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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
Item Page
---- ----
PART I
1. and 2. BUSINESS and PROPERTIES ...................................... 3
3. LEGAL PROCEEDINGS ............................................ 18
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .......... 18
PART II
5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS ....................................... 22
6. SELECTED FINANCIAL DATA ...................................... 23
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS ....................... 24
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ... 32
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA .................. 33
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE ....................... 33
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT ........... 34
11. EXECUTIVE COMPENSATION ....................................... 34
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ................................................ 34
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ............... 34
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K .................................................. 34
2
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.
3
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.
4
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.
5
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
6
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
7
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.
8
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.
2001 2000 1999
----------- ----------- -----------
Estimated proved natural gas reserves (Mcf) ........ 115,222,000 154,172,000 124,111,000
Estimated proved oil reserves (barrels) ............ 3,394,000 3,729,000 3,268,000
Present value of estimated future net cash
flows, before future income tax expense ......... $ 91,905,000 $576,052,000 $108,551,000
Standardized measure of discounted
future net cash flows ........................... $ 66,801,000 $371,121,000 $ 75,466,000
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.
2001 2000 1999
--------- --------- ---------
Quantities Sold:
Natural gas (Mcf) ............................ 9,277,000 8,683,000 7,163,000
Oil (barrels) ................................ 431,000 440,000 322,000
Average Sales Price (including hedging effects):
Natural gas (per Mcf) ........................ $ 3.60 $ 3.63 $ 2.10
Oil (per barrel) ............................. $ 25.88 $ 29.29 $ 17.42
Average Production Costs per
Equivalent Mcf(1) ............................. $ 0.56 $ 0.53 $ 0.42
(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.
Productive Wells
---------------------------------------------------------
Oil Gas
---------------------- -------------------------
Gross(1) Net(2) Gross(1)(3) Net(2)(3)
--------- -------- ------------ ---------
Operated:
Colorado .................................. 9 8.5 386 354.4
Wyoming ................................... 0 0.0 300 296.0
Non-operated:
Colorado .................................. 0 0.0 18 7.9
Utah ...................................... 0 0.0 1 0.4
Wyoming ................................... 0 0.0 35 3.3
--- ------ ------- --------
Total(4) .............................. 9 8.5 740 662.0
=== ====== ======= ========
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:
Developed Acreage(1) Undeveloped Acreage(2)
----------------------------- ------------------------------
Location Gross(3) Net(4) Gross(3) Net(4)
-------- --------- -------- --------- --------
Big Horn Basin ....................................... 0 0 102,000 26,000
Denver Basin ......................................... 18,400 15,500 14,000 13,000
Green River Basin .................................... 0 0 84,000 35,000
Powder River Basin ................................... 11,300 10,800 197,000 178,000
Uinta Basin .......................................... 0 0 105,000 74,000
Wind River Basin ..................................... 1,100 150 42,000 25,000
Other basins ......................................... 1,500 50 19,000 16,000
------ ------ ------- -------
Total ................................................ 32,300 26,500 563,000 367,000
====== ====== ======= =======
(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.
Acres Expiring
-------------------------------
Twelve Months Ending: Gross Net
--------- ---------
December 31, 2002 ............................. 16,000 7,000
December 31, 2003 ............................. 20,000 12,000
December 31, 2004 ............................. 59,000 30,000
December 31, 2005 ............................. 92,000 61,000
December 31, 2006 ............................. 43,000 42,000
December 31, 2007 and later ................... 291,000 214,000
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:
2001 2000 1999
----------------- ----------------- -----------------
Gross Net Gross Net Gross Net
----- ------ ----- ----- ----- -----
Development:
Productive ..................................... 123 121.33 178 176.69 33 27.14
Dry ............................................ 0 0.00 3 2.00 1 0.75
---- ------ ---- ------ --- -----
123 121.33 181 178.69 34 27.89
==== ====== ==== ====== === =====
Exploratory:
Productive ..................................... 14 14.00 5 4.90 9 6.19
Dry ........................................... 2 0.25 0 0.00 0 0.00
---- ------ ---- ------ --- -----
16 14.25 5 4.90 9 6.19
==== ====== ==== ====== === =====
Total:
Productive .................................... 137 135.33 183 181.59 42 33.33
Dry ........................................... 2 0.25 3 2.00 1 0.75
---- ------ ---- ------ --- -----
139 135.58 186 183.59 43 34.08
==== ====== ==== ====== === =====
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.
18
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, 2001 HIGH LOW
---------------------------- ---- ---
Quarter Ended March 31, 2001 .......................... $38.94 $25.25
Quarter Ended June 30, 2001 ........................... 32.17 22.81
Quarter Ended September 30, 2001 ...................... 27.69 19.99
Quarter Ended December 31, 2001 ....................... 25.48 19.50
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.
2001 2000 1999 1998 1997
------- ------- ------- ------- -------
Income Statement Data:
Revenues:
Oil and gas sales ....................... $ 44,548 $ 44,437 $ 20,644 $ 16,612 $ 17,840
Gains on derivative instruments, net .... 6,435 0 0 0 0
Oilfield services ....................... 8,090 6,278 4,974 4,148 3,214
Trading revenues ........................ 0 0 2,318 3,956 15,999
Interest, dividend and other ............ 1,214 1,464 1,286 4,378 854
-------- -------- -------- -------- --------
60,287 52,179 29,222 29,094 37,907
-------- -------- -------- -------- --------
Expenses:
Depletion of oil and gas properties ..... 9,190 6,150 4,650 6,260 4,935
Depreciation of other property .......... 1,369 1,054 817 616 497
Lease operating expense ................. 3,295 2,623 2,012 2,041 1,720
Ad valorem and production taxes ......... 3,344 3,421 1,765 1,272 1,355
Oilfield services ....................... 5,482 4,585 3,377 2,701 2,368
General and administrative .............. 3,559 2,916 1,712 1,143 972
Impairment of natural gas swap .......... 241 0 0 0 0
Trading costs ........................... 0 0 2,827 3,936 15,323
-------- -------- -------- -------- --------
26,480 20,749 17,160 17,969 27,170
-------- -------- -------- -------- --------
Income before income taxes and
cumulative effect of change in
accounting principle .................... 33,807 31,430 12,062 11,125 10,737
Provision for income taxes ................ 10,650 9,535 3,035 3,060 2,635
-------- -------- -------- -------- --------
Net income before cumulative effect of
change in accounting principle ............ 23,157 21,895 9,027 8,065 8,102
Cumulative effect of change in
accounting principle .................... 611 0 0 0 0
-------- -------- -------- -------- --------
Net income ................................ 23,768 $ 21,895 $ 9,027 $ 8,065 $ 8,102
======== ======== ======== ======== ========
Basic net income per share before
cumulative effect adjustment ............ $ 1.82 $ 1.72 $ 0.70 $ 0.62 $ 0.62
Cumulative effect adjustment .............. 0.05 0.00 0.00 0.00 0.00
-------- -------- -------- -------- --------
Basic net income per share ................ $ 1.87 $ 1.72 $ 0.70 $ 0.62 $ 0.62
======== ======== ======== ======== ========
Diluted net income per share before
cumulative effect adjustment ............ $ 1.75 $ 1.65 $ 0.69 $ 0.61 $ 0.61
Cumulative effect adjustment .............. 0.05 0.00 0.00 0.00 0.00
-------- -------- -------- -------- --------
Diluted net income per share .............. $ 1.80 $ 1.65 $ 0.69 $ 0.61 $ 0.61
======== ======== ======== ======== ========
Balance Sheet Data (at end of period):
Total assets .............................. $135,444 $104,900 $ 72,665 $ 66,866 $ 57,921
Net property and equipment ................ 96,005 70,597 44,467 55,607 43,181
Long-term debt ............................ 0 0 0 120 240
Stockholders' equity ...................... 101,740 80,298 58,908 51,308 43,214
Working capital ........................... 28,122 25,678 21,408 5,467 7,952
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
reduce earnings and impact stockholders' equity in the period of occurrence and
result in lower amortization expense in future periods. The discounted present
value of our proved reserves is a major component of the ceiling calculation and
requires subjective judgments. Given the volatility of natural gas and oil
prices, it is likely that our estimate of discounted future net cash flows from
proved reserves will change in the future. If natural gas and oil prices
decline, even if only for a short period of time, or if we have downward
revisions to our estimated proved reserves, it is possible that writedowns of
our oil and gas properties could occur. While the quantities of proved reserves
require substantial judgment, the associated prices of oil and natural gas
reserves that are included in the discounted present value of the reserves do
not require judgment. The future net revenues associated with our estimated
proved reserves are not based on our assessment of future prices or costs. The
ceiling calculation dictates that prices and costs in effect as of the last day
of the quarter are held constant. However, we may not be subject to a writedown
if prices increase shortly after the end of a quarter in which a writedown might
otherwise be required.
