Future cash inflows $698,988 $654,658 $748,881
Future production costs (259,628) (238,715) (300,609)
Future development costs (16,624) (8,316) (13,135)
--------- --------- ----------
Future net cash flows
before taxes 422,736 407,627 435,137
10% annual discount factor (187,735) (182,071) (208,407)
--------- --------- ----------
Discounted future cash flows
before taxes 235,001 225,556 226,730
Discounted future income taxes (70,500) (63,156) (63,484)
--------- --------- ----------
Standardized measure of discounted
future net cash flows $164,501 $162,400 $163,246
--------- --------- ----------
--------- --------- ----------
December 31
---------------------------------------
IN THOUSANDS 1994 1993 1992
-------------------------------------------------------------------------------
Standardized measure --
beginning of year $162,400 $163,246 $169,629
Increases (Decreases):
Purchase of reserves 21,546 250 12,663
Sales, net of production costs (36,999) (38,905) (34,798)
Net changes in future prices and
production costs (10,507) 11,309 (3,554)
Extensions, discoveries and additions,
less related costs 21,772 6,859 2,734
Changes in future development costs 3,506 4,868 13,275
Revisions of previous quantity estimates 1,298 (13,501) (10,835)
Sale of reserves (246) (521) (150)
Accretion of discount 22,555 22,673 23,237
Net change in income taxes (7,344) 328 (745)
Changes in production rates related to
timing of demand (13,480) 5,794 (8,210)
--------- --------- ----------
Standardized measure -- end of year $164,501 $162,400 $163,246
--------- --------- ----------
--------- --------- ----------
40
Note Eight (Continued)
The 1994, 1993 and 1992 standardized measure of discounted future
net cash flows and related changes were computed using either yearend prices or
prices under contractual arrangements for oil and gas and yearend costs. A
significant portion of the Company's gas reserves are dedicated under a long-
term contract with its principal purchaser, K N Energy, Inc. (K N). The price
applicable to this contract is subject to annual renegotiation. Sales of gas to
K N during 1994, 1993 and 1992 represented 34%, 48% and 47%, respectively, of
total revenues of the Company. During 1994 and 1993, Associated Natural Gas,
Inc. purchased natural gas representing 11% of total revenues. A second major
customer during 1992 was Scurlock Oil Company which purchased oil representing
13% of total revenues of the Company. There were no other sales to customers
which accounted for more than 10% of total revenues of the Company during the
three years presented.
Estimated dismantlement and abandonment costs, net of estimated
salvage values of the properties, if material, are included as future costs in
computing discounted future net cash flows.
The Company periodically performs an impairment test by comparing
total capitalized costs with future undiscounted net revenues of its properties
on a geographic basis, by field or basin. No impairment was recognized in 1994.
An impairment of $9.3 million was recorded in 1993.
Effective tax rates of 30% for 1994 and 28% for 1993 and 1992
were used in computing discounted future income taxes, respectively, which
reflect the benefits which will accrue to the Company because of the reduction
from statutory tax rates due to the utilization of available tax loss
carryforwards which are present at yearend (see Note Four). Accretion of
discount recognizes the increase resulting from the passage of time.
41
Report of Independent Public Accountants
To the Board of Directors and Stockholders of Plains Petroleum Company:
We have audited the accompanying consolidated balance sheets of Plains
Petroleum Company (a Delaware corporation) and subsidiaries as of December 31,
1994 and 1993, and the related consolidated statements of earnings,
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1994. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Plains
Petroleum Company and subsidiaries as of December 31, 1994 and 1993, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1994, in conformity with generally accepted
accounting principles.
/s/ ARTHUR ANDERSEN LLP
Denver, Colorado
January 31, 1995.
42
ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10: DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
-------------------------------------------------------------------------------
YEAR
FIRST OTHER BUSINESS
ELECTED POSITIONS EXPERIENCE
AS AGE HELD WITH DURING PAST 5
DIRECT THE COMPANY YEARS; OTHER
OR DIRECTORSHIPS
-------------------------------------------------------------------------------------------------
DIRECTORS WHOSE TERMS EXPIRE IN 1995 (CLASS I)
-------------------------------------------------------------------------------------------------
WILLIAM W. GRANT, 1987 62 Director Advisory Director of Colorado
III National Bankshares, Inc. and
Colorado National Bank since
1993. Director of Colorado
National Bankshares, Inc. from
1982 through 1993, and
Chairman of the Board of
Colorado National Bank,
Denver, Colorado from 1986
through 1993. Chairman of the
Board of Colorado Capital
Advisors from 1989 through
1994.
