PRIMA ENERGY CORP - 10-K Annual Report

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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

[ X ] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2001.

[ ] Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934.

COMMISSION FILE NUMBER 0-9408

PRIMA ENERGY CORPORATION
(Exact name of Registrant as specified in its charter)

DELAWARE 84-1097578
(State or other jurisdiction (I.R.S. Employer Identification No.)
of incorporation or organization)

1099 18TH STREET, SUITE 400, DENVER, COLORADO 80202
(Address of principal executive offices) (Zip Code)

(303) 297-2100
(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act
NONE

Securities registered pursuant to Section 12(g) of the Act
COMMON STOCK, $0.015 PAR VALUE
(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 [ ]

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 the Form 10-K or any amendment to this
Form 10-K. [ ]

Aggregate market value of the 8,965,191 shares of Common Stock held by
non-affiliates of the Registrant as of March 15, 2002 was $225,519,380 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).

As of March 15, 2002, Registrant had outstanding 12,728,672 shares of Common
Stock, $0.015 Par Value, its only class of voting stock.

DOCUMENT INCORPORATED BY REFERENCE
Parts of the following document are incorporated by reference to Part III of the
Form 10-K Report: Proxy Statement for the Registrant's 2002 Annual Meeting of
Stockholders.

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TABLE OF CONTENTS

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PART I

ITEMS 1 and 2. BUSINESS and PROPERTIES

The "Company" or "Prima" is used in this report to refer to Prima
Energy Corporation and its consolidated subsidiaries. Items 1 and 2 contain
"forward-looking statements" that are made pursuant to the "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995. These
statements include, without limitation, statements relating to the drilling and
completion of wells, well operations, utilization rates of oilfield service
equipment, gathering and compression of wells, reserve estimates (including
estimates for future net revenues associated with such reserves and the present
value of such future net reserves), business strategies, and other plans and
objectives of Prima management for future operations and activities and other
such matters. The words "believes," "plans," "intends," "strategy," "budgeted,"
"expected" or "anticipates" and similar expressions identify forward-looking
statements. Prima does not undertake to update, revise or correct any of the
forward-looking information. Readers are cautioned that such forward-looking
statements should be read in connection with Prima's disclosures under the
heading: "Cautionary Statement for the Purposes of the 'Safe Harbor' Provisions
of the Private Securities Litigation Reform Act of 1995".

GENERAL - THE COMPANY

Prima was incorporated in April 1980 for the purpose of engaging in the
exploration for, and the acquisition, development and production of crude oil
and natural gas, and for other related business activities. In October 1980, the
Company became publicly owned with a $3.6 million common stock offering. In
subsequent years, the Company's activities were expanded through its wholly
owned subsidiaries to include oil and gas property operations, oilfield
services, and natural gas gathering, marketing and trading. However, a
substantial majority of Prima's consolidated assets and revenue continue to be
related to its oil and gas production operations.

The Company organizes its principal activities in operating segments
that consist of the acquisition, exploration, development and operation of oil
and gas properties, and providing oilfield services for wells which it operates
and for unaffiliated third parties. During 2000, the Company initiated gas
gathering and compression operations, but these activities were not material to
Prima's operations at December 31, 2001. Prima's oil and gas exploration,
development and production activities are conducted by Prima Oil & Gas Company,
a wholly owned subsidiary. Wholly owned subsidiaries of Prima Oil & Gas Company
conduct the following activities: oilfield services by Action Oil Field
Services, Inc. and Action Energy Services; natural gas gathering and compression
by Arete Gathering Company, LLC; and natural gas marketing and trading by Prima
Natural Gas Marketing, Inc. For a more detailed discussion of the Company's
business segments, including revenues earned from third parties, operating
earnings and total assets, see "Segment Information" in the Notes to
Consolidated Financial Statements.

Prima's activities are principally conducted in the Rocky Mountain
region of the United States. The Company owns or controls leasehold interests in
over 595,000 gross, 393,000 net acres, predominately in the Denver Basin of
Colorado, the Powder River, Wind River, Big Horn and Green River basins of
Wyoming and the Wasatch Plateau and Overthrust Belt of Utah. For a discussion of
these areas, see "Properties with Production, Development, Exploitation and
Lower-Risk Exploration Activities" and "Other Exploratory Prospects and Acreage"
below.

Prima has identified more than 1,400 potential exploitation and
development opportunities on its acreage as of the end of 2001, including
drilling, recompletion and refracturing projects. Of these, 491 were assigned
proved oil and gas reserves at year-end 2001. Most of the identified non-proved
opportunities represent potential drilling locations on the Company's acreage in
the Powder River Basin coalbed methane ("CBM") play, where the Company's
internal and independent engineers have assigned estimated probable reserves.
These numbers reflect only those projects that might be economically viable
using unescalated year-end oil and gas prices, and have been adjusted to exclude
identified opportunities associated with certain CBM assets that were sold in
March 2002 (see "Subsequent Event" in the Notes to Consolidated Financial
Statements). Prima plans to continue to identify, develop and exploit
opportunities in its principal business operations over the next few years,
including the multi-year set of opportunities that the Company has identified on
its acreage holdings in the Powder River Basin CBM play.

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At December 31, 2001, the Company reported the following:

o $135,444,000 of assets.

o $28,122,000 of net working capital.

o Estimated net proved reserves of 135.6 Bcfe, with a pre-tax present
value using a 10% discount factor ("PV10") of $92 million, based on
constant year-end average prices of $1.94 per Mcf of natural gas and
$19.71 per barrel of oil. An alternate price case using average prices
of $2.33 per Mcf and $21.53 per barrel, based upon five-year forward
prices at the end of 2001, resulted in estimated net proved reserves of
156.1 Bcfe with PV10 of $122 million.

o 563,000 gross, 367,000 net, undeveloped acres and 32,300 gross, 26,500
net, developed acres.

o Operations of 695 productive wells, representing approximately 93% of
the productive wells in which Prima owns a working interest.

For the year ended December 31, 2001, the Company reported the
following:

o Net income of $23,768,000.

o Cash provided by operating activities of $43,008,000.

o Average daily net production of 25,416 Mcf of natural gas and 1,181
barrels of crude oil (32,501 Mcfe).

o Average price realizations of $3.60 per Mcf of natural gas and $25.88
per barrel of crude oil.

STRATEGY

OBJECTIVE. The Company seeks to create shareholder value by identifying,
evaluating and seizing opportunities where it can acquire, develop, operate and
market future reserves at superior margins on a risk-adjusted present value
basis. It is a goal of the Company to be one of the lowest cost producers with
the highest cash flow margins for reinvestment in the industry. Prima also seeks
to create value through oil and gas service operations that complement the
Company's exploration and production activities.

ACREAGE. Prima attempts to acquire leasehold acreage at reasonable costs with
attractive terms in prospective areas. The Company can potentially benefit from
the activities of other operators in these areas as well as from its own
activities.

OPERATIONS. It is generally the Company's objective to operate the oil and gas
properties in which it has significant economic interests. Prima believes that,
as operator, it is in a better position to control costs, safety, timeliness and
quality of work, and other factors affecting the profitability of a property.

EXPLOITATION. The Company intends to continue its exploitation efforts in all of
the operating areas. In the Denver Basin, we plan to continue well refracturing,
restimulation and development drilling, to the extent warranted by ongoing
results and economic success. Prima has been drilling wells in the Denver Basin
for 20 years, and refracturing wells in the area for over seven years. We also
plan to continue exploitation activity in the Powder River Basin, for both
conventional and coal seam reservoirs, and in the Wind River Basin, depending
upon the merit of each activity and subject to regulatory considerations. These
activities are generally low to moderate-risk endeavors that meet our economic
criteria.

EXPLORATION. The Company typically allocates 5% to 20% of its capital
expenditures budget for exploration activities. These activities may include
leasehold acquisition, geologic and geophysical evaluation, and either drilling
our own internally-generated prospects or participating in other operators'
prospects. The objective of our exploration activities is to expose a portion of
our capital to higher-risk projects where, we believe, the potential warrants
the higher risk. As compared to individual exploitation activities, exploration
projects could have a more significant impact on the value of the Company but
the likelihood of success is lower.

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GATHERING, MARKETING AND TRADING. The Company, to the extent possible and
warranted, markets its own natural gas and crude oil. Prima believes it can
better monitor its product pricing, and service and market conditions by
actively marketing and selling its products. The Company may own assets
downstream of the wellhead, including but not limited to gathering and
compression facilities. This is done, where warranted, in an effort to improve
overall project economics and enable Prima to capture more of the value chain
from wellhead to burner tip. Prima may also gather, compress and market
third-party gas.

WELL DRILLING AND SERVICING. Prima believes that it can better control the
timing, quality and cost of work performed on its wells by owning and operating
various well servicing equipment. The Company also intends for this activity to
constitute a separate profit center for work performed for third parties. We
have been involved in various aspects of the well servicing business for 14
years in the Denver Basin and started an oilfield drilling and service company
in the Powder River Basin in 1999.

MERGER, ACQUISITION AND DIVESTITURE. In its ordinary course of business, the
Company regularly reviews merger, acquisition and divestiture opportunities
related to the oil and gas industry that could enhance its business.

OIL AND GAS PRODUCTION OPERATIONS

PROPERTIES WITH PRODUCTION, DEVELOPMENT, EXPLOITATION AND LOWER-RISK EXPLORATION
ACTIVITIES

DENVER BASIN

LOCATION, OPERATIONS AND ACREAGE. Prima's activities in the Denver Basin are
conducted primarily in the Wattenberg Area, which encompasses more than 1,000
square miles, between 20 and 55 miles northeast of Denver, Colorado. Prima also
owns leasehold interests and conducts operations on 4,480 acres near Denver
International Airport ("DIA"), where it has drilled and completed ten wells.
Prima operated 395 wells in the Denver Basin (including those near DIA) as of
December 31, 2001. Our leasehold position in the Denver Basin at the end of 2001
was 18,400 gross, 15,500 net, developed acres, with an additional 14,000 gross,
13,000 net, undeveloped acres.