25
Unevaluated Costs - Unevaluated costs are excluded from our amortization base
until we have evaluated the properties associated with these costs. The costs
associated with unevaluated leasehold acreage and wells that have not yet been
determined to be productive or non-productive are not initially included in our
amortization base. Leasehold and associated costs are either transferred to our
amortization base with the costs of drilling related wells or are assessed
quarterly for possible impairment or reduction in value. Leasehold costs are
transferred to our amortization base if estimated fair value is below cost. The
decision to withhold costs from amortization and the timing of transferring such
costs into the amortization base involves a significant amount of management
judgment and may be subject to changes over time based on several factors,
including our drilling plans, availability of capital, project economics and
results of drilling on adjacent acreage.
Other Property and Equipment - Oilfield service equipment and other property and
equipment are carried at cost. Renewals and betterments are capitalized, while
repairs and maintenance are expensed. Capitalized costs are depreciated using
the straight-line method over the estimated useful lives of the assets. The
carrying value of property and equipment is reviewed for possible impairment
whenever events or changes in circumstances indicate that the carrying amount
may not be recoverable. Assets are determined to be impaired if a forecast of
undiscounted estimated future net operating cash flows directly related to the
asset, including disposal value if any, is less than the carrying amount of the
asset. If any asset is determined to be impaired, the loss is measured as the
amount by which the carrying amount of the asset exceeds its fair value. An
estimate of fair value is based on the best information available, including
prices for similar assets. Changes in such estimates could cause the Company to
reduce the carrying value of property and equipment.
Income Taxes - We provide for deferred income taxes on the difference between
the tax basis of an asset or liability and its carrying amount in our financial
statements. This difference will result in taxable income or deductions in
future years when the reported amount of the asset or liability is recovered or
settled, respectively. Our federal and state income tax returns are generally
not filed before the consolidated financial statements are prepared. We,
therefore, estimate the tax basis of our assets and liabilities at the end of
each period as well as the effects of tax rate changes, tax credits and net
operating loss carryforwards. Any differences between estimates we initially
used and subsequently determined to be appropriate are recorded in the period in
which our estimate is revised.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal sources of liquidity have been the internal
generation of cash flow from operations and existing net working capital.
Additional potential sources of capital include proceeds from the sale of
assets, borrowings, and issuances of common stock or other securities.
Net cash provided by operating activities totaled $43,008,000 in the
year ended December 31, 2001, compared to $36,376,000 for the year ended
December 31, 2000 and $12,006,000 for the year ended December 31, 1999. Net
working capital at December 31, 2001 totaled $28,122,000, as compared to
$25,678,000 at the end of the prior year. Prima's cash equivalents and
short-term investments totaled $25,755,000 at December 31, 2001, compared to
$22,693,000 at December 31, 2000, and the Company was free of long-term debt at
both dates.
The Company's revenues and cash flows are substantially derived from
oil and gas sales, which are dependent on oil and gas production volumes and
sales prices. Prima's aggregate net production volumes have increased from
2,765,000 Mcfe in the first quarter of 2001, to 2,892,000 Mcfe in the second
quarter, 3,088,000 Mcfe in the third quarter and 3,118,000 in the most recent
quarter, but gas prices have declined more significantly during the same
periods. As a consequence, the Company's oil and gas sales revenue, including
derivatives qualifying for hedge accounting, declined from $16,357,000 in the
first quarter, to $11,909,000 in the second quarter, $9,163,000 in the third
quarter and $7,119,000 in the latest quarter. For the full year in 2001, Prima's
oil and gas sales totaled $44,548,000, approximately flat with the prior year,
on a 5% increase in total net production. Prima's future revenues will continue
to be significantly affected by volatility in oil and gas prices.
This volatility in oil and gas prices is also reflected in year-end
estimates of the Company's proved oil and gas reserves and related future net
cash flows. Estimated future net cash flows from proved oil and gas reserves
were
26
$156,624,000 at December 31, 2001 compared to $975,940,000 at December 31, 2000
and $190,008,000 at December 31, 1999. The standardized measure of discounted
future net cash flows of the Company's proved oil and natural gas reserves was
$66,801,000 at December 31, 2001, compared to $371,121,000 at December 31, 2000
and $75,466,000 at December 31, 1999. The fluctuations in both future net cash
flows and the standardized measure were primarily attributable to the volatility
of commodity prices. The Company's average realized prices as of the last day of
each of the past three years, which were therefore used without future
escalation in preparing year-end reserve estimates, were as follows for 2001,
2000 and 1999, respectively: $1.94, $7.51 and $1.90 per Mcf of natural gas; and
$19.71, $26.48 and $24.68 per barrel of oil.
The Company increased its net working capital, with the sale of certain
oil and gas properties on March 5, 2002 for approximately $13,539,000 of cash.
The assets sold included the Company's Stones Throw CBM project in the northern
Powder River Basin, the associated gathering system facilities and approximately
35,000 net undeveloped acres in the Stones Throw area. These properties
accounted for approximately 6.1% of Prima's total estimated proved oil and gas
reserves and 4.5% of the related estimated present value of future net cash
flows before income taxes, as of the end of 2001. The producing wells sold
accounted for approximately 9.6% of Prima's total oil and gas sales revenue
before hedging gains in the fourth quarter of 2001.
The Company's average daily net production in the fourth quarter of
2001 totaled approximately 33,900 Mcfe, including 6,300 Mcf per day of CBM
production from the Stones Throw Field, which was sold on March 5, 2002. In the
absence of an acquisition in the interim, Prima does not expect significant
production from new sources until the third quarter of this year, when
production from the Company's Porcupine-Tuit CBM project is expected to
commence. No other major variances from recent production levels are expected in
the near term. Prima has drilled 23 Wyodak coal wells at Porcupine-Tuit to-date
and has 72 additional locations in the project area identified for near-term
drilling, but 63 of these are on federal lands for which drilling access is
presently limited. Production reported for several nearby wells owned by other
operators have been in the 150 to 400 Mcf per day per well range, after brief
de-watering periods. The Company expects production from its wells in this area
to exhibit similar performance, but cannot precisely forecast when production
will be initiated or how the wells will then perform. The timing and amounts of
production that may be added later in the year from other new activities,
including other CBM projects and exploration also cannot be precisely forecast.
Prima invested $35,248,000 in additions to oil and gas properties
during 2001, compared to $31,952,000 in 2000 and $18,617,000 in 1999. During
2001, $31,114,000 was expended for development, $1,620,000 for exploratory
activities, $2,114,000 for acquisitions of unproved oil and gas properties, and
$400,000 for purchases of proved properties. Other uses of funds in 2001
included $3,866,000 for treasury stock repurchases, $1,956,000 for purchases of
oilfield service equipment and facilities, and $125,000 for other assets.