CHARLES E. WRIGHT 1992 62 Director Attorney at Law in private
practice in Lincoln, Nebraska,
since 1959. Director of
FirsTier Bank, N.A., Lincoln,
Nebraska, since 1990.
-------------------------------------------------------------------------------------------------
DIRECTORS WHOSE TERMS EXPIRE IN 1996 (CLASS II)
-------------------------------------------------------------------------------------------------
DERRILL CODY 1990 56 Director Attorney at Law in private
practice in Oklahoma City,
Oklahoma, since January 1990.
Director of the General
Partner of TEPPCO Partners,
L.P. since January 1990.
Vice- President of Texas
Eastern Corporation from 1986
until December 1989. Chief
Executive Officer of Texas
Eastern Pipeline Company
43
from 1987 to 1989.
WILLIAM F. WALLACE 1994 55 Director. President Regional Vice President of
and Chief Operating Texaco Exploration and
Officer of Plains Production, Inc., New Orleans,
Petroleum Operating Louisiana, from 1989 to 1994.
Company, the Company's
operating subsidiary.
--------------------------------------------------------------------------------------------------
DIRECTORS WHOSE TERMS EXPIRE IN 1997 (CLASS III)
--------------------------------------------------------------------------------------------------
HARRY S. WELCH 1986 71 Director Attorney at Law in private
practice in Houston, Texas,
from August 1989 to present.
Served as Vice-President and
General Counsel of Texas
Eastern Corporation from 1988
through July 1989.
JAMES A. MILLER 1988 60 Director. Chairman
and Chief Executive
Officer.
<FN>
The additional information regarding executive officers required by
Item 401, Regulation S-K is included in Part I, Item 4 of this Form 10-K under
"Additional Item - Executive Officers of the Registrant."
44
ITEM 11: EXECUTIVE COMPENSATION
-------------------------------------------------------------------------------
The table below provides compensation information for the Company's chief
executive officer and the Company's four most highly compensated executive
officers, other than the chief executive officer, who were serving as executive
officers at the end of 1994 and whose total annual salary and bonus exceeded
$100,000.
-------------------------------------------------------------------------------
SUMMARY COMPENSATION TABLE
-------------------------------------------------------------------------------
ANNUAL LONG TERM
COMPENSATION(1) COMPENSATION(2)
--------------- ---------------
SECURITIES
UNDERLYING
OPTIONS/SARS ALL OTHER
NAME AND PRINCIPAL YEAR SALARY(3) BONUS(4) (#) COMPENSATION(5)
POSITION
---------------------------------------------------------------------------------------
James A. Miller 1994 $221,448 $0 12,843 $1,500
Chairman and 1993 221,448 0 0 539
Chief Executive Officer 1992 215,541 0 3,712 21,321
Robert M. Danos(6) 1994 200,856 0 4,833 1,500
President of 1993 200,856 0 0 539
Plains Petroleum 1992 195,488 0 3,712 20,896
Operating Company
Lee B. VanRamshorst 1994 135,960 20,000 7,228 1,500
Senior Vice President- 1993 135,960 0 0 539
Business Development of 1992 132,330 0 3,712 14,536
Plains Petroleum
Operating Company
Eugene A. Lang, Jr. 1994 127,560 8,000 25,460 1,500
Senior Vice President, 1993 127,560 0 0 539
General Counsel and 1992 124,150 0 3,712 13,501
Secretary
Robert W. Wagner 1994 117,120 0 6,283 1,500
Vice President, 1993 117,120 0 0 539
Land & Marketing of 1992 113,985 0 2,500 11,271
Plains Petroleum
Operating Company
-------------------------------------------------------------------------------
<FN>
(1) No named executive officer received perquisites and other personal benefits
in excess of the lesser of $50,000 or ten percent of his salary, as
reported in this table.
(2) The Company did not make restricted stock awards or payouts under long term
incentive plans in 1994, 1993 or 1992.
(3) Includes cash compensation deferred at the election of the named executive
officers under the Company's 401(k) Plan and Trust and the Company's
Executive Deferred Compensation Plan.
(4) The bonus figures reflect amounts paid in 1995 for services performed in
1994.