FORMATIONS AND PRODUCTION. The Company's drilling and production activities have
been centered in a portion of the Wattenberg Area where the primary productive
reservoirs are found in the Codell and Niobrara sands. The Codell and Niobrara
sands blanket large areas of the field at depths of approximately 7,000 to 7,300
feet and have moderate porosity and low permeability. These formations require
fracture stimulation to establish economic production. Recoverable reserves from
any individual wellbore are controlled by reservoir quality, thickness and
fracture stimulation techniques. Our Denver Basin wells produce both natural gas
and crude oil. Prima's natural gas production in this area averages
approximately 1,240 Btu per Mcf and generally sells at a slight premium to Rocky
Mountain spot price due to the high Btu content. Natural gas liquids (propane,
butane, ethane, isobutane, pentane) are processed out of the well stream and
sold separately by third-party gatherer/purchasers but their value is reflected
in our wellhead price for natural gas. Our crude oil in this area is sweet and
generally commands a premium to Eastern Colorado and West Texas Intermediate
postings. During 2001, Denver Basin properties accounted for approximately 72%
of the Company's total Mcfe produced and 78% of the Company's total oil and gas
revenues excluding hedging gains, with natural gas averaging 16,658 Mcf per day
and crude oil averaging 1,134 barrels per day net to Prima's interests.

RESERVES AND DEVELOPMENT COSTS. The Denver Basin represented 47% of Prima's
year-end proved oil and gas reserves on an Mcfe basis. Codell/Niobrara wells
drilled and completed in this area typically cost approximately $275,000 and
target approximately 250,000 to 300,000 Mcfe of gross recoverable reserves per
well. At year-end 2001, the Company controlled approximately 200 potential
drillsites in the Denver Basin, with 35 of these attributed proved undeveloped
reserves. The Company's strategy has been to selectively drill wells utilizing
advanced drilling and completion techniques, and utilize improved marketing and
cost controls to enhance economic returns and establish proved reserves on
additional acreage. There is no assurance that these locations will ultimately
be drilled or that, if drilled, such wells will prove to be commercially
productive.

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CODELL/NIOBRARA REFRACTURING. Advancements in refrac stimulation technology
(applying a new fracture treatment to a producing formation in an older well)
have enabled Prima to add deliverability and reserves from the Codell and
Niobrara formations. The Company targets older wells with declining
deliverability for restimulation, and gives priority to those that qualify for
Section 29 tax credits of approximately $0.65 per Mcf on production through the
year 2002. Refracs completed by Prima in 2001 resulted in initial incremental
production rates averaging 110 Mcf of natural gas and 9 barrels of oil per day.
The refracs cost an average of approximately $110,000 and target approximately
125,000 Mcfe of incremental recoverable reserves.

2001 ACTIVITY. During 2001, the Company participated in the drilling of 19 gross
(18.8 net) wells and the refracturing or recompleting of 63 gross (58.4 net)
wells in the Denver Basin. All of these operations have been successfully
completed and all of the wells have been placed on or returned to production.
New wells and recompletion operations in the Denver Basin are characterized by
flush production at relatively high rates for a few months, after which lower
production levels are established at relatively shallow decline rates. The
Company generally accelerates these operations when oil and gas prices are high
and defers them when prices are low, to enhance the impact on investment returns
from the flush production. Because of oil and gas price declines, and high
line-pressure attributable to limited processing capacity in the area, Prima
elected to postpone certain drilling and recompletion operations that had been
scheduled for the third and fourth quarters of 2001. Following a recent recovery
in gas prices and the completion of an expansion of a third-party owned gas
processing plant, the Company has resumed recompletion operations, but is still
deferring new wells until costs decline or prices increase further.

FUTURE ACTIVITY. The Company intends to continue its development and
exploitation activities in the Denver Basin. We are currently budgeting for
capital investments in the Denver Basin aggregating between $5 million and $8
million in 2002. Planned activities include approximately six new
Codell/Niobrara wells in the Wattenberg Area, 36 Codell/Niobrara refrac
stimulations and six well recompletions. However, such plans are subject to
revision based on economic conditions, performance results, activities conducted
in other areas, and other factors.

POWDER RIVER BASIN - COALBED METHANE

LOCATION, OPERATIONS, ACREAGE. The coalbed methane play in the Powder River
Basin is prospective over a vast geographic area encompassing approximately
three million acres in northeastern Wyoming. The Company has been active in this
CBM play since 1999, and its operations have included drilling, producing,
oilfield services, and gathering and compression. According to the Wyoming Oil &
Gas Commission, over 12,000 CBM wells have been drilled to date, and
approximately 8,100 wells were producing approximately 817 MMcf of natural gas
per day as of December 2001. The Wyoming Oil & Gas Commission also indicated
that more than 60 drilling rigs were being utilized in the area in February
2002, making this the most active play in the United States. Prima has assembled
a significant leasehold position within the play, with parcels stretching from
the southernmost part of the play to its known limits on the northern end. This
leasehold position is generally close to gathering and transportation
infrastructure and, in several instances, is relatively close to areas of known
production. At December 31, 2001, Prima held 10,200 gross, 9,900 net, developed
acres, with an additional 141,000 gross, 130,000 net, undeveloped acres in this
play. This acreage is comprised of approximately 81% federal, 9% state, and 10%
fee (private) leases. The federal leases have an initial ten-year term, state
leases have a five-year term, and the terms of fee leases vary from a few months
to several years. The Company organized its Powder River Basin CBM acreage into
28 defined project areas for the convenience of operations management. On March
5, 2002, Prima closed the sale of a portion of its CBM acreage, representing
approximately 4,000 gross and net developed acres, and 40,000 gross, 35,000 net,
undeveloped acres. The acreage sold represented most of six project areas
located in the northern portion of the play and included the Company's
partially-developed Stones Throw project -- see "Subsequent Event" in the Notes
to Consolidated Financial Statements. Prima retained its acreage elsewhere in
the Powder River Basin CBM play where our assessment is that deeper, thicker
undeveloped coals hold the potential for better economic returns than obtainable
on the acreage sold.

FORMATION AND PRODUCTION. The primary target coals are located in the Fort Union
formation at depths ranging from 200 to 2,000 feet. It is common to encounter
multiple coal zones varying in thickness from a few feet to over 175 feet
between these depths. The methane in coal beds is absorbed, or attached, within
the coal layers and is held in place by water within the coals. When water is
produced from the coal seam, the pressure is reduced, allowing the gas to desorb
from the coal. Operators in the area have experienced de-watering times that
range from a few days to over one year, and

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the de-watering time is influenced by well density, coal depth, permeability,
well location and other factors. Individual well production rates have ranged
from a few Mcf to over 1,000 Mcf per day, and have averaged approximately 125
Mcf per day within the play to date. To produce gas in this CBM play, wells must
generally be hooked-up to a low-pressure gathering system and compression,
commonly referred to as "screw compression", which holds wellhead pressures to
approximately five pounds per square inch gauged ("psig"). The gas must then
move through a gathering system where, at its terminus, gas needs to be boosted
up to about 1,400 psig to enter a high-pressure header system line. This
high-pressure boost is commonly referred to as "reciprocating compression". CBM
gas from this area is generally somewhat less than 1,000 Btu per Mcf and may
require carbon dioxide extraction to meet interstate pipeline gas quality
specifications. Prima established its first significant Powder River Basin CBM
production in 2001 from the Stones Throw and Kingsbury properties, with
production rates generally increasing throughout the year. Combined, during 2001
these properties accounted for approximately 12% of the Company's Mcfe produced
and 5% of its total oil and gas revenues excluding hedging gains, with net gas
production averaging 3,980 Mcf per day for the full year and 6,995 Mcf per day
in the final quarter of the year.

RESERVES AND DEVELOPMENT COSTS. Powder River Basin CBM properties accounted for
46% of Prima's year-end proved oil and gas reserves on an Mcfe basis. CBM wells
generally cost from $75,000 to $125,000 to drill, equip and complete through the
sales meter, depending on location and depth, exclusive of gathering and
compression costs. A typical well will establish gross recoverable reserves of
200,000 to 500,000 Mcf. At year-end 2001, the Company's reserve report for the
CBM area included 116 proved developed producing wells, 81 wells classified as
proved developed non-producing and 230 locations assigned proved undeveloped
reserves. Based on engineering estimates prepared as of December 31, 2001, and
excluding assets sold on March 5, 2002, the Company believes it has a potential
inventory of over 1,600 drill sites in this play, subject to economic viability
which will vary with regional gas prices and other factors. The Company cautions
that well reserves and production capabilities may vary considerably depending
on location, thickness and depths of coals, number of coals present,
permeability, gas content, desorption, completion and production methods and
other factors, and will vary from one group of wells to another throughout the
basin. There is no assurance that these potential wells will be drilled or that
those drilled will ultimately develop economic reserves.

PERMITS - DRILLING, WATER DISCHARGE AND AIR QUALITY. Drilling permits for this
CBM play are issued by the Wyoming Oil & Gas Commission for wells located on
state and private lands. The Bureau of Land Management ("BLM") also issues
drilling permits on federal leaseholds following completion of an environmental
impact statement. The first environmental impact statement for the CBM play was
completed in 1999 and provided for the drilling of approximately 5,900 wells.
These permits have all been issued, and there has essentially been a moratorium
on issuing drilling permits for federal leaseholds pending issuance of a second
environmental impact statement ("EIS"), unless the location qualifies under an
Environmental Assessment that provides for the issuance of approximately 2,500
special drainage permits on federal leaseholds pending completion of the EIS.
The EIS, which is expected to provide for the drilling of approximately 50,000
CBM wells in the area, inclusive of wells drilled to date, is currently underway
with a record of decision expected in the latter part of 2002. The Company
anticipates much greater accessibility to its federal acreage after this EIS is
issued. A significant delay in the issuance of additional drilling permits on
federal acreage would significantly impact the Company's development plans for
the area. Water produced from CBM wells is generally potable (drinking water
quality) and can be discharged on the surface. Water discharge permits are
issued by the Wyoming Department of Environmental Quality ("DEQ"). Issuance of
water discharge permits slowed during the past year in order to address the
sodium absorption ratio and mineral content of water discharged in the basin and
its potential impact on agriculture. This issue is most acute for producers in
the northwestern portion of the play and Prima's operations are focused
primarily on the eastern side of the basin. An alternative to surface discharge
is water re-injection back into the ground, or "water recharge wells" which
could be used in the play, but add to expense. Air discharge permits, which are
required to operate natural gas fired compressors, are also issued by the DEQ,
and take approximately four months to be issued. The Company has not encountered
significant difficulties to date in acquiring air permits for its CBM
operations.