Excluding acquisitions, Prima currently plans to make capital
investments in 2002 aggregating between $25 million and $30 million. Among
anticipated 2002 drilling activities are 60 to 110 CBM wells, six to 12 wells in
the Denver Basin, and three to six exploratory wells. The Company also intends
to invest in various hook-up and infrastructure projects, including the
Porcupine-Tuit CBM project in the Powder River Basin, and anticipates conducting
40 to 50 refracturing or recompletion operations in the Denver Basin. A
significant portion of the 2002 budget has also been reserved for acquisition of
additional acreage for future exploration or exploitation, or for other
opportunities identified during the year. Activities planned by the Company for
2002 are weighted toward the second half of the year. This may enable the
Company to benefit from development and operating efficiencies related to the
expected issuance by the Bureau of Land Management of a record of decision
concerning an environmental impact statement (EIS) for CBM development in the
Powder River Basin. Approximately 82% of Prima's Powder River Basin acreage is
federal, and access to federal lands has been limited pending completion of the
EIS. The Company has also been deferring certain investments to benefit from
anticipated improvements in gas prices and service costs, which have recently
begun to materialize. Prima does not establish a specific budget for property
acquisitions, but the Company continues to pursue such opportunities on an
ongoing basis. The strong financial condition of the Company allows for
considerable flexibility in responding to opportunities. Spot market prices for
gas and oil have risen by approximately 20% from levels prevailing when the
Company's budgeting process was initially completed. These prices, if deemed
sustainable, may result in an acceleration of activities, which could include
additional Powder River Basin CBM and Denver Basin drilling.
27
In January 2001, Prima's Board of Directors approved a repurchase
program of up to 5% of the Company's common stock then outstanding, or
approximately 640,000 shares. As of December 31, 2001, approximately 485,000
shares remained subject to repurchase under this authorization.
Prima expects to fund its exploration, development, and exploitation
operations, the expansion of its service companies, and any re-purchases of
common stock primarily with cash provided by operating activities and working
capital. The Company also regularly reviews opportunities for acquisition of
assets or companies related to the oil and gas industry that could expand or
enhance its existing business. If a sufficiently large transaction is
consummated, it could involve the incurrence of debt or issuance of equity
securities.
RESULTS OF OPERATIONS
As noted above, the Company's primary source of revenues is the sale of
oil and natural gas production. Because of significant fluctuations in oil and
natural gas prices and variances in production volumes, the Company's operating
results for any period are not necessarily indicative of future operating
results.
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. Prima's revenues, cash flows, earnings and
operations are adversely affected when oil and gas prices decline. Gas prices
have declined significantly since reaching record high levels early in 2001, and
oil prices have also declined during the past year, albeit more modestly. These
price declines have unfavorably impacted the Company's operating results, as
more fully described below. The Company cannot accurately predict future oil and
natural gas prices, but historically oil and gas supply and demand have
responded to changes in price levels to correct from short-lived extreme levels
of high or low prices.
2001 VS 2000
For the year ended December 31, 2001, the Company earned net income of
$23,768,000, or $1.80 per diluted share, on revenues of $60,287,000, compared to
net income of $21,895,000, or $1.65 per diluted share, on revenues of
$52,179,000 for the year ended December 31, 2000. Expenses, other than income
taxes, were $26,480,000 for 2001 compared to $20,749,000 for 2000. Revenues
increased $8,108,000 or 16%, expenses increased $5,731,000 or 28% and net income
increased $1,873,000 or 9% in 2001.
Revenues for 2001 included $9,816,000 of gains from oil and gas
derivatives (see "Derivative Activities" in Notes to Consolidated Financial
Statements). This total included hedging gains of $3,381,000, which were
reflected in oil and gas sales, plus $6,435,000 of separately reported gains on
derivative instruments not qualifying for hedge accounting, of which $2,057,000
were realized and $4,378,000 were unrealized as of December 31, 2001. During the
prior year the company recognized $42,000 of hedging gains. Derivative
instruments that did not qualify for hedge accounting were principally NYMEX gas
swaps for which the Company did not elect to enter into corresponding swaps for
Rocky Mountain basis differentials.
Oil and gas sales reported for 2001 totaled $44,548,000, compared to
$44,437,000 for 2000, an increase of less than 1%. The flat sales results were
creditable to a 5% year-over-year growth in production volumes offset by
approximately a like-sized decline in the average price realized per equivalent
unit of natural gas and oil production. Excluding gains from derivative
instruments, oil and gas sales reported for 2001 were $41,167,000, compared to
$44,395,000 for 2000, a decrease of $3,228,000 or 7%.
The following information is provided excluding effects of derivatives.
The average sales price received by the Company for natural gas production was
$3.24 per Mcf in 2001, compared to $3.63 per Mcf in 2000, a decrease of $0.39
per Mcf, or 11%. The average price received per barrel of oil was $25.68 in
2001, compared to $29.20 in 2000, representing a decrease of $3.52 per barrel or
12%. On an Mcf equivalent basis, the average price received was $3.47
28
per Mcfe in 2001 compared to $3.92 per Mcfe in the prior year, representing an
overall 11% decline in average prices. The portion of the Company's total oil
and gas revenues that was derived from natural gas was 73% in 2001 compared to
71% in 2000.
The $3,381,000 of gains from derivative transactions that were
accounted for as hedges in 2001 had the effect of increasing average price
realizations reported for the year by $0.36 per Mcf of natural gas, $0.20 per
barrel of oil, and $0.29 per Mcfe. These hedges covered approximately 24% of the
Company's natural gas production and 19% of its oil production for the year.
Total gains realized on all derivatives related to production months in 2001,
including the portion reported as non-hedge derivatives, totaled $5,438,000.
During 2000, the Company hedged approximately 1% of its gas production and 5% of
its oil production, and realized gains of $42,000 were included in oil and gas
revenues. These gains had the effect of increasing average price realizations by
$0.09 per barrel of oil, but had a negligible impact on average price
realizations per Mcf of gas or per Mcfe.
The Company's natural gas production totaled 9,277,000 Mcf in 2001
compared to 8,683,000 Mcf in 2000, representing a current year increase of
594,000 Mcf, or 7%. Prima's oil production totaled 431,000 barrels and 440,000
barrels in 2001 and 2000, respectively, representing a decrease of 9,000
barrels, or 2%. On an equivalent unit basis, the Company's production increased
approximately 5%, to 11,863,000 Mcfe in the recent year from 11,325,000 Mcfe in
2000. Total production was 78% natural gas and 22% oil in 2001, compared to 77%
gas and 23% oil in the prior year. Net production from the Company's CBM
operations, which totaled 1,453,000 Mcf in 2001 compared to 7,000 Mcf in 2000,
more than offset net decreases from the Company's other producing properties,
which were attributable to natural declines and limited new activity.
The Company's depletion expense for oil and gas properties was
$9,190,000, or $0.77 per Mcfe, in 2001, compared to $6,150,000, or $0.54 per
Mcfe, in 2000. The substantial increase in the depletion rate reflects a number
of factors, including: significant declines in oil and gas prices, which, under
the methodology prescribed, affects estimates of oil and gas reserves that can
be economically recovered through future production; increases in oilfield
service costs, which impacted actual costs incurred during the past year and the
assumptions required to be used in estimating future development costs; and use
of more conservative assumptions for estimating undeveloped CBM reserves,
pending additional performance-related data. The depletion rate per Mcfe was
increased mid-year 2001 to reflect these factors, and averaged $0.90 during the
second half of the year.
Depreciation of other fixed assets, which include service equipment,
office furniture and equipment, and buildings, was $1,369,000 and $1,054,000 for
2001 and 2000, respectively. The increase of $315,000, or 30%, was due primarily
to acquisitions of oilfield service equipment in 2000 and 2001.