(5) The amounts disclosed in this column for 1994 represent the Company's
matching contribution, paid in Company Common Stock, under the 401(k) Plan
and Trust. The amounts disclosed in this column for 1993 represent the
45
Company's contributions to the Company's Payroll-Based Tax Credit Employee
Stock Ownership Plan, which plan was terminated on January 1, 1994. The
amounts disclosed in this column for 1992 include the following:
(a) the Company's contributions to the Company's Profit Sharing Plan and
Trust on behalf of Messrs. Miller ($20,789), Danos ($20,364),
VanRamshorst ($13,824), Lang ($12,969) and Wagner ($10,739), and
(b) the Company's contributions to the Company's Payroll-Based Tax Credit
Employee Stock Ownership Plan on behalf of Messrs. Miller ($532),
Danos ($532), VanRamshorst ($532), Lang ($532) and Wagner ($532).
As discussed in the Report of the Compensation Committee, effective January
1, 1993, officers no longer participate in the Company's Profit Sharing
Plan and Trust.
(6) From October 3, 1994 through January 3, 1995, Mr. Danos served as President
of Plains Petroleum Company. Mr. Danos retired on January 3, 1995.
William F. Wallace became a director of the Company and President of Plains
Petroleum Operating Company on October 3, 1994.
The table below provides information on the grants of stock options to the named
executive officers during 1994.(1)
------------------------------------------------------------------------------------------------------
NUMBER PERCENT
OF OF TOTAL POTENTIAL REALIZABLE
SECURITIES OPTIONS/SARS EXERCISE VALUE AT ASSUMED
UNDERLYING GRANTED TO OR BASE ANNUAL RATES OF
OPTIONS/SARS EMPLOYEES IN PRICE EXPIRATION STOCK PRICE APPRECIATION
NAME GRANTED 1994 ($/SHARE) DATE FOR OPTION TERM
(#)
------------------------------------------------------------------------------------------------------
5% ($) 10% ($)
-------- --------
James A. Miller 12,843 6.4% 20.6875 4/12/04 $167,091 $423,441
Robert M. Danos 4,833 2.4 20.6875 4/03/95(2) 62,879 159,451
Lee B. VanRamshorst 7,228 3.6 20.6875 4/12/04 94,038 238,311
Eugene A. Lang, Jr. 7,460 3.7 20.6875 4/12/04 97,056 245,960
18,000 9.0 22.1875 9/08/04 251,165 636,501
Robert W. Wagner 6,283 3.1 20.6875 4/12/04 81,743 207,154
<FN>
___________
(1) Included in this table are 4,833 option shares for Mr. Miller, 2,395 shares
for Mr. VanRamshorst, 2,627 shares for Mr. Lang and 1,450 shares for Mr. Wagner
which were granted in 1994 but were first exercisable on January 1, 1995. Also
included are 3,177 option shares granted to Mr. Miller in 1994 that are first
exercisable on January 1, 1996. These 3,177 option shares granted to Mr. Miller
would become immediately exercisable upon certain events constituting a change
in control of the Company. The last reported sales price of the Company's
Common Stock on the New York Stock Exchange on December 31, 1994 was $23.375 per
share.
(2) Mr. Danos retired on January 3, 1995. Under the Company's employee option
plans, a retiree must exercise his or her options within three
months of retirement.
The table below provides information on the value of the named executive
officers' unexercised options. No stock options were exercised by the named
individuals during 1994.
OPTION VALUES AT DECEMBER 31, 1994(1)
---------------------------------------------------------------------------------------------
NUMBER OF SECURITIES UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED OPTIONS/SARS IN-THE-MONEY OPTIONS/SARS
AT 12-31-94(1) AT 12-31-94(1)
EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
NAME (#) ($)
---------------------------------------------------------------------------------------------
James A. Miller 19,542/8,010 $ 12,989/21,527
46
Robert M. Danos 19,019/0 12,989/0
Lee B. VanRamshorst 33,169/2,395 65,720/6,437
Eugene A. Lang, Jr. 33,303/2,627 34,364/7,060
Robert W. Wagner 26,012/1,450 30,837/3,897
---------------------------------------------------------------------------------------------
<FN>
(1) The last reported sales price of the Company's Common Stock on the New York
Stock Exchange on December 31, 1994 was $23.375 per
share.
47
The following table shows the estimated annual benefits payable upon retirement
to Company employees under the Company's retirement plan and supplemental
retirement plan.