NATURAL GAS TRANSPORTATION INFRASTRUCTURE. The transportation infrastructure in
this basin is currently capable of moving approximately 1.4 Bcf (1,400,000 Mcf)
per day of natural gas. High-pressure header systems, including Bighorn Gas
Gathering LLC, Fort Union Gas Gathering LLC, and Thunder Creek Gas Services LLC,
feed downstream into interstate pipeline capacity provided by Colorado
Interstate Gas Company, Wyoming Interstate Pipeline, KM Interstate, Williston
Basin Interstate Pipeline, and MIGC Inc. Downstream of these interstate
pipelines, the pipeline grid is being enhanced by three current projects.
Trailblazer Pipeline is expected to be on line in June 2002 with a 324,000 Mcf
per day expansion that will move gas from the Cheyenne, Wyoming Hub to the
mid-continent. Kern River Pipeline is

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expected to be on line in May 2003 with an additional 900,000 Mcf per day that
will move gas from southwest Wyoming to Nevada and California markets. Front
Range Pipeline, which delivers natural gas from Cheyenne, Wyoming to Denver,
Colorado, is anticipated to add 440,000 Mcf per day of capacity by December
2002. Williams, Northern Border, Colorado Interstate Gas, Williston Basin
Interstate and KM pipelines have also announced potential projects to move gas
from the basin, but firm commitments and dates are pending. The Company
estimates that at year-end 2001 about 800,000 Mcf per day of CBM gas was
flowing. We caution that Prima does not own firm transportation for its own
account, and may have difficulty moving gas from the basin if pipelines fill to
capacity. The Company does, however, have an option with a third party that owns
and controls firm header and pipeline capacity from the basin that would allow
the Company, at certain junctures, to enter into a firm sales arrangement for
gas production in its Kingsbury project area, which is described below.

2001 ACTIVITY. During 2001, Prima drilled 118 gross (116.5 net) CBM wells in
this play. From 1999, when Prima commenced its CBM operations, through the end
of 2001, the Company drilled a total of 286 gross (283.8 net) wells in the play.
All but seven of the CBM wells drilled by the Company to-date have been located
within six of the Company's 28 project areas. The concentration of Prima's
development activities to-date within these project areas, and on the specific
coals targeted so far, reflect a number of considerations other than estimated
recoverable reserves and projected production rates. The Company's CBM
activities have been limited to fee lands, state lands, and certain coals
underlying federal lands for which drilling permits have been attainable. These
activities have largely been focused on relatively shallow coals, near
development activities of other operators. The higher potential coals identified
on the Company's lands have not yet been developed. These deeper, thicker coal
sequences are also either undeveloped or are in the early stages of development
by other operators, and are expected to initially take longer to de-water than
coals that have been under development and production in the region for a period
of time. The following is a brief description of activities in the six project
areas where most of Prima's CBM operations have been conducted to-date.

Stones Throw Area. The 9,900-acre Stones Throw project area, located
approximately 30 miles north of Gillette, Wyoming, was the first chosen by the
Company for CBM development. Its selection was due to Prima's control of a
significant portion of fee acreage within the project area and its proximity to
both an existing CBM field and related infrastructure. By the end of 2001, Prima
had drilled 153 wells at Stones Throw, including 42 that were drilled during the
past year. Wells drilled in this area have targeted the Canyon, Cook, or Wall
coal, at depths between 500 and 850 feet. Prima installed a gathering system
with leased compression facilities at Stones Throw, establishing capacity to
produce up to 10 million cubic feet of gas per day. Gross production from the
field reached approximately 8 MMcf of gas per day and averaged 6.3 MMcf per day
net to Prima in the fourth quarter of 2001, from 106 wells that were hooked up
and producing during the period. This field, the associated gathering system,
and certain surrounding acreage were sold in March 2002, following the Company's
decision to focus future CBM exploitation and development activities on other
lands that it holds in the play where the presence of thicker, deeper coals is
expected to yield superior investment returns -- see "Subsequent Event" in the
Notes to Consolidated Financial Statements.

Kingsbury Area. Prima drilled seven additional wells during 2001 in the
10,300-acre Kingsbury project area, which is located 15 miles west of Gillette.
The Company also completed and hooked up 26 of the 32 wells that have been
drilled to date in the Kingsbury area. We elected to have the low-pressure
gathering system installed by a third party that already had such facilities in
place in the area, and entered into a market-price based sales agreement. All
but six wells drilled by Prima to-date at Kingsbury have been completed in the
Lower Anderson coal, but several developable coals are present within this
project area. Aggregate gas production from the 26 wells that have been
producing gas or de-watering has gradually increased as de-watering has
progressed, and gross production at Kingsbury was recently averaging
approximately 1,100 Mcf of gas per day.

North Shell Draw Area. The 7,400-acre North Shell Draw project area is located
approximately 25 miles northwest of Gillette, Wyoming. Prima had drilled 36
wells within this project area through the end of 2001, including 22 drilled
during the past year. All of the wells drilled to date have targeted the Lower
Anderson coal, but several other developable coals are also present. Encouraging
results were obtained from production testing seven of the North Shell Draw
wells during the third quarter of 2001. This data will be used to design
facilities, structure gas gathering arrangements and plan 2002 drilling
activities for the area. Prima plans to install, or arrange for a third party to
install, a gathering system and compression at North Shell Draw by late 2002.

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Porcupine-Tuit Area. The 5,600-acre Porcupine-Tuit project area is located
approximately 50 miles south of Gillette, Wyoming. The Company has drilled 23
Wyodak-coal wells, including 15 in 2001, in this project area, which exhibits
favorable coal quality and thickness at relatively shallow depths. Other
operators in the area have already reported encouraging performance from
completions in the same coal and Prima conducted a short duration, two-well
production test with positive results. The Company has arranged for third-party
installation of gathering and compression facilities in 2002, and production is
expected to be initiated in the third quarter of the year. Drilling in the area
will also likely resume in the second half of the year, subject to obtaining
drilling permits on federal lands. Prima's acreage position in the
Porcupine-Tuit area was enhanced by an acquisition closed in the fourth quarter
of 2001 that added approximately 1,800 gross, 800 net, undeveloped acres.

Hensley Area. The 4,800-acre Hensley project area is located approximately 20
miles northwest of Gillette, Wyoming. Prima has drilled and completed 18 wells
in the project area, including 15 in 2001. Eight of these were drilled to the
Lower Canyon coal, seven targeted the Wall coal, and three were drilled to the
Upper Anderson coal. The Company has delayed entering into a gathering agreement
with a third party pending resolution of development plans for this project
area. We anticipate that after the Company negotiates such a gathering
agreement, 16 of the existing wells at Hensley could be placed on-line within a
few months.

Cedar Draw. During 2001 the Company drilled 17 wells on the 3,800-acre Echeta
federal unit within the 6,000-acre Cedar Draw project area, located
approximately 20 miles northwest of Gillette, Wyoming. Three separate coals were
targeted by these wells, which have provided test data that will be used to
formulate plans for further development. Cedar Draw is in close proximity to the
North Shell Draw area, and the Company anticipates coordinating development of
the two projects, including infrastructure installation and the scheduling of
additional drilling during 2002.

FUTURE ACTIVITY. Prima recently reduced the pace of its development activities
in the CBM play due to low gas prices, regulatory constraints, and delays in
infrastructure development required to tie-in new wells. The Company plans to
actively develop its CBM acreage as infrastructure development proceeds and
regulatory constraints are addressed. The Company currently anticipates drilling
between 60 and 110 CBM wells in 2002. Among the project areas with significant
planned new drilling activity during the year are Porcupine-Tuit and Wild
Turkey, where the primary target coal is the Big George. Our capital investments
in the CBM play during 2002 are expected to total between $10 and $15 million.
However, these plans are subject to change based on economic conditions,
availability of required permits, activities of other operators and gas
transporters, and other factors.

POWDER RIVER BASIN - CONVENTIONAL

LOCATION, OPERATIONS, ACREAGE. Prima has been active in lease acquisition,
drilling and production from conventional reservoirs in the Powder River Basin
since 1994. The Company owns the deep rights (below the coals) in approximately
162,000 gross, 149,000 net, acres in the basin, and we currently operate 13 of
the 17 conventional reservoir Powder River Basin wells in which we have an
interest. The Company has conducted a modest amount of exploration in the area,
in addition to acquiring proved properties, and discovered the Cedar Draw Field,
approximately 21 miles northwest of Gillette, Wyoming, in 1997 as a field
extension to Amos Draw. At the end of 2001, Prima operated six wells and had a
non-operated working interest in two other wells in the Cedar Draw Field.

FORMATIONS AND PRODUCTION. At December 31, 2001, Prima's production from
conventional reservoirs in the Powder River Basin was derived primarily from the
Muddy formation, located at a depth of approximately 9,600 feet, and the Turner
formation, found at a depth of about 10,000 feet. Both of these formations are
localized in nature, have moderate porosity and permeability, and typically
require fracture stimulation to establish economic production. The production
stream includes natural gas, natural gas liquids, and sweet crude oil. Natural
gas from these two formations averages approximately 1,280 Btu per Mcf and is
sold at a slight premium to Rocky Mountain indices, or spot prices. The crude
oil sells for a premium to postings for Wyoming crude oil in this area. During
2001, production from Prima's conventional Powder River Basin properties
accounted for approximately 8% of the Company's Mcfe produced and 8% of the
Company's total oil and gas revenues excluding hedging gains, with natural gas
averaging 2,142 Mcf per day and crude oil averaging 40 barrels per day net to
our interests.

