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.
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.
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.
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:

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.
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.
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.
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.
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.
Proved reserves added from extensions, discoveries and other additions in each year were as follows:
(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.
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.
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:

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.
ITEM 4:

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.
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:

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.
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.
ITEM 6:

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.
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.
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.
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

ITEM 8: FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PLAINS PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF EARNINGS
The accompanying notes are an integral part of these financial statements.
PLAINS PETROLEUM COMPANY
CONSOLIDATED BALANCE SHEETS Successful Efforts Accounting Method
The accompanying notes are an integral part of these financial statements.
PLAINS PETROLEUM COMPANY CONSOLIDATED BALANCE SHEETS Successful Efforts Accounting Method
The accompanying notes are an integral part of these financial statements.
PLAINS PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these financial statements.
PLAINS PETROLEUM COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
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.
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:
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.
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.
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:
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:
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:
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.
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:
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%.
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:
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:
* 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.
Note Five (Continued)
Net periodic postretirement benefit cost included the following components:
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.
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.
NOTE SEVEN COMPARATIVE QUARTERLY RESULTS (UNAUDITED)
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".
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.
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.
Note Eight (Continued)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGE THEREIN RELATING TO PROVED RESERVES (UNAUDITED)
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.
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.
ITEM 9:

ITEM 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.
PART III
ITEM 10:

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 -------------------------------------------------------------------------------
The table below provides information on the grants of stock options to the named executive officers during 1994.(1)
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)
The following table shows the estimated annual benefits payable upon retirement to Company employees under the Company's retirement plan and supplemental retirement plan.
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.
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.
ITEM 12:

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.
ITEM 13:

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.
PART IV
ITEM 14:

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.
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).
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.
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.
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]
(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.
(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.
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.
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