HIGH THREE YEARS OF SERVICE
YEAR AVERAGE --------------------------------------------------------------------
------------ 15 YEARS 20 YEARS 25 YEARS 30 YEARS 35 YEARS
$125,000 $30,989 $41,319 $ 51,649 $ 61,978 $ 72,308
150,000 37,552 50,069 62,586 75,103 87,620
175,000 44,114 58,819 73,524 88,228 102,933
200,000 50,677 67,669 84,461 101,353 118,245
225,000 57,239 76,319 95,399 114,478 133,538
250,000 63,802 85,069 106,336 127,603 148,870
-----------------------------------------------------------------------------------------
Annual pension benefits under such plan at the normal retirement age of 65 are
equal to accrued annuity credits. The yearly retirement credit for each plan
year from September 13, 1985 until December 31, 1988 equaled 1.3 percent of the
first $8,400 of compensation and 2.1 percent of amounts in excess of $8,400.
For participants who complete a year of service after December 31, 1988, the
credits are equal to the greater of (a) the foregoing credits plus those based
on 2.0 percent of total monthly compensation after January 1, 1989 or (b)
credits based upon 1.25 percent of average compensation during the three
consecutive years within the last ten years of employment when compensation was
the highest, times years of service, plus 0.50 percent of such average
compensation that exceeds the Social Security taxable wage base in effect for
each year of service, times years of service (not to exceed 35 years). For
purposes of the pension plan, compensation includes salary, overtime and special
duty compensation and excludes bonuses and commissions. For each of the named
executive officers, the compensation covered by the plan is the amount reported
as such officer's salary in the summary compensation table above. Benefits
under the plan are paid monthly after retirement for the life of the participant
(straight-life annuity amount). Benefits under the plan are not subject to the
deduction for Social Security benefits or other offset amounts. The named
executive officers have accrued the following years of service for funding of
benefits under the plan: Mr. Miller, 7 years; Mr. Danos, 6 years; Mr.
VanRamshorst, 10 years; Mr. Lang, 5 years; and Mr. Wagner, 10 years. Mr. Danos
retired on January 3, 1995. The benefits illustrated in this table do not
reflect Internal Revenue Code Sections 415 and 401(a) limitations to which the
plan is subject. If payment of actual retirement benefits is limited by such
provisions, an amount equal to any reduction in retirement benefits will be paid
as supplemental benefits under the Plains Petroleum Supplemental Retirement
Plan.
EMPLOYMENT CONTRACTS
--------------------------------------------------------------------------------
Mr. Miller is a party to an agreement with the Company which provides, among
other things, that if, within three years after a "change in control" (as
defined in such agreement), Mr. Miller's employment with the Company is
involuntarily terminated or is terminated by Mr. Miller for "Good Reason," he is
to be paid promptly a cash amount equal to 299 percent of the higher of (a) his
then annual compensation (including salary, bonuses and incentive compensation)
or (b) the highest annual compensation (including salary, bonuses and incentive
compensation) paid or payable during any of the three calendar years ending with
the year of his termination. "Good Reason" is defined as a reduction in Mr.
Miller's compensation or employment responsibilities, a required relocation
outside the greater Denver, Colorado area or, generally, any conduct by the
Company which renders the executive unable to discharge his employment duties
effectively.
Messrs. VanRamshorst, Wagner and Lang are also parties to severance agreements
identical to the agreement with Mr. Miller, except that the agreements with
Messrs. VanRamshorst, Wagner and Lang provide for payment equal to two times the
then annual compensation or the highest annual compensation paid or payable
during either one of the two calendar years immediately preceding termination.
48
COMPENSATION OF DIRECTORS
--------------------------------------------------------------------------------
Effective December 1, 1993, a director who is otherwise not employed by the
Company or its subsidiaries receives a retainer of $1,300 per month and a fee of
$900 per day of each Board or committee meeting attended. Directors who are
full-time employees of the Company or its subsidiary receive no additional
compensation for their services as directors. All directors, however, are
reimbursed for reasonable travel expenses incurred in attending all meetings.
Directors who are not also employees of the Company participate in the 1985
Stock Option Plan for Non-Employee Directors (the "Directors Plan"). Options
granted pursuant to the Directors Plan are not intended to qualify as incentive
stock options. Under the Directors Plan, each Director who is not a salaried
employee of the Company, within 30 days after election or re-election to the
Company's Board of Directors, will be granted options to purchase a number of
shares of Common Stock equal to 1,000 multiplied by the number of years in the
term to which he or she is elected. If any person is elected by the Board of
Directors to fill an unexpired term or vacancy on the Board of Directors, within
30 days of the election, such person will be granted options for a number of
shares equal to 1,000 multiplied by the number of twelve-month periods of the
director's term (rounded up for any fraction of a twelve-month period). In
1994, Harry S. Welch received options to purchase 3,000 shares at the exercise
price of $21.00 per share.