Lease operating expenses ("LOE") totaled $3,295,000 for the year ended
December 31, 2001 compared to $2,623,000 for the year ended December 31, 2000,
an increase of $672,000 or 26%. The increase was primarily attributable to new
production from CBM wells. Ad valorem and production taxes were $3,344,000 and
$3,421,000 for the same periods, a decrease of $77,000 or 2%. Production taxes
fluctuate with revenues and changing mill levy rates. Total lifting costs (LOE
plus ad valorem and production taxes) were 15% of oil and gas revenues and $0.56
per Mcfe for 2001 compared to 14% and $0.53 per Mcfe for 2000.
Oilfield services include the operations of Action Oilfield Services,
Inc. (Colorado) and Action Energy Services (Wyoming), wholly-owned subsidiaries.
Related revenues include well servicing fees from completion and swab rigs, CBM
drilling rigs, trucking, water hauling, equipment rentals, and other related
activities. Services are provided to both Prima and unaffiliated third parties,
but intercompany billings are eliminated in consolidation. Revenues from third
parties totaled $8,090,000 for the year ended December 31, 2001 compared to
$6,278,000 for the year ended December 31, 2000, an increase of $1,812,000, or
29%. Costs of oilfield services provided to third parties were $5,482,000 in
2001 compared to $4,585,000 for 2000, an increase of $897,000 or 20%. Higher
revenues and costs both reflected increases in the amount of equipment placed in
service and the portion of services provided to third parties. Approximately 34%
of fees billed by the service companies in 2001 were for Company-owned property
interests, compared to 37% in 2000. Improved revenues were also partially
attributable to rate increases resulting from increased demand for oilfield
services.
29
General and administrative expenses ("G&A"), net of third party
reimbursements and amounts capitalized, were $3,559,000 for the year ended
December 31, 2001 compared to $2,916,000 for the year ended December 31, 2000.
Net G&A costs increased by $643,000 or 22% due to expansion of the Company's
activities and operations, partially offset by increased amounts capitalized.
Third party reimbursements of management and operator fees decreased from
$426,000 in 2000 to $371,000 in 2001 due to the Company's acquisition of
additional ownership interests in certain managed properties. Capitalized G&A
increased from $1,200,000 in 2000 to $1,573,000 in 2001, reflecting additional
costs incurred to grow exploration and development activities.
The impairment of a natural gas swap in 2001 relates to a derivatives
contract with Enron North America Corp, which filed for bankruptcy protection in
December 2001. Prima had an unrealized gain of $241,000 due from Enron when the
Company terminated the contract under default provisions in the agreement.
Although this amount was reflected in gains on derivative instruments in 2001,
the full amount was reserved for and reflected as an impairment expense in the
same period.
The provision for income taxes was $10,650,000 for the year ended
December 31, 2001 compared to $9,535,000 for the year ended December 31, 2000,
an increase of $1,115,000 or 12%. The Company's effective tax rate increased to
31.5% in 2001 from 30.3% in 2000. The effective tax rates in both years were
less than statutory rates due to permanent differences in financial and taxable
income, consisting primarily of statutory depletion deductions and Section 29
tax credits. The higher effective tax rate in 2001 was primarily attributable to
a $2,377,000, or 8%, increase in pre-tax income without a proportionate increase
in permanent differences.
2000 VS 1999
Prima earned net income in 2000 of $21,895,000, or $1.65 per diluted
share, on revenues of $52,179,000, compared to net income of $9,027,000, or
$0.69 per diluted share, on revenues of $29,222,000 in 1999. Expenses, other
than income taxes, were $20,749,000 for 2000 compared to $17,160,000 for 1999.
Revenues increased $22,957,000 or 79%, expenses increased $3,589,000 or 21% and
net income increased $12,868,000 or 143% in 2000, compared to 1999.
Oil and gas sales in 2000 were $44,437,000 compared to $20,644,000 in
1999, an increase of $23,793,000 or 115%. This increase was due to both
significantly higher product prices and increased production. The Company's net
natural gas production was 8.7 Bcf for 2000 compared to 7.2 Bcf in 1999, an
increase of 1.5 Bcf or 21%. Net oil production was 440,000 barrels in 2000
compared to 322,000 barrels for 1999, an increase of 118,000 barrels or 37%. On
an Mcfe basis, the Company's production for 2000 increased 2.2 Bcfe or 25%. The
average price received per Mcf of natural gas sold was $3.63 for 2000 compared
to $2.10 per Mcf for the prior year, an increase of $1.53 per Mcf or 73%. The
average price received per barrel of oil sold was $29.29 in 2000 compared to
$17.42 in 1999, an increase of $11.87 per barrel or 68%. During the year ended
December 31, 2000, the Company hedged approximately 1% of its gas production and
5% of its oil production. Hedging gains of $42,000 were included in oil and gas
revenues for the year, which increased the average price received per barrel of
oil by $0.09 and had no material effect on the price realized for natural gas or
per equivalent unit of production. The Company hedged approximately 25% of its
oil production and 15% of its natural gas production in 1999. Hedging losses of
$180,000 were included in oil and gas revenues for the year, which decreased
average prices received by $0.17 per barrel of oil, by $0.02 per Mcf of natural
gas, and by $0.02 per Mcfe of production.
The Company's depletion of oil and gas properties was $6,150,000, or
$0.54 per Mcfe, on 11,325,000 equivalent Mcf produced in 2000. This compared to
$4,650,000, or $0.51 per Mcfe, on 9,093,000 equivalent Mcf produced in 1999. The
higher depletion rate for 2000 reflected higher oilfield service costs
experienced during the fourth quarter of 2000, as industry activity escalated.
Depreciation of other fixed assets, including service equipment, office
furniture and equipment and buildings, was $1,054,000 and $817,000 for 2000 and
1999, respectively. Depreciation expense on these assets increased $237,000, or
29%, due primarily to acquisitions of oilfield service equipment.
LOE was $2,623,000 in 2000 compared to $2,012,000 in 1999. Ad valorem
and production taxes were $3,421,000 and $1,765,000, respectively, for the same
periods. Production taxes increased with oil and gas revenues, on higher
production volumes and product prices. Total lifting costs were 14% of oil and
gas revenues and $0.53 per Mcfe for 2000, compared to 18% and $0.42 for 1999.
30
Oilfield services revenues were $6,278,000 and $4,974,000 in 2000 and
1999, respectively. Costs for oilfield services were $4,585,000 in 2000 compared
to $3,377,000 in 1999. These amounts reflect an increase in revenues of
$1,304,000, or 26%, and an increase in costs of $1,208,000 or 36%. Utilization
levels in the Wattenberg Area remained high and activity levels increased
steadily during the period in the Powder River Basin of Wyoming, where service
operations were initiated in March 1999. During 2000 and 1999, 37% and 26%,
respectively, of the gross fees billed by the service companies were for
Prima-owned property interests.
Trading revenues and costs relate to the marketing of third-party gas
by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary. Trading
activities fluctuate with natural gas markets and the Company's ability to
develop markets that meet the Company's trading criteria. The Company engaged in
no trading activities during 2000. In 1999, the Company marketed 1,311,000
Mmbtus of natural gas, with trading revenues of $2,318,000 and costs of
$2,827,000.
G&A, net of third-party reimbursements, totaled $2,916,000 for 2000
compared to $1,712,000 for 1999, an increase of $1,204,000 or 70%. Third-party
reimbursements were $426,000 and $619,000 during 2000 and 1999, respectively.
The Company's G&A increased due to expansion of the Company's operations,
particularly increased activities in the Powder River Basin. The Company
capitalized G&A costs of $1,200,000 and $780,000 in 2000 and 1999, respectively,
reflecting these increases in exploration and development activities.
The provision for income taxes was $9,535,000 for 2000 compared to
$3,035,000 for 1999. The effective tax rate was 30.3% in 2000 compared to 25.2%
in 1999. The Company's effective tax rate increased primarily because pre-tax
income increased $19,368,000 or 161% for 2000, while permanent differences did
not increase proportionately.