9

RESERVES AND DEVELOPMENT COSTS. The Powder River Basin conventional play
represented approximately 4% of Prima's proved oil and gas reserves at the end
of 2001, on an Mcfe basis. Muddy formation wells in this area typically cost
from $750,000 to $850,000 to drill and complete, and average 1.2 to 1.5 Bcfe per
well. At the end of 2001, the Company carried only proved developed reserves in
its reserve report for conventional reservoirs in this area, but three
additional development drilling locations have been identified on Prima's lands
subject to higher gas prices. The Company also has identified several
conventional exploratory prospects on its acreage in the Powder River Basin.

2001 AND FUTURE ACTIVITY. No conventional development wells were drilled in the
Powder River Basin in 2001. Although no development drilling activity targeting
conventional reservoirs in the Powder River Basin is currently planned for 2002,
the Company intends to continue its evaluation of prospects and leads in the
conventional play, as further discussed under "Other Exploratory Prospects and
Acreage" below.

WIND RIVER BASIN

LOCATION, OPERATIONS AND ACREAGE. The Wind River Basin is located in central
Wyoming, and Prima's production in the basin is located in the Cave Gulch area,
comprising approximately three square miles. Prima has been active in the area
since 1987, primarily as a non-operating working interest owner, but we also
operate one producing well and have overriding royalty interests in ten wells.
Prima owns working interests ranging from 4.5% to 24% in 29 gross (2.08 net
wells) in the area. Our Wind River Basin acreage position is 1,100 gross, 150
net, developed acres, with 42,000 gross, 25,000 net, undeveloped acres at
year-end 2001.

FORMATIONS AND PRODUCTION. The primary producing formations in the Cave Gulch
area are the Fort Union at approximately 4,750 feet, the Lance from 4,900 to
8,800 feet, and the Frontier/Lakota/Muddy sands from 16,000 to 19,000 feet. The
Frontier and Lakota/Muddy formations are lenticular in nature, with the Fort
Union and Lance being localized reservoirs. The Lance formation has particularly
thick intervals of producing reservoirs which, when completed and fractured
together, have resulted in production of up to 18,000 Mcf per day from a single
well. Lakota/Muddy wells in the area have produced up to 45,000 Mcf per day from
a single well. The Fort Union, which appears sporadically at shallow depths, can
be evaluated on the way down to the Lance or Lakota/Muddy, and has been
completed and produced in approximately 18% of the locations where deeper wells
have been drilled. Production from this area includes natural gas, natural gas
liquids and sweet crude oil. The natural gas averages approximately 1,150 Btu
per Mcf and is sold at a slight premium to Rocky Mountain indices, or spot
prices. The crude oil sells for a premium to postings for Wyoming crude oil in
this area. During 2001, production from Prima's Wind River properties accounted
for approximately 8% of total Mcfe produced and 9% of the Company's total oil
and gas revenues excluding hedging gains, with natural gas averaging 2,636 Mcf
per day and crude oil averaging 7 barrels per day net to our interests.

RESERVES AND DEVELOPMENT COSTS. The Wind River Basin represented approximately
3% of Prima's proved oil and gas reserves at the end of 2001, on an Mcfe basis.
Lance formation wells cost approximately $1.6 million to drill and complete, and
target approximately 2 Bcfe per well. The deep Frontier/Lakota/Muddy wells cost
approximately $9.5 million per well, and target 15 to 18 Bcfe per well. The
year-end 2001 reserve report for this area included one proved developed
non-producing opportunity.

2001 AND FUTURE ACTIVITY. Activity in the Cave Gulch area has decelerated as the
field reaches its limits of known areal extent and producing horizons. No new
wells were drilled in 2001, but two successful recompletion operations were
conducted. Future activities, which generally would be initiated by a
third-party operator, are expected to be limited. Prima anticipates modest
capital expenditures in this area for new drilling or recompletions during 2002.

OTHER EXPLORATORY PROSPECTS AND ACREAGE

Prima holds the following undeveloped acreage positions, except where
noted, where recent developments have occurred or the Company either plans
activities or is aware of activities planned by others that could benefit the
Company. There is no assurance that any of the anticipated activities will occur
or, if undertaken, that they will result in favorable outcomes.

10

WYOMING

Prima controls 425,000 gross, 264,000 net, undeveloped acres in the
Powder River, Wind River, Big Horn and Green River basins in Wyoming.

Merna Prospect. Prima owns approximately 75,800 gross, 28,700 net, undeveloped
acres in the Merna Prospect, located in the northern Green River Basin, Sublette
County, Wyoming. The acreage is primarily prospective for natural gas
development from the over-pressured Upper Cretaceous Lance Formation at a depth
of approximately 13,000 feet. This prospect is located approximately 20 miles
northwest of the Pinedale Anticline which is expected to produce over 2.0 Tcf of
natural gas from the Upper Cretaceous Lance and Mesaverde formations. The
Company entered into an agreement with a third party to support that party's
effort to re-enter and complete an existing well and to drill a second well on
offsetting acreage. In exchange for the information obtained from these
operations, Prima agreed to allow the third party to participate in the drilling
of an additional test well on, and to earn, a portion of Prima's acreage.
Initial results of the project have been encouraging but not conclusive. The
Company anticipates that the third party will drill at least one well and
conduct additional production testing in 2002. Prima will evaluate any proposals
to participate in such operations based on available technical data.

South Jonah Prospect. Prima owns approximately 5,900 gross, 3,700 net,
undeveloped acres in the South Jonah Prospect, which is located in the northern
Green River Basin, Sublette County, Wyoming. This prospect is located
approximately ten miles from the Jonah Field, which is expected to produce over
2.5 Tcf of natural gas from the over-pressured Upper Cretaceous Lance Formation.
There has been significant activity by other operators in the South Jonah area
during the past two years. Five new wells have been drilled in the area to test
the Lance and Mesaverde formations, and one well was re-entered to test the
Lance Formation. Four of the wells were completed and are waiting on pipeline
connections and two of the wells are currently being tested. Two of the wells
directly offset Prima's acreage. The Company anticipates that additional
drilling and production testing in the area will be conducted by other operators
during 2002.

Hell's Half Acre Prospect. Prima owns approximately 17,200 gross, 5,500 net,
undeveloped acres in the Hell's Half Acre Prospect, which is located in the
eastern Wind River Basin, Natrona County, Wyoming. This prospect is a
seismically-defined structure located approximately ten miles southeast of Cave
Gulch Field. Cave Gulch Field is expected to produce between 1.0 and 1.5 Tcf of
natural gas from the Tertiary Fort Union and Cretaceous Lance, Mesaverde,
Frontier, and Muddy formations. During 2001, Prima participated with a 7%
working interest in the Miller Ranch No. 11-9 well, which was drilled to a total
depth of 12,592 feet to test the Upper Cretaceous Mesaverde Formation. Although
the well encountered gas in several horizons it was determined to be
non-commercial and was plugged and abandoned. This well did not evaluate the
deeper potential of the prospect, which is the Company's primary objective in
the area. Additional drilling is expected to evaluate the deeper potential,
however, based on indications from third parties with interests in the prospect,
no activity is anticipated until late 2002 or 2003.

Klondike Prospect. Prima owns approximately 102,000 gross, 26,000 net
undeveloped acres in the southern Big Horn Basin, Hot Springs and Washakie
counties, Wyoming. This exploration play is prospective for both oil and natural
gas. A third-party operator has indicated an interest in drilling several wells
on the acreage this year, but no firm plans have yet been formulated.

Powder River Basin Prospects. Prima owns deep rights on approximately 162,000
gross, 149,000 net, undeveloped acres in the Powder River Basin, Campbell and
Converse counties, Wyoming. Much of this acreage was acquired for its CBM
potential, but a significant portion was also acquired for deeper conventional
prospects. In 1997, Prima discovered the Cedar Draw Field, which is an extension
to Amos Draw Field.

Prima participated with a 15% interest in a test well on the 7,600 acre Jim Hill
Draw Federal Unit in Converse County, Wyoming during 2001. The Jim Hill Draw
Unit is located approximately one mile west of the Sand Dunes Field, which has
produced more than 24 million barrels of oil and 56 Bcf of natural gas. The
primary objective of the test well was the Cretaceous Muddy Sandstone, at
approximately 12,100 feet. The well was unsuccessful and no further activity is
currently planned.

11

Prima owns approximately 26,000 gross and net undeveloped acres in the Brooks
Draw area located in Natrona County, Wyoming. The position is prospective for
natural gas and oil from the highly fractured Cretaceous Niobrara, Turner and
Newcastle Formations. During 2000 and 2001, third-party operators drilled
several horizontal wells in this area designed to intersect fractures from a
single well bore. While initial reports of results were encouraging, activity
does not appear to have been sustained and ultimate economics of the play are
not clearly defined at this stage of development. Prima plans to monitor
activity in this area, and may participate in well(s) where our acreage is
included within the spacing units of wells proposed by other operators. No such
activity is anticipated for 2002.

The Company intends to continue to identify and pursue Powder River Basin
conventional prospects in the future.

UTAH

Prima has continued to expand its acreage position on the Wasatch
Plateau located in east-central Utah. At the end of 2001, the Company held
105,000 gross, 74,000 net, undeveloped acres in Utah. Net acreage holdings were
increased to approximately 100,000 in early 2002 through the exercise of an
option covering interests under a portion of this acreage. The four prospects
defined in Utah have conventional oil and gas potential as well as CBM
potential.

The Company has a 37.5% non-operated working interest in a well drilled
in 2000 in the Helper Field, located immediately north of Price, Utah. The well
was placed on production in late-January 2001 and at last report was producing
in excess of 400 Mcf of natural gas per day. This well is completed in
Cretaceous Ferron coals between 1,850 to 1,950 feet.

East Clear Creek Prospect. Prima owns approximately 9,000 gross and net acres in
the East Clear Creek Prospect, which is located approximately 15 miles west of
Price, Utah. This prospect is one mile east of Clear Creek Field, which has
produced 136 Bcf of natural gas from 16 wells drilled to the Cretaceous Ferron
sandstone. Two miles east of Prima's prospect is Gordon Creek Field where a
third party completed three Ferron sandstone wells during 2001. These new wells
are currently waiting for pipeline connections. The Company's initial
exploration at East Clear Creek will target the Ferron sandstone at a depth of
approximately 6,000 feet on a seismically defined structure. Prima is currently
working with the U.S. Forest Service to complete an Environmental Impact
Statement (EIS) for this area and anticipates drilling its first well in the
summer of 2003.