49
ITEM 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
--------------------------------------------------------------------------------
The following table sets forth, as of March 15, 1995, the beneficial ownership
of the Company's Common Stock by the Company's directors, each of the executive
officers listed in the Summary Compensation Chart and all executive officers and
directors as a group.
NUMBER OF SHARES
NAME BENEFICIALLY OWNED(1) PERCENTAGE OF CLASS
--------------------------------------------------------------------------------
Derrill Cody 5,200 *
William W. Grant, III 15,500 *
Eugene A. Lang, Jr. 38,882(2) *
James A. Miller 38,056(3) *
Lee B. VanRamshorst 39,733(4) *
Robert W. Wagner 28,899(5) *
William F. Wallace 11,637(6) *
Harry S. Welch 10,000 *
Charles E. Wright 5,254(7) *
All executive officers and 266,728 2.72%
directors as a group (12 persons)
--------------------------------------------------------------------------------
<FN>
(1) For purposes of determining the numbers of shares beneficially owned by the
named individuals and by all executive officers and directors as a group,
with respect to any director or executive officer who held options to
purchase shares of the Company's Common Stock exercisable within 60 days of
March 15, 1995, it was assumed that such options had been exercised and
the shares issued were outstanding. The following number of shares
representing such unexercised options were added to the holdings of each
of the following directors and officers: Mr. Cody 5,000 shares; Mr. Grant
8,000 shares; Mr. Lang 35,932 shares; Mr. Miller 27,552 shares;
Mr. VanRamshorst 35,564 shares; Mr. Wagner, 27,462; Mr. Wallace
11,428 shares; Mr. Welch 8,000 shares; Mr. Wright 3,000 shares; and all
executive officers and directors as a group 218,073 shares. The respective
directors and executive officers have sole voting power and sole
investment power over all shares reflected in the table and in this note,
except as described in the notes to this table.
(2) Includes 1,000 shares as to which Mr. Lang has shared investment power and
shared voting power and 1950 shares as to which Mr. Lang has no investment
power and sole voting power.
(3) Includes 85 shares owned by Mr. Miller's wife individually or as custodian
for their child over which Mr. Miller disclaims beneficial ownership and
over which he has neither investment nor voting power, 1,000 shares as to
which Mr. Miller has shared investment power and shared voting power and
4,419 shares as to which Mr. Miller has no investment power and sole voting
power.
(4) Includes 200 shares owned by Mr. VanRamshorst's children over which Mr.
VanRamshorst disclaims beneficial ownership and over which he has neither
investment power nor voting power and 3,969 shares as to which Mr.
VanRamshorst has no investment power and sole voting power.
(5) Includes 300 shares as to which Mr. Wagner has shared investment power and
shared voting power and 992 shares as to which Mr. Wagner has no investment
power and sole voting power.
50
(6) Includes 209 shares as to which Mr. Wallace has no investment power and
sole voting power.
(7) Includes 254 shares owned by Mr. Wright's wife over which Mr. Wright
disclaims beneficial ownership and over which he has neither investment
nor voting power.
* Less than 1 percent of the outstanding shares of Common Stock.
According to publicly available information, as of March 15, 1995, the only
entities that owned more than 5 percent of the outstanding shares of Common
Stock of the Company were as follows:
NAME AND ADDRESS AMOUNT AND NATURE OF PERCENTAGE
OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP OF CLASS
---------------------------------------------------------------------------------------------
State Farm Mutual Automobile Insurance Company 711,410 7.25%
and related entity (1)
One State Farm Plaza
Bloomington, Illinois 61710
Cross Timbers Oil Company and related entity(2) 644,500 6.57%
810 Houston Street, Suite 2000
Fort Worth, Texas 76102
---------------------------------------------------------------------------------------------
<FN>
(1) According to its Schedule 13G dated January 24, 1995 filed with the
Securities and Exchange Commission. The Schedule 13G states that State
Farm Mutual Automobile Insurance Company has sole voting and sole
investment power with respect to 611,410 shares of the Common Stock of the
Company, and State Farm Fire and Casualty Company has sole voting power and
sole investment power with respect to 100,000 shares of the Common Stock of
the Company.