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 141, "Business
Combinations." SFAS No. 141 is intended to improve the transparency of the
accounting and reporting for business combinations by requiring that all
business combinations be accounted for under a single method, the purchase
method. This statement is effective for all business combinations initiated
after June 30, 2001. Management does not believe the adoption of this statement
will have a material effect on the Company's financial position or results of
operations.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement applies to intangibles and goodwill acquired
after June 30, 2001, as well as goodwill and intangibles previously acquired.
Under this statement, goodwill as well as other intangibles determined to have
an infinite life will no longer be amortized. These assets will be reviewed for
impairment on a periodic basis. This statement is effective for the Company in
the first quarter of 2002. Management does not believe the adoption of this
statement will have a material effect on the Company's financial position or
results of operations.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with long-lived assets and requires the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The associated asset retirement costs are capitalized as part of the
carrying costs of the asset. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002, and early adoption is permitted. The Company is
currently assessing, but has not yet determined, the impact of SFAS No. 143 on
its consolidated results of operations, cash flows or financial position.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that
long-lived assets be measured at the lower of carrying amount or fair value less
costs to sell, whether reported in continuing operations or in discontinued
operations. Therefore, discontinued operations will no longer be measured at net
realizable value or include amounts for operating losses that have not yet
occurred. SFAS No. 144 is effective for financial statements issued for fiscal
years beginning after December 15, 2001 and generally is to be applied
prospectively. Management does not believe the adoption of this statement will
have a material effect on the Company's financial position or results of
operations.
31
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in prices received
on sales of natural gas and oil production. The Company periodically enters into
derivative contracts to mitigate a portion of this commodity price risk. Such
derivatives consist of commodity futures or price swaps (agreements with
counterparties to exchange floating prices for fixed prices), and options on
such futures or price swaps. These instruments reduce the Company's exposure to
decreases in gas and oil prices, or increases in differentials between NYMEX and
Rocky Mountain gas prices, but they also generally limit the benefits realized
by the Company from increases in prices or narrowing of basis differentials. By
hedging only a portion of its exposure to changes in prices, the Company is able
to benefit from increases in gas and oil prices or improvements in basis
differentials, but it remains exposed to market risk on the portion of its
production not covered by such derivatives. The Company also retains risks
related to the ineffective portion of its derivatives instruments, when
applicable.
The Company has derivative positions that are intended to offset risks
associated with downward price movements in benchmark NYMEX gas and oil prices
and basis swaps to protect the Company from increases in the differential
between NYMEX and Rocky Mountain gas prices. The Company's derivatives contracts
generally represent cash flow hedges that are determined to be qualifying or
non-qualifying for hedge accounting treatment in accordance with the provisions
of SFAS 133. See Derivative Activities in Notes to Consolidated Financial
Statements for additional information with respect to derivatives and related
accounting policies.
All derivatives transactions are executed by personnel who have
appropriate skills, experience and supervision. The personnel involved in these
activities must follow prescribed trading limits and parameters that are
regularly reviewed by the Company's Chief Executive Officer. All derivatives
transactions are approved by the Company's Chief Executive Officer before being
entered into and significant transactions are reviewed by the Company's Board of
Directors. The Company uses only conventional derivative instruments and
attempts to manage its credit risk by entering into derivative contracts only
with financial institutions that are believed to be reputable and which carry an
investment grade rating.
Following are disclosures regarding the Company's market risk
instruments. Investors and other users are cautioned to avoid simplistic use of
these disclosures. Users should realize that the actual impact of future
commodity price movements will likely differ from the amounts disclosed below
due to ongoing changes in risk exposure levels and concurrent adjustments to
positions. It is not possible to accurately predict future movements in natural
gas and oil prices.
During 2001, the Company sold 431,000 barrels of oil. A hypothetical
decrease of $2.57 per barrel (10% of average prices for the period exclusive of
hedging transactions) would have decreased the Company's production revenues by
$1,108,000 for the period. The Company sold 9,277,000 Mcf of natural gas during
the same period. A hypothetical decrease of $ 0.32 per Mcf (10% of average
prices for the period exclusive of hedging transactions) would have decreased
the Company's production revenues by $2,969,000 for the period.
The Company closed certain derivative instruments between December 31,
2001 and March 15, 2002, for net realized gains totaling $2,450,000. As of March
15, 2002, open oil and gas derivative instruments showed net unrealized losses
of $48,000, as follows:
32
Market Total Volumes Contract Unrealized
Time Period Index (MMBtu or Bbls) Price Gains (Losses)
----------- ------- --------------- -------- --------------
Natural gas futures
April - June 2002 ........................... NYMEX 2,300,000 $ 3.152 $ 69,000
July - September 2002 ....................... NYMEX 2,100,000 3.214 59,000
October - December 2002 ..................... NYMEX 1,000,000 3.308 (4,000)
January - February 2003 ..................... NYMEX 300,000 3.630 (35,000)
Natural gas basis swaps
November - December 2002 .................... NYMEX/CIG 600,000 0.34 42,000
January - March 2003 ........................ NYMEX/CIG 900,000 0.34 63,000
Crude Oil Futures
May - June 2002 ............................. NYMEX 30,000 21.60 (98,000)
July - September 2002 ....................... NYMEX 45,000 21.45 (144,000)
---------
Total Unrealized Gains ........................... $ (48,000)
=========
As of December 31, 2001, the Company had $4,378,000 of unrealized gains
on derivatives that did not qualify for hedge accounting, which had been
reported as revenue in 2001, and $94,000 of unrealized mark-to-market gains on
derivatives treated as hedges, which amount was included in other comprehensive
income for 2001. This total of $4,472,000 exceeded the aggregate of gains
realized on derivatives in 2002 through March 15 and the net unrealized loss on
derivatives outstanding at that date by $2,070,000. This amount less the $94,000
of unrealized hedging gains which were not reported as revenue in 2001 would be
recorded as a reduction of current period or future revenue if gas and oil
prices were to remain at levels reflected on futures markets as of March 15,
2002. Such amounts will change, however, potentially significantly, as gas and
oil prices rise or fall before such contracts expire or are terminated.
The table above excludes commodity positions with Enron North America
Corp, which filed for bankruptcy protection in December 2001. Prima's unrealized
hedge gain due from Enron totaled approximately $241,000 when the Company
terminated the contract under default provisions in the agreement. Although this
amount was reflected in gains on derivative instruments in 2001, the full amount
was reserved for and reflected as an impairment expense in the same period.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements that constitute Item 8 are
attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements is also included in Item 14(a) of this Annual
Report on Form 10-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
33
Since the Company's inception, there has not been any Form 8-K filed
under the Securities Exchange Act of 1934 reporting a change in accountants in
which there was a reported disagreement on any matter of accounting principles
or practices or financial statement disclosure.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, and 13 are
omitted because the Company will file a definitive proxy statement pursuant to
Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days
after the close of the fiscal year. The information required by such Items will
be included in the definitive proxy statement to be so filed for the Company's
annual meeting of stockholders scheduled for May 15, 2002 and is hereby
incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report ............................................ 36
Consolidated Balance Sheets at December 31, 2001 and 2000 ............... 37
Consolidated Statements of Income for the years ended
December 31, 2001, 2000 and 1999 ................................... 39
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2001, 2000 and 1999 ................................... 40
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2001, 2000 and 1999 ................................... 41
Consolidated Statements of Cash Flows for the years ended
December 31, 2001, 2000 and 1999 ................................... 42
Notes to Consolidated Financial Statements for the years ended
December 31, 2001, 2000 and 1999 ................................... 43
(a)(2) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not
applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.
(a)(3) EXHIBITS
The following Exhibits are filed herewith pursuant to Rule 601 of the
Regulation S-K or are incorporated by reference to previous filings.