Coyote Flats Prospect. Prima controls approximately 76,000 gross, 71,000 net,
undeveloped acres within its Coyote Flats Prospect area. The prospect is located
15 to 25 miles northwest of Price, Utah. Significant hydrocarbon production
exists in the area. The Company's leasehold position is approximately 15 miles
northwest of the Drunkard's Wash Field, which produces from the Cretaceous
Ferron coals and sandstones and is expected to ultimately produce in excess of
1.2 Tcf of natural gas. Prima's objective at Coyote Flats is to test the
hydrocarbon potential of sandstone and coal bed reservoirs in the Cretaceous
Blackhawk formation, the Emery and Ferron members of the Mancos, and the Dakota
formation. The primary CBM target on Prima's lease block is the Emery formation.
The Emery coals are found across the majority of the lease position at depths
ranging from 2,000 to 5,000 feet, with an average coal thickness of 60 to 70
feet. The lease block is also on trend with CBM production from the Cretaceous
Blackhawk coals at the Castlegate Field, approximately 10 to 15 miles to the
east, and Blackhawk coals are present under the Coyote Flats lease block at
depths ranging from the surface to 3,000 feet. Gas shows have been reported from
both the Emery and Blackhawk intervals. In addition to the CBM potential of the
block, significant gas shows have been reported from the Cretaceous Ferron
sandstones, Mancos shales, and Dakota sandstones. The Company anticipates
drilling its first well at Coyote Flats during the second half of 2002.

Flat Canyon Prospect. Prima owns approximately 6,200 gross and net acres in the
Flat Canyon Prospect located in Emery County, Utah. Prima's acreage immediately
offsets the Flat Canyon Field, which was discovered in 1952. The Flat Canyon
Field has produced 9.6 Bcf of natural gas and 14,000 barrels of oil from six
wells completed in the Cretaceous Ferron sandstones. Prima intends to test the
Cretaceous Ferron and Dakota formations at depths between 6,500 and 7,500 feet
on the prospect. A secondary objective at Flat Canyon is the Cretaceous
Blackhawk coals, which are 10 to 30 feet thick at depths of 1,100 to 2,500 feet.
Prima is currently working with the U.S. Forest Service and the

12

Bureau of Land Management to permit two wells on this prospect. The Company
anticipates drilling its first well at Flat Canyon during the summer of 2003.

Christmas Meadows Prospect. Prima owns or controls a 50% farmout interest in
the Table Top Federal Unit that consists of approximately 23,000 acres. The
Federal Unit is located in Summit County, Utah approximately 30 miles south of
Evanston, Wyoming. The prospect objective is a seismically defined structural
feature. The project has been delayed for several years while the U.S. Forest
Service has been conducting an Environmental Impact Statement and considering a
revision of the forest plan for the area. Prima and its partners intend to cause
a well to be drilled on the prospect shortly after the Forest Service completes
this work, but no drilling activity is expected to take place during 2002.

CALIFORNIA

East Lost Hills Prospect. During the second quarter of 1998, the Company
participated for a 6.25% interest in a deep exploratory well located in the San
Joaquin Basin of central California. A dispute arose as to Prima's ownership in
the prospect during the drilling of the initial test well, following a blowout
and Prima's election not to participate in sidetrack operations. After
evaluating its legal position and the development progress of the prospect since
that time, including estimated costs incurred to date, Prima elected not to
pursue legal action to enforce its ownership claim. The Company no longer
asserts an interest in the East Lost Hills Prospect.

RESERVES

The Company's net proved reserves at the end of 2001 are comprised of
approximately 85% natural gas and 15% crude oil. Net proved reserves as of
December 31, 2001 were estimated by the Company's engineers and audited by
Netherland, Sewell and Associates, Inc., independent petroleum engineers. Prior
year reserve estimates were prepared or audited in part by Netherland, Sewell
and Associates, Inc and in part by Ryder Scott Company., independent petroleum
engineers.

The table below sets forth the estimated quantities of net proved
reserves attributed to the Company's property interests at the end of each of
the last three years, and the present value of estimated future net cash flows
attributed to such reserves using prices in effect as of the respective year-end
dates, held constant. The average net realizable prices used to estimate reserve
quantities at the end of 2001, 2000, and 1999, respectively, were as follows:
$1.94, $7.51 and $1.90 per Mcf for natural gas; and $19.71, $26.48 and $24.68
per barrel of oil. Projected future net cash flows from production of proved
reserves were discounted by ten percent per annum to derive present values and
the "Standardized Measure" of discounted future net cash flows after income
taxes, as specified by the Securities and Exchange Commission. The 10% discount
factor is not necessarily a market rate, and present value, no matter what
discount factor used, is materially affected by assumptions as to future prices
and costs and the timing of future production, which may prove to be inaccurate.
For further information concerning estimated proved reserves and the discounted
future net cash flows related to these reserves, see unaudited "Supplementary
Oil And Gas Information" in the Notes to Consolidated Financial Statements.

Proved reserve quantities at the end of 2001 and the related present
value of future net cash flows before income taxes were also estimated using an
alternate price case based upon five-year forward prices quoted on December 31,
2001, as adjusted for transportation and quality differentials. Using prices
averaging $2.33 per Mcf of natural gas and $21.53 per barrel of oil, estimated
proved reserves totaled approximately 135 Bcf of natural gas and 3.5 million
barrels of oil, with associated pre-tax PV10 of $122 million.

13

There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing and
amounts of development expenditures. Oil and gas reserve engineering should be
recognized as a subjective process of estimating underground accumulations of
oil and natural gas that cannot be measured in an exact way. The accuracy of any
reserve estimate is a function of the quality of available engineering and
geological data and interpretation, and judgment. Results of drilling, testing
and production after estimates are prepared may justify revisions. Accordingly,
reserve estimates are often materially different from the quantities of oil and
natural gas that are ultimately produced. The Company has had no major discovery
or other event that is believed to have caused a significant upward or downward
change in estimated proved reserves subsequent to December 31, 2001. Oil and
natural gas prices have historically been volatile and are expected to continue
to be so in the future. Changes in product prices affect the economic limits,
and therefor recoverable reserve quantities of oil and gas wells, as well as the
present value of estimated future net cash flows and the standardized measure of
discounted future net cash flows.

Since January 1, 2001, the Company has filed Department of Energy Form
EIA-23, "Annual Survey of Oil and Gas Reserves," as required by operators of
domestic oil and gas properties. There are differences between the reserves as
reported on Form EIA-23 and reserves as reported herein. Form EIA-23 requires
that operators report on total proved developed reserves for operated wells only
and that the reserves be reported on a gross operated basis rather than on a net
interest basis.

PRODUCTION

The Company's net natural gas production averaged 25,416 Mcf per day
for the year ended December 31, 2001 compared to 23,724 Mcf per day for the year
ended December 31, 2000 and 19,625 Mcf per day during the year ended December
31, 1999. Net oil production averaged 1,181 barrels per day for the year ended
December 31, 2001 compared to 1,202 barrels per day during the year ended
December 31, 2000 and 882 barrels per day during the year ended December 31,
1999. The following table summarizes information with respect to the Company's
producing oil and gas properties for each of these periods.

(1) Oil production has been converted to a common unit of production (Mcf
of natural gas) on the basis of relative energy content (one barrel of
oil to six Mcf of natural gas).

PRODUCTIVE WELLS

The following table summarizes total gross and net productive wells
for the Company at December 31, 2001.

14

Additionally, Prima owns royalty interests in 52 gross wells that are
not included in the above table.

- ---------------------------

(1) A gross well is a well in which a working interest is held. The number
of gross wells is the total number of wells in which a working interest
is owned.

(2) A net well is deemed to exist when the sum of fractional ownership
interests in gross wells equals one. The number of net wells is the sum
of the fractional working interests owned in gross wells expressed as
whole numbers and fractions thereof.

(3) Includes 136 gross, 133.7 net, CBM wells in Wyoming that were shut-in
awaiting hook-up at December 31, 2001

(4) Wells are classified as oil wells or gas wells according to predominate
production stream. Multiple completions (26 wells) are counted as one
well.

DEVELOPED AND UNDEVELOPED ACREAGE

At December 31, 2001, the Company held leased acreage as set forth
below:

(1) Developed acres are acres spaced or assigned to productive wells.

(2) Undeveloped acreage are those lease acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil or natural gas, regardless of whether
such acreage contains proved reserves.

(3) A gross acre is an acre in which a working interest is owned. The
number of gross acres is the total number of acres in which a working
interest is owned.

(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres
is the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.

Many of the leases summarized in the table above as undeveloped
acreage will expire at the end of their respective primary terms unless
production has been obtained from the acreage subject to the lease prior to that
date, in which event the lease will remain in effect until the cessation of
production. Prima has generally been able to obtain extensions of the primary
terms of its federal leases for the period that it is unable to obtain drilling
permits due to a pending EIS. The following table sets forth the expiration
dates of the gross and net acres subject to leases summarized in the table of
undeveloped acreage.

15

DRILLING ACTIVITIES

Certain information with regard to the Company's drilling activities
for the years ended December 31, 2001, 2000 and 1999 is set forth below:

Since December 31, 2001 and through March 15, 2002 the Company has
participated in nine gross (7.5 net) refracs or recompletions in the Denver
Basin, all of which have been restored to production. On March 15, 2002, the
Company also owned interests in 104 gross (101.7 net) CBM productive wells in
the Powder River Basin that were awaiting hook-up to gas compression and
transportation facilities (excludes wells sold on March 5, 2002).

NATURAL GAS AND OIL MARKETING AND TRADING

The Company's marketing and trading activities consist of marketing
the Company's own production, marketing the production of others from wells
operated by the Company, purchase and resale of third party natural gas, and
basis trading the differential in price between the Rocky Mountain region and
other areas of the United States. Financial instruments are used from time to
time to hedge the price of a portion of the Company's production as well as
purchases for resale.