(2) According to its Schedule 13D dated September 19, 1994, Amendment No. 1
thereto dated October 20, 1994, Amendment No. 2 thereto dated November 18,
1994 and Amendment No. 3 thereto dated February 10, 1995 filed with the
Securities and Exchange Commission. Amendment No. 3 to such Schedule 13D
states that Cross Timbers Oil Company has sole voting power and sole
investment power with respect to 644,400 shares of Common Stock of the
Company and shares voting and investment power with WTW Properties, Inc., a
newly-formed and wholly-owned subsidiary of Cross Timbers Oil Company, with
respect to 100 shares of Common Stock of the Company.
51
ITEM 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
--------------------------------------------------------------------------------
The Company had a loan commitment through February 17, 1995 from three banks,
one of which was Colorado National Bank ("CNB"), a wholly owned subsidiary of
Colorado National Bankshares, Inc. CNB's portion of the commitment was $9
million, and it received an annual commitment fee of approximately $17,978 in
1994. William W. Grant, III, a director of the Company, was Chairman of the
Board of CNB and a director of Colorado National Bankshares, Inc. through June
1993, and he now serves as an advisory director of CNB and Colorado National
Bankshares, Inc.
52
PART IV
ITEM 14: EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
--------------------------------------------------------------------------------
(A) See Item 8 of Form 10-K with respect to financial statements.
(B) The Financial Data Schedule included as an exhibit to this report on
Form 10-K should be read in conjunction with the financial statements
in Item 8. Schedules not included with these financial statement
schedules have been omitted because they are not applicable or the
required information is shown in the financial statements or notes
thereto.
(C) The Exhibit Index which follows lists the exhibits to this report
which are filed herewith, except those incorporated by reference as
indicated.
(D) REPORTS ON FORM 8-K:
The following report on Form 8-K was filed by the Company during the
last quarter of the year ended December 31, 1994 included in this Form
10-K, and is incorporated by reference in this report:
(1) Date of Report: October 19, 1994
Items Reported:
ITEM 5 - OTHER EVENTS
Amendment to Rights Agreement dated October 19, 1994 between the
Registrant and Chemical Bank, as successor Rights Agent, to
Rights Agreement dated May 12, 1988, to preserve the ability of
the Board of Directors to control the study process and to pursue
business combinations to the best interest of the shareholders.
ITEM 7 - FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
AND EXHIBITS
Exhibits related to Amendment to Rights Agreement dated
October 19, 1994, noted in Item 5.
(2) Date of Report: November 15, 1994
Items Reported:
ITEM 2 - ACQUISITION OR DISPOSITION OF ASSETS
Acquisition of certain oil and gas properties from Anadarko
Petroleum Corporation.
ITEM 7 - FINANCIAL STATEMENTS, PRO FORMA FINANCIAL INFORMATION
AND EXHIBITS
No financial information was available at the time of the report
filing. Information was subsequently provided in an amended
report in January 1995.
53
EXHIBIT INDEX
Exhibit Footnote
Number Reference Description of Document
------ --------- -----------------------
3(a) Restated Certificate of Incorporation of Plains
Petroleum Company.
3(b) Certificate of Correction of Restated Certificate
of Incorporation of Plains Petroleum Company.
3(c) (1) By-laws of Plains Petroleum Company.
4(a) (2) Preferred Stock Rights Purchase Agreement made as
of May 12, 1988 between Plains Petroleum Company
and Manufacturers Hanover Trust Company.
4(b) (24) Amendment dated October 19, 1994 between Plains
Petroleum Company and Manufacturers Hanover Trust
to Exhibit 4(a).
The provisions in Registrant's Restated
Certificate of Incorporation and By-laws defining
the rights of holders of its equity securities
are included in Exhibits 3(a), 3(b) and 3(c).
4(c) (15) Credit Agreement effective January 1, 1991
between Plains Petroleum Company, Plains
Petroleum Operating Company and NCNB Texas
National Bank, et.al.
4(d) (17) Amendment to Credit Agreement effective January
1, 1992 between Plains Petroleum Company, Plains
Petroleum Operating Company and NationsBank of
Texas, N.A., et.al.
4(e) (20) Second amendment to Credit Agreement effective
January 1, 1993 between Plains Petroleum Company,
Plains Petroleum Operating Company and
NationsBank of Texas, N.A., et.al.
4(f) (22) Third Amendment to Credit Agreement effective
January 1, 1994 between Plains Petroleum Company,
Plains Petroleum Operating Company and
NationsBank of Texas, N.A., et al.