34
EXHIBIT NO. DOCUMENT
3 Certificate of Incorporation of Prima energy Corporation, Delaware,
as filed August 18, 1988. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)
3 Certificate of Amendment of Certificate of Incorporation of Prima
Energy Corporation filed May 1, 1989. (Incorporated by reference to
Annual Report on Form 10-K for Prima Energy Corporation dated June
30, 1989.)
3 Bylaws of Prima Energy Corporation. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated June 30,
1997.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated September
30, 2000.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated June 30,
2001 and filed August 14, 2001.)
4 Rights Agreement dated as of May 23, 2001, between Prima Energy
Corporation and Computershare Trust Company, Inc., as Rights Agent,
including the form of Certificate of Designation, Powers,
Preferences and Rights of Series A Participating Preferred Stock
dated May 29, 2001, as Exhibit A, the Form of Right Certificate, as
Exhibit B, and the Summary of Rights to Purchase Preferred Shares.
(Incorporated by reference to Current Report on Form 8-K for Prima
Energy Corporation dated May 23, 2001 and filed June 6, 2001.)
10 Prima Energy Corporation Employee Stock Ownership Plan
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation dated June 30, 1989.)
10 Prima Energy Corporation 1993 Stock Incentive Plan. (Incorporated
by reference to Annual Report on Form 10-K for Prima Energy
Corporation dated December 31, 1993.)
10 Agreement of Lease between Denver-Stellar Associates LP, Landlord
and Prima Energy Corporation, Tenant, effective December 1, 2000.
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation dated December 31, 2000.)
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP
(b) REPORTS ON FORM 8-K
During the quarter ended and subsequent to December 31, 2001, the
Company filed the following reports on Form 8-K:
o Report dated November 13, 2001, reporting earnings for the quarter and
nine months ended September 30, 2001, and providing an update on
operating activities and commodity hedging.
o Report dated March 4, 2002, reporting year-end 2001 reserves, year 2002
estimated capital expenditures, and the sale of assets.
o Report dated March 20, 2002, reporting year-end 2001 financial results
and providing an update of operating activities and commodity hedging
transactions.
35
INDEPENDENT AUDITORS' REPORT
Prima Energy Corporation:
We have audited the accompanying consolidated balance sheets of Prima
Energy Corporation ("Company") and subsidiaries as of December 31, 2001 and
2000, and the related consolidated statements of income, comprehensive income,
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2001. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of the Company and its
subsidiaries at December 31, 2001 and 2000, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2001 in conformity with accounting principles generally accepted in the
United States of America.
As discussed in Note 1 to the consolidated financial statements, in
2001 the Company adopted Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities."
DELOITTE & TOUCHE LLP
March 15, 2002
Denver, Colorado
36
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
ASSETS
2001 2000
------------- -------------
CURRENT ASSETS
Cash and cash equivalents ...................................................... $ 23,337,000 $ 20,382,000
Available for sale securities, at market ....................................... 2,418,000 2,311,000
Receivables (net of allowance for doubtful
accounts: $295,000 and $44,000) ............................................ 5,806,000 8,902,000
Derivatives, at fair value ..................................................... 4,472,000 0
Inventory ...................................................................... 1,415,000 1,409,000
Other .......................................................................... 710,000 1,042,000
------------- -------------
Total current assets ......................................................... 38,158,000 34,046,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted for using the full cost method:
Proved ......................................................................... 130,710,000 100,270,000
Unproved ....................................................................... 13,132,000 9,382,000
Less accumulated depreciation, depletion and amortization ..................... (53,270,000) (43,935,000)
------------- -------------
Oil and gas properties - net ............................................... 90,572,000 65,717,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ..................................................... 9,159,000 7,664,000
Furniture and equipment ........................................................ 694,000 729,000
Field office, shop and land .................................................... 473,000 473,000
------------- -------------
10,326,000 8,866,000
Less accumulated depreciation .................................................. (4,893,000) (3,986,000)
------------- -------------
Property and equipment - net ............................................... 5,433,000 4,880,000
------------- -------------
OTHER ASSETS ................................................................... 1,281,000 257,000
------------- -------------
$ 135,444,000 $ 104,900,000
============= =============
See accompanying notes to consolidated financial statements.
37
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 2001 AND 2000
LIABILITIES AND STOCKHOLDERS' EQUITY
2001 2000
------------- -------------
CURRENT LIABILITIES
Accounts payable ..................................................... $ 1,668,000 $ 3,207,000
Amounts payable to oil and gas property owners ....................... 1,910,000 2,501,000
Ad valorem and production taxes payable .............................. 3,272,000 1,857,000
Accrued and other liabilities ........................................ 1,408,000 803,000
Deferred tax liability ............................................... 1,778,000 0
------------- -------------
Total current liabilities ........................................ 10,036,000 8,368,000
AD VALOREM TAXES, non-current ........................................ 3,302,000 3,213,000
DEFERRED INCOME TAX LIABILITY ........................................ 20,366,000 13,021,000
------------- -------------
Total liabilities ............................................... 33,704,000 24,602,000
------------- -------------
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued or outstanding ........................ 0 0
Common stock, $0.015 par value, 35,000,000 shares
authorized; 12,890,346 and 12,793,373 shares issued ................ 193,000 192,000
Additional paid-in capital ........................................... 3,147,000 1,760,000
Retained earnings .................................................... 102,240,000 78,472,000
Accumulated other comprehensive income (loss) ........................ 26,000 (126,000)
Treasury stock, 155,351 and no shares, at cost ....................... (3,866,000) 0
------------- -------------
Stockholders' equity - net ...................................... 101,740,000 80,298,000
------------- -------------
$ 135,444,000 $ 104,900,000
============= =============
See accompanying notes to consolidated financial statements.
38
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999
----------- ----------- -----------
REVENUES
Oil and gas sales ............................................ $44,548,000 $44,437,000 $20,644,000
Gains on derivative instruments, net ......................... 6,435,000 0 0
Oilfield services ............................................ 8,090,000 6,278,000 4,974,000
Trading revenues ............................................. 0 0 2,318,000
Interest, dividend and other income .......................... 1,214,000 1,464,000 1,286,000
----------- ----------- -----------
60,287,000 52,179,000 29,222,000
----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ........................ 9,190,000 6,150,000 4,650,000
Depreciation of property and equipment ..................... 1,369,000 1,054,000 817,000
Lease operating expense ...................................... 3,295,000 2,623,000 2,012,000
Ad valorem and production taxes .............................. 3,344,000 3,421,000 1,765,000
Oilfield services ............................................ 5,482,000 4,585,000 3,377,000
General and administrative ................................... 3,559,000 2,916,000 1,712,000
Impairment of natural gas swap ............................... 241,000 0 0
Cost of trading .............................................. 0 0 2,827,000
----------- ----------- -----------
26,480,000 20,749,000 17,160,000
----------- ----------- -----------
Income Before Income Taxes and Cumulative Effect
of Change in Accounting Principle .......................... 33,807,000 31,430,000 12,062,000
Provision for Income Taxes ................................... 10,650,000 9,535,000 3,035,000
----------- ----------- -----------
Net Income Before Cumulative Effect of Change in
Accounting Principle ....................................... 23,157,000 21,895,000 9,027,000
Cumulative Effect of Change in Accounting Principle (net
of income taxes of $265,000) ................................. 611,000 0 0
----------- ----------- -----------
NET INCOME ................................................... $23,768,000 $21,895,000 $ 9,027,000
=========== =========== ===========
Basic Net Income per Share Before Cumulative Effect
of Change in Accounting Principle .......................... $ 1.82 $ 1.72 $ 0.70
Cumulative Effect of Change in Accounting Principle .......... 0.05 0.00 0.00
----------- ----------- -----------
BASIC NET INCOME PER SHARE ................................... $ 1.87 $ 1.72 $ 0.70
=========== =========== ===========
Diluted Net Income per Share Before Cumulative Effect
of Change in Accounting Principle .......................... $ 1.75 $ 1.65 $ 0.69
Cumulative Effect of Change in Accounting Principle .......... 0.05 0.00 0.00
----------- ----------- -----------
DILUTED NET INCOME PER SHARE ................................. $ 1.80 $ 1.65 $ 0.69
=========== =========== ===========
See accompanying notes to consolidated financial statements.