NATURAL GAS. The terms and conditions of our various natural gas sales contracts
vary as to price, quantity, term and other conditions, but in general follow
30-day spot or day-to-day prices as posted. The Company does occasionally sell
fixed price gas for terms in excess of 30 days as a hedge on its production when
warranted by its assessment of market conditions and to protect from downward
price movements, but had no direct customer sales for a fixed price at year-end
2001. Prima has one significant purchaser of its natural gas in the Denver
Basin, Duke Energy Field Services, LLC ("Duke"), which accounted for 31% of the
Company's total consolidated revenues in 2001. Duke is not affiliated with
Prima, and while loss of Duke as a customer could have a material adverse effect
on the Company, we believe an ample market exists to sell the natural gas to
alternate customers. The Company currently has three gathering agreements, one
in the Denver Basin, one in the Wind River Basin, and one in the Powder River
CBM play, to get its gas from the wellhead into high-pressure header systems or
interstate pipelines. Prima has not, however, contracted for downstream
transportation on a firm basis. As such, we have no liability to pay reservation
(demand) charges for header or pipeline capacity, but we also have no assurance
that our gas will flow every day. No significant curtailments of gas production
occurred in 2001. In its areas of activity, Prima has also engaged in purchasing
and re-selling third-party gas. These arrangements typically provide for the
purchase of natural gas at a known price or index, with a corresponding sale.
The Company does from time to time have open purchase or sale commitments
without corresponding contracts, which could result in a loss. Prima's Chief
Executive Officer reviews such positions before they are committed to, and we
monitor (mark-to-market) these positions regularly. The Company had no
purchase-for-resale trading obligations at year-end 2001. In 2001, total
revenues from the sale of Prima's natural gas production, including related
hedging effects, were $33,392,000, or 75% of oil and gas sales and 55% of
consolidated revenues.

OIL. The Company's oil production is sold under a number of contracts at prices
posted in the area of activity, plus a negotiated bonus determined by quality
and location. The contracts are generally month-to-month in duration. Our point
of sale for crude oil is at the well, where oil is picked up and trucked by the
purchaser to pipelines or refineries. During

16

2001, one purchaser, Valero Energy Corporation (via its acquisition of Ultramar
Diamond Shamrock) accounted for approximately 16% of Prima's total consolidated
revenues for the year. Prima is not affiliated with Valero, and believes that it
can sell its crude to other purchasers on comparable terms should we lose Valero
as a customer. In 2001, total revenues from the sale of Prima's crude oil,
including related hedging effects, were $11,156,000, or 25% of oil and gas sales
and 19% of consolidated revenues.

RISK MANAGEMENT. To mitigate its risk from changes in benchmark oil and gas
prices, the Company from time to time uses commodity futures and energy swaps.
Such transactions can also be used to protect the Company from an expanding
NYMEX to CIG basis differential, which can occur when natural gas supplies
exceed pipeline capacity out of the Rocky Mountain region or due to other
factors, such as regional weather differences. During 2001, Prima entered into
derivatives contracts covering approximately 45% of its natural gas production
and 19% of its crude oil production. A portion of these contracts did not meet
all of the conditions required for utilization of hedge accounting, but were
nevertheless viewed by management as providing considerable revenue protection
in the event of declining oil and gas prices or widening basis differentials.
Approximately 24% of the Company's natural gas production and 19% of its crude
oil production in 2001 were covered by derivatives contracts that qualified for
hedge accounting. See "Quantitative and Qualitative Disclosures about Market
Risk" below for additional disclosures, including the Company's open derivative
positions as of March 15, 2002.

OILFIELD SERVICES

Prima conducts its oilfield services business under the names of
Action Oilfield Services in Colorado and Action Energy Services in Wyoming.

ACTION OILFIELD SERVICES. Action Oilfield Services ("AOS") has been active in
the Denver Basin since 1986, operating out of a field office and yard near
LaSalle, Colorado. AOS owns various well servicing equipment including
completion rigs, a swab rig, tractor trailer rigs for water hauling, and
oilfield rental equipment, such as pumps, tanks and blowout preventers. During
2001, we experienced high utilization rates for our people and equipment due to
strong demand for services for well recompletions, re-works and drilling in the
area. We intend to continue to grow our well servicing activities in the Denver
Basin. AOS provides services for Prima as well as third-party operators in the
area. During 2001, 27% of AOS's revenues were from activities performed on wells
for Prima. The Company's share of fees paid to AOS on Company-owned properties
and the costs associated with providing these services are eliminated in the
consolidated financial statements. Third-party revenues recorded by AOS in 2001
totaled $5,683,000, or 9% of Prima's consolidated revenues.

ACTION ENERGY SERVICES. Prima formed Action Energy Services ("AES") in the first
quarter of 1999, to conduct well drilling and servicing activities in the Powder
River Basin. AES leases an office and yard in Gillette, Wyoming. In addition to
providing well services similar to those offered by AOS in the Denver Basin, AES
has six CBM drilling rigs. We intend to continue to conduct both drilling and
well servicing activities in the Powder River Basin, on behalf of both Prima and
unaffiliated third parties. During 2001, 48% of AES's revenues were applicable
to well interests owned by Prima, and these revenues have been accounted for in
the same manner as noted for AOS. AES's third-party revenues were $2,224,000 in
2001, representing 4% of the Company's consolidated revenues.

GAS GATHERING SERVICES

ARETE GATHERING COMPANY, LLC. Prima formed Arete Gathering Company, LLC
("Arete") in the third quarter of 2000 to provide gas compression and gathering
services for the CBM play in the Powder River Basin. Arete installed its first
gathering system in Prima's Stones Throw Area between mid-2000 and the first
quarter of 2001. These assets were included in the sale transaction consummated
in March 2002 -- see "Subsequent Event" in the Notes to Consolidated Financial
Statements. No other gathering systems have been installed by Arete to date. We
will evaluate future opportunities to build gathering and compression systems in
the Powder River Basin based on the size and estimated reserve potential of our
acreage blocks, proximity to header systems and pipelines, competitive options
provided by third parties, and other factors affecting the economics of each
project. In areas where Prima does not have a significant contiguous acreage
block, or where third party gathering systems have already been installed, we
will generally elect not to have Arete build a gathering system. Where Arete
does install gathering and compression infrastructure, we will seek to provide
such services to third parties to benefit from economies-of-scale and enhance
our overall economic returns.

17

OTHER PROPERTIES, EQUIPMENT AND REAL ESTATE

Prima leases its Denver office space at an average annual rate of
approximately $275,000. Such offices consist of 15,840 square feet and the lease
continues until November 2007. The Company owns office furniture and equipment
with a net book value at December 31, 2001 of $207,000.

Prima has leased office space with yard and shop facilities in
Gillette, Wyoming. The yard and shop area is used to store and maintain various
well-servicing equipment, drilling rigs and production equipment. Net book value
of our service equipment, office furniture and equipment and leasehold
improvements at this location was $2,421,000 on December 31, 2001.

The Company owns 160 acres of land in Weld County, Colorado near
LaSalle, Colorado. The shop, office building and yard facilities located on the
land are used for the Company's field and oilfield service operations. Net book
value of the land, buildings and office furniture and equipment at December 31,
2001 was $170,000.

Prima owns approximately ten acres of surface land with no mineral
rights on the western side of Greeley, Colorado. The land was acquired in March
2001 in exchange for minor undeveloped mineral rights. This ten-acre parcel is
part of a planned 760-acre commercial and office park development. Prima plans
to hold this land, which had a net book value of $944,000 at the end of 2001,
for future sale, exchange or development.

The Company also owns service company and related equipment, including
completion rigs, swab rigs, tractor trailer rigs used for water hauling,
oilfield rental equipment and various oilfield vehicles, with a net book value
of $1,991,000 at December 31, 2001.

Prima is a 6% limited partner in a real estate limited partnership
that currently owns approximately 22 acres of undeveloped land in Phoenix,
Arizona for investment and capital appreciation. The book value of this
partnership interest was $257,000 at December 31, 2001.

EMPLOYEES AND OFFICES

As of December 31, 2001, the Company had 144 full-time employees,
including 38 in its Denver office and 106 field employees. Of the field
employees, Action Oilfield Services employed 51 people, Action Energy Services
employed 31 people, and 24 were employed in Prima's lease and well management
operations. Prima field employees also handled work for Arete Gathering Company.
Prima also contracts the services of independent consultants involved in land,
geology, engineering, accounting, regulatory affairs, and other disciplines as
needed. The Company believes its relations with its employees are good. Prima's
principal executive offices are located at 1099 18th Street, Suite 400, Denver,
Colorado 80202.

ITEM 3. LEGAL PROCEEDINGS

The Company is a party to various legal proceedings arising in the
ordinary course of its business. As of the date of the filing of this report,
none of these is anticipated to have a material adverse impact on Prima's
financial position or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the fiscal year ended December 31, 2001.

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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

Prima is including the following cautionary statement to take
advantage of the "safe harbor" provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statement made by, or on behalf of,
the Company. The factors identified in this cautionary statement are important
factors (but not necessarily all of the important factors) that could cause
actual results to differ materially from those expressed in any forward-looking
statement made by, or on behalf of, the Company. Where any such forward-looking
statement includes a statement of the assumptions or bases underlying such
forward-looking statement, the Company cautions that, while it believes such
assumptions or bases to be reasonable and makes them in good faith, assumed
facts or bases almost always vary from actual results, and the differences
between assumed facts or bases and actual results can be material, depending
upon the circumstances. Where, in any forward-looking statement, the Company, or
its management, expresses an expectation or belief as to the future results,
such expectation or belief is expressed in good faith and believed to have a
reasonable basis, but there can be no assurance that the statement of
expectation or belief will result, or be achieved or accomplished. The Company
does not undertake to update, revise or correct any of the forward-looking
information. Taking into account the foregoing, the following are identified as
important risk factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by, or on behalf of, the
Company:

VOLATILITY OF OIL AND NATURAL GAS PRICES. Historically, oil and
natural gas prices have been volatile and are likely to continue to be volatile.
Prices are affected by, among other things, market supply and demand factors,
market uncertainty, and actions of the United States and foreign governments and
international cartels. These factors are beyond the control of the Company.
Excluding hedging effects, average natural gas and oil prices realized by the
Company at the end of 2001 were 74% and 26% lower, respectively, than at the end
of the prior year. To the extent that oil and gas prices decline, the Company's
revenues, cash flows, earnings and operations are adversely impacted. Low oil
and gas prices, in adversely affecting cash flow and access to capital, could
reduce our ability to replace production and grow. The Company is unable to
accurately predict future oil and natural gas prices.