4(g) Credit Agreement effective February 17, 1995
between Plains Petroleum Operating Company and
NationsBank of Texas, N.A., et.al.
10(a) (3) Service Agreement between Plains Petroleum
Company and K N Energy, Inc.
10(b) (6) Amendment dated August 11, 1986 between Plains
Petroleum Company and K N Energy, Inc. to Exhibit
Number 10(a).
10(c) (1) Amendment as of January 1, 1988 between Plains
Petroleum Company and K N Energy, Inc. to Exhibit
Number 10(a).
54
Exhibit Footnote
Number Reference Description of Document
------- --------- -----------------------
10(d) (4) Gas Purchase Contract. No. P-1090, dated April
20, 1984, as amended June 25, 1985, between
Plains Petroleum Company and K N Energy, Inc.
10(e) (6) Amendment dated October 30, 1986 between Plains
Petroleum Company and K N Energy, Inc. to Exhibit
Number 10(d).
10(f) (12) Amendment dated April 11, 1990 between Plains
Petroleum Operating Company and K N Energy, Inc.
to Exhibit Number 10(d).
10(g) (17) Amendments dated July 12, July 24 and July 25 of
1991 between Plains Petroleum Operating Company
and K N Energy, Inc. to Exhibit Number 10(d).
10(h) (19) Agreement dated September 3, 1992 to Redetermine
Price Under Purchase Contract No. P-1090 and
Conditions of Future Amendment for Release of
Contract Gas Purchases between K N Energy, Inc.
and Plains Petroleum Operating Company
10(i)-1 (21) Agreement dated August 25, 1993 to Redetermine
Price Under Purchase Contract No. P-1090 between
KN Energy, Inc. and Plains Petroleum Operating
Company.
10(i)-2 (23) Agreement to Release of Pre-636 Exchange Gas
P-1090 dated July 13, 1994 between Plains
Petroleum Operating Company and K N Gas Supply
Services, Inc.
10(i)-3 Agreement dated December 8, 1994 between Plains
Petroleum Operating Company and K N Energy, Inc.
to Exhibit Number 10(d).
21 Subsidiaries of the registrant.
23(a) Consent of Independent Public Accountants.
23(b) Consent of Independent Reservoir Engineer.
27 Financial Data Schedule for the year ended
December 31, 1994.
99(a) Form 11-K for the year ended December 31, 1992
dated March 31, 1995.
99(b) Form 11-K for the year ended December 31, 1993
dated March 31, 1995.
99(c) Form 11-K for the year ended December 31, 1994
dated March 31, 1995.
55
Exhibit Footnote
Number Reference Description of Document
------- --------- -----------------------
COMPENSATION PLANS AND AGREEMENTS
10(j) (4) 1985 Incentive Stock Option Plan.
10(k) (4) 1985 Stock Option Plan for Non-Employee Directors
10(l) (9) 1989 Stock Option Plan
10(m) (18) 1992 Stock Option Plan
10(n) (4) Employment Agreement dated April 1, 1985 between
Plains Petroleum Company and Elmer J. Jackson.
10(o) (10) Amended and Restated Employment Agreement dated
March 17, 1989 between Plains Petroleum Company
and Elmer J. Jackson.
10(p) (4) Severance Agreement dated May 1, 1985 between
Plains Petroleum Company and Robert W. Wagner.
10(q) (6) Severance Agreements between Plains Petroleum
Company and Darrel M. Reed, Robert A. Miller,
Jr., David L. Cook, and Lee B. VanRamshorst, and
dated July 22, 1985; September 16, 1985; August
26, 1985; and November 18, 1985, respectively.
10(r) (8) Amendment to Severance Agreements dated June 1,
1988 between Plains Petroleum Company and Darrel
M. Reed, Robert A. Miller, Jr., Robert W. Wagner,
and Lee B. VanRamshorst, respectively.
10(s) (20) Director's Deferred Fee Plan dated August 8,
1987.
10(t) (20) Executive Deferred Compensation Plan dated
August 8, 1987.
10(u) (20) First and Second Amendments to the Executive
Deferred Compensation Plan dated December 1, 1988
and August 26, 1992, respectively.
10(v) (13) Plains Petroleum Company 401(k) Plan & Trust.
10(w) (7) Severance Agreement dated May 1, 1988 between
Plains Petroleum Company and James A. Miller.
56
Exhibit Footnote
Number Reference Description of Document
------ --------- -----------------------
10(x) (10) Severance Agreement dated January 23, 1989
between Plains Petroleum Company and Robert M.