39
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999
------------ ------------ ------------
Net income .................................................. $ 23,768,000 $ 21,895,000 $ 9,027,000
------------ ------------ ------------
Other comprehensive income:
Change in fair value of hedges .............................. 3,475,000 0 0
Reclassification adjustment for realized gains on hedges
included in net income .................................... (3,381,000) 0 0
Deferred income tax expense related to change in fair
value of hedges ........................................... (35,000) 0 0
Change in fair value of available-for-sale securities ....... 147,000 170,000 (551,000)
Reclassification adjustment for realized losses included
in net income ............................................. 1,000 18,000 81,000
Deferred income tax (expense) benefit related to change
in fair value of available-for-sale securities ............ (55,000) (70,000) 175,000
------------ ------------ ------------
152,000 118,000 (295,000)
------------ ------------ ------------
COMPREHENSIVE INCOME ........................................ $ 23,920,000 $ 22,013,000 $ 8,732,000
============ ============ ============
See accompanying notes to consolidated financial statements.
40
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Treasury
Stock Capital Earnings Income (Loss) Stock Total
-------- ----------- ------------- ------------- ----------- ------------
BALANCES, January 1, 1999 ............. $196,000 $ 4,308,000 $ 47,550,000 $ 51,000 $ (797,000) $ 51,308,000
Net income ............................ 9,027,000 9,027,000
Exercise of stock options ............. 2,000 843,000 845,000
Tax benefit from exercise of non-
qualified stock options ............. 477,000 477,000
Other comprehensive income ............ (295,000) (295,000)
Treasury stock purchased .............. (2,454,000) (2,454,000)
-------- ----------- ------------- ---------- ----------- ------------
BALANCES, December 31, 1999 ........... 198,000 5,628,000 56,577,000 (244,000) (3,251,000) 58,908,000
Net income ............................ 21,895,000 21,895,000
Exercise of stock options ............. 1,000 591,000 592,000
Tax benefit from exercise of non-
qualified stock options ............. 720,000 720,000
Other comprehensive income ............ 118,000 118,000
Treasury stock purchased .............. (1,935,000) (1,935,000)
Treasury stock canceled ............... (7,000) (5,179,000) 5,186,000 0
-------- ----------- ------------- ---------- ----------- ------------
BALANCES, December 31, 2000 ........... 192,000 1,760,000 78,472,000 (126,000) 0 80,298,000
Net income ............................ 23,768,000 23,768,000
Exercise of stock options ............. 1,000 525,000 526,000
Tax benefit from exercise of non-
qualified stock options ............. 732,000 732,000
Other comprehensive income ............ 152,000 152,000
Treasury stock purchased .............. (3,866,000) (3,866,000)
Other ................................. 130,000 130,000
-------- ----------- ------------- ---------- ----------- ------------
BALANCES, December 31, 2001 ........... $193,000 $ 3,147,000 $ 102,240,000 $ 26,000 $(3,866,000) $101,740,000
======== =========== ============= ========== =========== ============
See accompanying notes to consolidated financial statements.
41
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
2001 2000 1999
------------ ------------ ------------
OPERATING ACTIVITIES
Net income .................................................. $ 23,768,000 $ 21,895,000 $ 9,027,000
Adjustments to reconcile net income to net cash
provided by operating activities ............................
Depreciation, depletion and amortization ................. 10,559,000 7,204,000 5,467,000
Deferred income taxes .................................... 9,123,000 7,319,000 2,281,000
Unrealized derivative activities ......................... (4,378,000)
Current taxes from sale of oil and gas properties ........ 0 0 (5,704,000)
0
Other .................................................... 626,000 745,000 551,000
Changes in operating assets and liabilities:
Receivables ........................................... 3,096,000 (3,618,000) (588,000)
Inventory ............................................. (6,000) (572,000) (225,000)
Other current assets .................................. 241,000 (129,000) (374,000)
Accounts payable and payables to owners ............... (2,130,000) 2,124,000 489,000
Production taxes payable .............................. 1,504,000 2,344,000 86,000
Accrued and other liabilities ......................... 605,000 (936,000) 996,000
------------ ------------ ------------
Net cash provided by operating activities ........... 43,008,000 36,376,000 12,006,000
------------ ------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties ......................... (35,248,000) (31,952,000) (18,617,000)
Purchases of other properties ............................... (1,958,000) (1,613,000) (2,673,000)
Purchases of securities ..................................... (125,000) (249,000) (497,000)
Proceeds from sales of property ............................. 435,000 280,000 27,871,000
------------ ------------ ------------
Net cash provided by (used in) investing activities ...... (36,896,000) (33,534,000) 6,084,000
------------ ------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased .................................... (3,866,000) (1,935,000) (2,454,000)
Proceeds from exercise of stock options ..................... 526,000 592,000 845,000
Other ....................................................... 183,000 0 (120,000)
------------ ------------ ------------
Net cash used in financing activities .................... (3,157,000) (1,343,000) (1,729,000)
------------ ------------ ------------
Increase in cash and cash equivalents ....................... 2,955,000 1,499,000 16,361,000
Cash and cash equivalents, beginning of year ................ 20,382,000 18,883,000 2,522,000
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year ...................... $ 23,337,000 $ 20,382,000 $ 18,883,000
============ ============ ============
See accompanying notes to consolidated financial statements.
42
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
Prima Energy Corporation ("Prima") is an independent oil and gas
company primarily engaged in the exploration for, and the acquisition,
development and production of, crude oil and natural gas. Through its wholly
owned subsidiaries, Prima is also engaged in oil and gas property operations,
oilfield services and natural gas gathering, marketing and trading. Prima's
current activities are conducted principally in the Rocky Mountain region of the
United States.
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the
accounts of Prima and its wholly owned subsidiaries, herein collectively
referred to as the "Company." The Company's proportionate share of capital
expenditures, production revenue and operating expenses from working interests
in oil and gas properties is included in the consolidated financial statements.
All significant intercompany transactions have been eliminated. Certain amounts
in prior years have been reclassified to conform with the classifications at
December 31, 2001.
USE OF ESTIMATES
The preparation of the financial statements of the Company in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from these estimates.
COMPREHENSIVE INCOME
Comprehensive income consists of net income and unrealized gains and
losses on marketable equity securities held for sale and the effective component
of derivative instruments classified as cash flow hedges, net of tax.
Comprehensive income is presented in the consolidated statements of
stockholders' equity and comprehensive income.
CONSOLIDATED STATEMENTS OF CASH FLOWS
Cash in excess of daily requirements is invested in money market
accounts and commercial paper with maturities of three months or less. Such
investments are deemed to be cash equivalents for purposes of the consolidated
financial statements.
Supplemental disclosures of cash flow information:
Cash paid for income taxes was $905,000, $2,722,000 and $4,725,000 for
the years ended December 31, 2001, 2000 and 1999, respectively. Cash paid for
interest in 2000 and 1999 was $15,000 and $37,000, respectively. No amounts were
paid for interest in 2001.
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets for $ 460,000 in March
1999. A summary of the transaction is as follows:
Fair value of assets acquired .............................. $460,000
Cash paid .................................................. 276,000
-------
Note payable issued to seller .............................. $184,000
========
43
ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS AND AVAILABLE FOR SALE SECURITIES
Cash in excess of daily requirements is invested in money market
accounts and commercial paper with maturities of three months or less. The
carrying amount of cash equivalents approximates fair value because of the short
maturity and high credit quality of those investments.