UNCERTAINTY OF OIL AND NATURAL GAS RESERVE ESTIMATES. Estimates of the
Company's proved reserves and future net revenues are based on engineering
reports prepared by the Company's engineers and audited by independent
engineers. These estimates are based on several assumptions that the Securities
and Exchange Commission requires oil and natural gas companies to use, including
that oil and natural gas prices in effect as of the end of the year remain
constant. Such estimates are inherently imprecise indications of future net
revenues. Actual future production, revenues, taxes, production costs and
development costs may vary substantially from those assumed in the estimates.
Any significant variance could materially affect the estimates. In addition, the
Company's reserves might be subject to upward or downward adjustment based on
future production, results of future exploration and development, prevailing oil
and natural gas prices and other factors.

RISKS OF OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION.
The search for oil and natural gas often results in unprofitable efforts, not
only from dry holes, but also from wells which, though productive, do not
produce oil or natural gas in sufficient quantities to return a profit on the
costs incurred. No assurance can be given that the Company's exploration,
development and acquisition activities in the future will result in the addition
of any oil or natural gas reserves that will be commercially productive. In
addition, the cost of drilling, completing and operating wells is often
uncertain, and drilling may be delayed or canceled as a result of many factors,
including unacceptably low oil and natural gas prices, availability of drilling
rigs, oil and natural gas property title problems, government regulation,
inclement weather conditions and financial instability of well operators and
working interest owners. Furthermore, the availability of a ready market for the
Company's oil and natural gas depends on numerous factors beyond its control,
including demand for and supply of oil and natural gas, general economic
conditions, proximity of natural gas reserves to pipelines, availability and
terms for pipeline space, weather conditions and government regulation.

NEED TO REPLACE RESERVES. As is customary in the oil and gas
exploration and production industry, the Company's future success depends upon
its ability to continue to find, develop or acquire additional oil and gas
reserves that are economically recoverable. Unless the Company replaces the
reserves that it produces through successful development, exploration or
acquisition, the Company's proved reserves will decline. Further, approximately
47% of the Company's proved reserves at December 31, 2001 were located in the
Wattenberg Area of the Denver Basin, where wells are characterized by relatively
rapid initial decline rates. Additionally, approximately 36% of the Company's
total proved reserves at December 31, 2001, were undeveloped. Recovery of such
reserves will require significant capital

19

expenditures and successful drilling and/or recompletion operations. There can
be no assurance that the Company will continue to be successful in its effort to
develop or replace its proved reserves.

ACQUISITIONS RISKS. We continually evaluate opportunities for property
or corporate acquisitions that could enhance our business. The successful
acquisition of producing properties requires an assessment of several factors,
including recoverable reserves, future oil and gas prices, future capital and
operating costs, and potential environmental and other liabilities. The accuracy
of these assessments is inherently uncertain. In connection with these
assessments, we would intend to perform a review of the subject properties
consistent with industry practices. However, such review will not reveal all
existing or potential problems nor will it permit us to become sufficiently
familiar with the properties to fully assess their deficiencies and
capabilities. Inspections may not always be performed on every property and
environmental problems are not necessarily observable even when an inspection is
undertaken. Even when problems are identified, the seller may be unwilling or
unable to provide effective contractual protection against all or part of the
problems. Additionally, significant acquisitions can change the nature of our
operations and business depending upon the character of the acquired properties,
which may have substantially different operating and geological characteristics
or be in different geographic locations than our existing properties. While it
is our current intention to continue to concentrate on acquiring properties with
development, exploitation and exploration potential located in our core
operating areas, we cannot assure you that in the future we will not decide to
pursue acquisitions or properties located in other geographic regions. To the
extent that such acquired properties are substantially different than our
existing properties, our ability to efficiently realize the economic benefits of
such transactions may be limited. We may not be able to successfully integrate
future property or corporate acquisitions. We seek to make selective niche
acquisitions of oil and gas properties, and we will pursue corporate
acquisitions that we believe will be accretive. However, integrating acquired
properties and businesses involves a number of special risks. These risks
include the possibility that management may be distracted from normal business
concerns by the need to integrate operations and systems and in retaining and
assimilating additional employees. Any of these or other similar risks could
lead to potential adverse short-term or long-term effects on our operating
results.

DEPENDENCE ON TRANSPORTATION FACILITIES OWNED BY OTHERS. Our business
depends on transportation facilities owned by others. The marketability of our
oil and gas production depends in part on the availability, proximity and
capacity of pipeline systems owned by third parties. The unavailability of or
lack of available capacity on these systems and facilities could result in the
shut-in of producing wells or the delay or discontinuance of development plans
for properties. Although we have some contractual control over the
transportation of our product, material changes in these business relationships
could materially affect our operations. Federal and state regulation of oil and
gas production and transportation, tax and energy policies, changes in supply
and demand, pipeline pressures, damage to or destruction of pipelines and
general economic conditions could adversely affect our ability to produce,
gather and transport oil and natural gas.

DERIVATIVES ACTIVITIES. Part of the Company's business strategy is to
periodically use both commodity futures contracts and price and basis swaps to
mitigate the impact of the volatility of oil and natural gas prices on a portion
of our production and gas marketing activities. In certain circumstances,
significant reductions in production, due to unforeseen events, could require
the Company to make payments under such agreements even though payments are not
offset by production. To reduce this risk, the Company generally strives to
enter into derivatives for only a portion of its projected production.
Derivatives may also prevent the Company from receiving the full advantage of
increases in oil or natural gas prices. Further, such transactions may expose us
to additional risk of financial loss in certain circumstances, including
instances in which counterparties to our futures contracts fail to perform under
the contracts or ineffectiveness of our derivatives result in losses not offset
by increased sales revenue. The terms of our hedging agreements may also require
that we furnish cash collateral, letters of credit or other forms of performance
assurance in the event that mark-to-market calculations result in settlement
obligations by us to the counterparties, which could encumber our liquidity and
capital resources. We adopted Statement of Financial Accounting Standards (SFAS)
No. 133 on January 1, 2001, which requires us to record each hedging transaction
as an asset or liability measured at its fair value. Each quarter we must record
changes in the value of our hedges, which could result in significant
fluctuations in net income and stockholders' equity from period to period.

CAPITAL REQUIREMENTS. We anticipate continuing to make substantial
expenditures to find, develop, acquire and produce oil and gas reserves. We
expect to have sufficient cash provided by operating activities and from
available net working capital to fund planned capital expenditures in 2002.
However, we have not established a line of credit to provide additional capital
if required to respond to new opportunities. While we believe that we could
arrange for borrowings or issuance of securities to fund such opportunities,
should lower oil and gas prices or operating difficulties

20

result in our cash flow from operations being less than expected or if capital
markets were to deteriorate, we may be unable to obtain additional funds to
expand our business.

DEMAND FOR OILFIELD SERVICES. Our oilfield services operations are
dependent on the level of demand in our operating markets. Both short-term and
long-term trends in oil and natural gas prices affect demand. Because oil and
natural gas prices are volatile, the level of demand for our services can also
be volatile. Although Prima utilizes its service companies in its oil and gas
operations, the substantial majority of the demand for their services is
dependent on third parties. In addition to oil and gas prices, factors which can
influence activity levels for our oilfield service operations include
competition, our experience and reputation, the availability of labor, and the
weather.

COMPETITION. The Company competes with numerous other companies and
individuals, including many that have significantly greater resources, in
virtually all facets of its business. Such competitors may be able to pay more
for desirable leases and to evaluate, bid for and purchase a greater number of
properties than the financial or personnel resources of the Company permit. The
ability of the Company to increase reserves in the future will be dependent on
its ability to select and acquire suitable producing properties and prospects
for future exploration and development. The availability of a market for oil and
natural gas production depends upon numerous factors beyond the control of
producers, including but not limited to the availability of other domestic or
imported production, the locations and capacity of pipelines, and the effect of
federal and state regulation on such production. Domestic oil and natural gas
must compete with imported oil and natural gas, coal, nuclear energy,
hydroelectric power and other forms of energy.

OPERATING HAZARDS AND UNINSURED RISKS. The oil and gas business
involves a variety of operating risks, including the risk of fire, explosions
and blow-outs, as well as risks associated with production, marketing and
general economic conditions. The Company maintains insurance against some, but
not all, of these risks, any of which could result in substantial losses to the
Company. There can be no assurance that any insurance would be adequate to cover
any losses or exposure to liability or whether insurance will continue to be
available at premium levels that justify its purchase or whether it will be
available at all.

GOVERNMENT REGULATION. All aspects of the oil and gas industry are
extensively regulated by federal, state and local governments in all areas in
which the Company has operations. Regulations govern such things as drilling
permits, environmental protection and pollution control, spacing of wells, the
unitization and pooling of properties, reports concerning operations, royalty
rates and various other matters including taxation. As an example, the Company's
exploration and development plans for its Powder River Basin CBM properties are
dependent upon the timing, content and implementation of a pending record of
decision by the Bureau of Land Management concerning an environmental impact
statement covering CBM development in the area. Oil and gas industry legislation
and administrative regulations are periodically changed for a variety of
political, economic and other reasons. These regulations may substantially
increase the cost of doing business and sometimes prevent or delay the
commencement or continuance of any given exploration or development project and
may adversely affect the economics of capital projects. At the present time, it
is impossible to predict what effects current and future proposals or changes in
existing laws or regulations will have on operations, estimates of oil and
natural gas reserves, or future revenues. The costs of complying, monitoring
compliance and dealing with the agencies that administer these regulations can
be significant.