Danos.
10(y) (11) Amendment to Severance Agreements dated May 12,
1989 between Plains Petroleum Company and James
A. Miller and Robert M. Danos, respectively.
10(z) (14) Severance Agreement dated September 26, 1990
between Plains Petroleum Company and Eugene A.
Lang, Jr.
10(aa) (16) Severance Agreement dated May 13, 1991 between
Plains Petroleum Company and John N. Wood.
10(bb) (20) Incentive Compensation Plan dated February 18,
1993.
10(cc) (24) Amendment to 1985, 1989 and 1992 Stock Option
Plans, dated September 8, 1994.
10(dd) (24) Employment Agreement dated August 7, 1994 between
Plains Petroleum Operating Company and William F.
Wallace.
10(ee) (24) Amendment of Employment Agreement dated
October 3, 1994 between Plains Petroleum
Operating Company and William F. Wallace.
______________________________
(1) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 28, 1988. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(2) Incorporated by reference to Plains Petroleum Company's Registration
Statement on Form 8-A dated May 20, 1988.
(3) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 27, 1986. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(4) Incorporated by reference to Plains Petroleum Company's Registration
Statement on Form 10 dated August 21, 1985.
(5) [Intentionally omitted]
57
(6) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 30, 1987. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(7) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated May 13, 1988. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(8) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated August 11, 1988. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(9) Incorporated by reference to Plains Petroleum Company's Proxy Statement,
Exhibit A, dated March 21, 1989. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(10) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated May 12, 1989. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(11) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 28, 1990. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(12) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated May 7, 1990. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(13) Incorporated by reference to Plains Petroleum Company's Registration
Statement on Form S-8 (Amendment No. 1) dated June 18, 1990 and (Amendment
No. 2) dated December 21, 1993.
(14) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated November 13, 1990. [SEC file number 1-8975] [available on]
microfiche at the SEC]
(15) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 27, 1991.
(16) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated August 13, 1992.
(17) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 26, 1992.
(18) Incorporated by reference to Plains Petroleum Company's Proxy Statement,
Exhibit A, dated March 26, 1992.
(19) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated November 12, 1992.
(20) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 26, 1993.
58
(21) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated November 11, 1993.
(22) Incorporated by reference to Plains Petroleum Company's Annual Report on
Form 10-K dated March 28, 1994.
(23) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated August 12, 1994.
(24) Incorporated by reference to Plains Petroleum Company's Quarterly Report on
Form 10-Q dated November 11, 1994.
59
ADDITIONAL ITEM -
For purposes of complying with the amendments to the rules governing Form
S-8 (effective July 13, 1990) under the Securities Act of 1933, the registrant
hereby undertakes as follows, which undertaking shall be incorporated by
reference into registrant's Registration Statements on Form S-8 Nos. 33-30507
(filed August 11, 1989), 33-35306 (filed June 18, 1990 and December 21, 1993)
and 33-54636 (filed November 16, 1992);
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
registrant has been advised that in the opinion of the Securities and
Exchange Commission such indemnification is against public policy as
expressed in the Securities Act of 1933 and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities
(other than the payment by the registrant of expenses incurred or paid by a
director, officer or controlling person of the registrant in the successful
defense of any action, suit or proceeding) is asserted by such director,
officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the
matter has been settled by controlling precedent, submit to a court of
appropriate jurisdiction the question whether such indemnification by it is
against public policy as expressed in the Act and will be governed by the
final adjudication of such issue.
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SIGNATURES
Pursuant to the requirements of the Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
PLAINS PETROLEUM COMPANY
March 30, 1995 By: /s/ Darrel Reed
--------------------------------
Darrel Reed
Vice President and Chief Accounting Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date
indicated.
/s/ James A. Miller Chairman, Chief Executive March 30, 1995
-------------------------- Officer and Director
James A. Miller
/s/ William F. Wallace President and Chief Operating March 30, 1995
-------------------------- Officer (Plains Petroleum
William F. Wallace Operating Company) and Director
/s/ Derrill Cody Director March 30, 1995
--------------------------
Derrill Cody
/s/ William W. Grant, III Director March 30, 1995
--------------------------
William W. Grant, III
/s/ Harry S. Welch Director March 30, 1995
--------------------------
Harry S. Welch
/s/ Charles E. Wright Director March 30, 1995
--------------------------
Charles E. Wright
61