ENVIRONMENTAL REGULATION. We must comply with complex environmental
regulations. Our operations are subject to complex and constantly changing
environmental laws and regulations adopted by federal, state and local
governmental authorities where we are engaged in exploration or production
operations. New laws or regulations, or changes to current requirements, could
have a material adverse effect on our business. We will continue to be subject
to uncertainty associated with new regulatory interpretations and inconsistent
interpretations between state and federal agencies. We could face significant
liabilities to the government and third parties for discharges of oil, natural
gas or other pollutants into the air, soil or water, and we could have to spend
substantial amounts on investigations, litigation and remediation. We cannot be
sure that existing environmental laws or regulations, as currently interpreted
or enforced, or as they may be interpreted, enforced or altered in the future,
will not materially adversely affect our results of operations and financial
condition. As a result, we may face material indemnity claims with respect to
properties we own or have owned.

KEY PERSONNEL. We depend on the continued services of our executive
officers. Loss of the services of any of these people could have a material
adverse effect on our operations. We currently do not have employment agreements
with any of our executive officers, including Richard H. Lewis, who serves as
the Company's Chief Executive Officer, President and Chairman of the Board of
Directors.

21

PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Prima's common stock trades on the Nasdaq National Market under the
symbol "PENG." The following table sets forth the Nasdaq high and low sales
prices for Prima's common stock for each quarterly period during the Company's
years ended December 31, 2001 and 2000. These prices have been restated to
reflect the effect of the three for two split of Prima's common stock
distributed on February 24, 2000 and the three for two split of Prima's common
stock distributed on December 11, 2000.

Year Ended December 31, 2000
----------------------------

Quarter Ended March 31, 2000 .......................... $18.50 $10.50
Quarter Ended June 30, 2000 ........................... 36.92 15.17
Quarter Ended September 30, 2000 ...................... 37.83 20.71
Quarter Ended December 31, 2000 ....................... 39.92 23.08

The above quotations are from sources believed to be reliable. They do
not include any retail mark-ups, mark-downs or commissions and may not represent
actual transactions.

On March 15, 2002, the closing sale price for the Company's common
stock was $25.20 per share. Prima's common stockholders of record at March 15,
2002 totaled 849.

Holders of common stock are entitled to receive such dividends as may
be declared by Prima's Board of Directors. No cash dividends were declared or
paid in 2001, 2000 or 1999. Future cash dividends, if any, will be evaluated
based among other things, on operating results, capital requirements and
financial condition of the Company at the time.

During 2001, Prima issued a total of 10,125 common shares and options
to acquire a total of 135,000 common shares that were not registered under the
Securities Act of 1933, as amended. The shares and options were issued as
follows:

o Prima issued a total of 10,125 common shares during July 2001 to a former
director of Prima upon exercise of stock options previously granted to that
director under Prima's Non-Employee Directors' Stock Option Plan.

o Options to acquire a total of 22,500 common shares were granted by Prima to
directors of Prima under the terms of Prima's Non-Employee Directors' Stock
Option Plan.

o Options to acquire a total of 112,500 common shares were granted to certain
officers of Prima under the terms of Prima's 2001 Incentive Stock Plan.

No underwriter was involved in any of the transactions and no sales
commissions, fees, or similar compensation were paid by Prima to any person in
connection with the issuance of the shares and options. Prima believes that the
grant of the options and the issuance of the shares in each instance was exempt
from the registration requirements of Section 5 of the Securities Act by virtue
of Section 4(2) of the Securities Act and/or under Rule 506 of Regulation D
promulgated by the SEC thereunder, since each recipient of the common shares and
options was a director and/or executive officer of Prima.

22

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth a summary of selected consolidated
financial data. This data should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and the
Consolidated Financial Statements and notes thereto.

23

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

This Item 7 contains "forward-looking statements" which are made
pursuant to the "safe harbor" provisions of the Private Securities Litigation
Reform Act of 1995. These statements include, without limitation, statements
relating to liquidity, financing of operations, continued volatility of oil and
natural gas prices, estimates of future production and net cash flows
attributable to proved reserves, future expenditures, and other such matters.
The words "anticipates," "believes," "expects," "intends" or "estimates" and
similar expressions identify forward-looking statements. Prima does not
undertake to update, revise or correct any of the forward-looking information.
Readers are cautioned that such forward-looking statements should be read in
connection with Prima's disclosures under the heading: "Cautionary Statement for
the Purposes of the 'Safe Harbor' Provisions of the Private Securities
Litigation Reform Act of 1995".

The following discussion is intended to assist in understanding the
Company's financial position and results of operations for the three-year period
ended December 31, 2001. The Consolidated Financial Statements and notes thereto
should be referred to in conjunction with this discussion.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion of financial condition and results of operation are
based upon the information reported in our consolidated financial statements.
The preparation of these financial statements requires us to make assumptions
and estimates that affect the reported amounts of assets, liabilities, revenues
and expenses as well as the disclosure of contingent assets and liabilities at
the date of our financial statements. We base our decisions on historical
experience and various other sources that are believed to be reasonable under
the circumstances. Actual results may differ from the estimates we calculated
due to changing business conditions or unexpected circumstances. Policies we
believe are critical to understanding our business operations and results of
operations are detailed below. For additional information on our significant
accounting policies you should see Notes to Consolidated Financial Statements,
particularly Notes 1 and 11, in our accompanying consolidated financial
statements.

Revenue Recognition - We are engaged in the exploration, development,
acquisition and production of natural gas and crude oil. Our revenue recognition
policy is significant because our revenue is a key component of our results of
operations and our forward looking statements contained in Liquidity and Capital
Resources. We derive our revenue primarily from the sale of produced natural gas
and crude oil. Revenue is recorded in the month our production is delivered to
the purchaser, but payment is generally received between 20 and 90 days after
the date of production. At the end of each period we make estimates of the
amount of production delivered to the purchaser and the price we received. We
use our knowledge of our properties, their historical performance, NYMEX and
local spot market prices and other factors as the basis for these estimates.
Variances between our estimates and the actual amounts received, which have
historically been minimal, are recorded in the month such estimates are revised
or when payment is received.

Fair Value of Derivative Instruments - Beginning in 2001, the estimated fair
values of our derivative instruments are recorded on our consolidated balance
sheet. All of our derivative instruments are entered into to mitigate risks
related to the prices we will receive for our future natural gas and oil
production. We do not use derivative instruments for trading purposes. Although
our derivatives are reported on the balance sheet at fair value, to the extent
that instruments qualify for hedge accounting treatment, changes in fair value
are not included in our consolidated results of operations. Instead, they are
recorded net of taxes directly to stockholders' equity until the hedged oil or
natural gas quantities are produced. To the extent changes in the fair values of
derivatives relate to instruments not qualifying for hedge accounting treatment,
such changes are recorded in income in the period they occur. In determining the
amounts to be recorded, we are required to estimate the fair values of
derivatives. Our estimates are based upon various factors that include contract
volumes and prices, contract settlement dates, quoted closing prices on the
NYMEX or over-the-counter and, where applicable, volatility and the time value
of options. The calculation of the fair value of collars and floors requires the
use of the Black-Scholes option-pricing model. The estimated future prices are
compared to the prices fixed by the derivatives agreements and the resulting
estimated future cash inflows or outflows over the lives of the hedges are
discounted to calculate the fair value of the derivative contracts. These
pricing and discounting variables are sensitive

24

to market volatility as well as changes in future price forecasts, regional
price differences and interest rates. We periodically validate our valuations
using independent third party quotations.

Reserve Estimates - The Company's estimates of gas and oil reserves, by
necessity, are projections based on geologic and engineering data, and there are
uncertainties inherent in the interpretation of such data as well as the
projection of future rates of production and the timing of development
expenditures. Reserve engineering is a subjective process of estimating
underground accumulations of gas and oil that are difficult to measure. The
accuracy of any reserve estimate is a function of the quality of available data,
engineering and geological interpretation and judgment. Estimates of
economically recoverable gas and oil reserves and future net cash flows
necessarily depend upon a number of variable factors and assumptions, such as
expected future production rates, gas and oil prices, operating costs, severance
taxes, and development costs, all of which may in fact vary considerably from
actual results. The future drilling costs associated with reserves assigned to
proved undeveloped locations may ultimately increase to an extent that these
reserves may later be determined to be uneconomic. For these reasons, estimates
of the economically recoverable quantities of gas and oil attributable to any
particular group of properties, classifications of such reserves based on risk
of recovery, and estimates of the future net cash flows expected therefrom may
vary substantially. Any significant variance in the assumptions could materially
affect the estimated quantity and value of the reserves, which could affect the
carrying value of the Company's gas and oil properties and/or the rate of
depletion of the gas and oil properties. Actual production, revenues and
expenditures with respect to the Company's reserves will likely vary from
estimates, and such variances may be material.

Full Cost Method - We use the full cost method of accounting for our oil and gas
activities. Under this method, all costs incurred in the acquisition,
development and exploration of oil and gas properties are capitalized into cost
centers that are established on a country-by-country basis (we have a single
cost center, for the United States). Such amounts include the cost of drilling
and equipping productive wells, dry hole costs, lease acquisition costs and
delay rentals. Capitalized costs also include salaries, employee benefits, costs
of consulting services and other expenses that are directly related to
acquisition, development and exploration activities. Costs associated with
production and general corporate activities are expensed in the period incurred.

Depletion - The capitalized costs of our oil and gas properties, plus estimated
future development and abandonment costs related to our proved reserves, are
amortized on a unit-of-production method based on our estimate of total proved
reserves. The quantities of estimated proved oil and gas reserves is a
significant component of amortization and revisions in such estimates may alter
the rate of future expense. Generally, if reserve volumes increase or decrease,
then the amortization rate per unit of production will change inversely.
However, when capitalized costs change, the amortization rate moves in the same
direction. The per-unit rate is not affected by production volumes.

Full Cost Ceiling Limitation - Under the full cost method, we are subject to
quarterly calculations of a limitation, or "ceiling", on the amount of our oil
and gas properties that can be capitalized on our balance sheet. If the net
capitalized costs of our oil and gas properties exceed the cost center ceiling,
we are subject to a ceiling test writedown to the extent of such excess. A
ceiling test writedown is a non-cash charge to earnings. If required, it would