The Company classifies marketable securities as "available for sale,"
states them at market value and reports unrealized gains and losses, net of
deferred income taxes, as an adjustment to stockholders' equity. Available for
sale securities are readily marketable and available for use in the Company's
operations should the need arise. Therefore, the Company has classified its
portfolio as a current asset. Realized gains and losses are determined on the
specific identification method.
Commencing with its adoption of Statement of Financial Accounting
Standards No. 133 on January 1, 2001 (see Note 4), the Company has recognized
all derivatives on its balance sheet at their estimated fair values. The fair
values of these contracts are determined based on various factors, including
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, but the Company had
no such positions during 2001. Substantially all of the Company's derivatives
transactions are settled based upon reported settlement prices on the NYMEX or
as quoted in relatively liquid over-the-counter markets by a number of market
makers.
INVENTORY
Inventory consists of various tubular goods and surface production
facility equipment intended to be used in the Company's oil and gas operations
and is stated at the lower of cost or market value using the first-in, first-out
valuation method.
OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for oil and
gas activities. Under this method, all costs associated with property
acquisition, exploration and development, including costs of unsuccessful
exploration, are capitalized within a cost center. The Company's oil and gas
properties are all located within the United States, which constitutes one cost
center. No gain or loss is recognized upon the sale or abandonment of
undeveloped or producing oil and gas properties unless the sale represents a
significant portion of oil and gas properties and the gain significantly alters
the relationship between capitalized costs and proved oil and gas reserves of
the cost center. Depreciation, depletion and amortization of oil and gas
properties is computed on the units of production method based on proved
reserves. Amortizable costs include estimates of future development costs of
proved undeveloped reserves. The Company invests in unevaluated oil and gas
properties for the purpose of future exploration for proved reserves. The costs
of such assets are included in unproved oil and gas properties at the lower of
cost or estimated fair market value and are not subject to amortization.
Capitalized costs of oil and gas properties may not exceed an amount
equal to the present value, discounted at 10%, of the estimated future net cash
flows from proved oil and gas reserves plus the cost, or estimated fair market
value if lower, of unproved properties. Should capitalized costs exceed this
ceiling, an impairment is recognized. The present value of estimated future net
cash flows is computed by applying prices of oil and natural gas as of the
balance sheet date of the calculation to estimated future production of proved
oil and gas reserves as of such date, less estimated future expenditures to be
incurred in developing and producing the proved reserves and assuming
continuation of existing economic conditions. The Company did not recognize any
impairment losses during the three-year period ended December 31, 2001.
The Company does not accrue costs for future site restoration,
dismantlement and abandonment costs related to proved oil and gas properties
because the Company estimates that such costs will be offset by the salvage
value of equipment sold upon abandonment of such properties. The Company's
estimates are based upon its historical experience and upon review of its
current properties and restoration obligations.
44
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Renewals and betterments
that substantially extend the useful lives of the assets are capitalized.
Maintenance and repairs are expensed when incurred. Depreciation is provided
using the straight-line method over the estimated useful lives of the assets,
ranging from three to 15 years. Long-lived assets, other than oil and gas
properties, are evaluated for impairment to determine if current circumstances
and market conditions indicate the carrying amount may not be recoverable. The
Company did not recognize any impairment losses during the three-year period
ended December 31, 2001.
NATURAL GAS REVENUES
The Company utilizes the accrual method of accounting for natural gas
revenues whereby revenues are recognized as the Company's entitlement share of
gas is produced based on its net revenue interests in the properties. The
Company records a receivable (payable) to the extent it receives less (more)
than its proportionate share of gas revenues. At December 31, 2001, the
imbalance position was not significant.
OILFIELD SERVICES AND OPERATOR FEES
Fees earned from providing oilfield services and operating wells for
third parties are recorded when the services are performed. Oilfield services
fees are recognized as income. Operating fees are recorded as a reduction of
general and administrative expenses.
INCOME TAXES
Income taxes are provided for the tax effects of transactions reported
in the financial statements and consist of taxes currently payable plus deferred
income taxes related to certain income and expenses recognized in different
periods for financial and income tax reporting purposes. The deferred income tax
assets and liabilities represent the future tax return consequences of those
differences, which will either be taxable or deductible when the assets and
liabilities are recovered or settled. Deferred income taxes are also recognized
for tax credits that are available to offset future federal income taxes.
Deferred income taxes are measured by applying currently enacted tax rates.
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
The Company periodically enters into derivative contracts to mitigate
risks associated with downward price movements in benchmark NYMEX gas and oil
prices or, in the case of basis swaps, to protect the Company from increases in
the differential between NYMEX and Rocky Mountain gas prices. The Company's
derivatives contracts generally represent cash flow hedges that are determined
to be qualifying or non-qualifying for hedge accounting treatment in accordance
with the provisions of Statement of Financial Accounting Standards No. 133,
"Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133").
SFAS 133 prescribes that the fair value of all derivatives should be
recognized as either assets or liabilities in the statement of financial
position. SFAS 133 also establishes requirements for designation and
documentation of hedging relationships and ongoing effectiveness assessments.
Hedge effectiveness is measured based on the relative changes over time in the
fair values of a derivative and the related hedged item. If a cash flow hedge
qualifies for hedge accounting under SFAS 133, and is so designated by the
Company, changes in the fair value of the derivative are recorded initially in
other comprehensive income and then recognized in the income statement when the
hedged item affects earnings. If a cash flow hedge does not qualify for hedge
accounting under SFAS 133, or if the Company so elects, changes in the fair
value of the derivative are immediately recognized in earnings. The Company
generally elects to use hedge accounting when conditions to do so are satisfied.
The Company has determined that pursuant to SFAS 133 requirements, and
based on its current sources of oil and gas production, swaps, collars, puts or
floors that are based on NYMEX oil prices or CIG gas prices qualify as cash flow
hedges. Derivatives based on NYMEX gas prices will not so qualify unless the
Company has entered into corresponding transactions to hedge basis differentials
between NYMEX and CIG indices. In addition, stand-alone basis differential swaps
and sales of call options do not qualify for hedge accounting.
45
The adoption of SFAS 133 as of January 1, 2001 resulted in the
recognition of a current asset of $1,241,000, a current liability of $549,000,
and net-of-tax cumulative effect adjustments reducing other comprehensive income
by $129,000 and increasing net income by $611,000. The $611,000 is reflected as
the cumulative effect of a change in accounting principle in the December 31,
2001 financial statements.
EARNINGS PER SHARE
Basic net income per share is computed by dividing net income by the
weighted average common shares outstanding during the period. Diluted net income
per share includes the potential dilution that could occur upon exercise of the
options to acquire common stock described in Note 10, computed using the
treasury stock method. The treasury stock method assumes that the increase in
the number of shares issued is reduced by the number of shares which could have
been repurchased by the Company with the proceeds from the exercise of the
options (which were assumed to have been at the average market price of the
common shares during the reporting period).
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standard ("SFAS") No. 141, "Business
Combinations." SFAS No. 141 is intended to improve the transparency of the
accounting and reporting for business combinations by requiring that all
business combinations be accounted for under a single method, the purchase
method. This statement is effective for all business combinations initiated
after June 30, 2001. Management does not believe the adoption of this statement
will have a material effect on the Company's financial position or results of
operations.
In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets." This statement applies to intangibles and goodwill acquired
after June 30, 2001, as well as goodwill and intangibles previously acquired.
Under this statement, goodwill as well as other intangibles determined to have
an infinite life will no longer be amortized. These assets will be reviewed for
impairment on a periodic basis. This statement is effective for the Company in
the first quarter of 2002. Management does not believe the adoption of this
statement will have a material effect on the Company's financial position or
results of operations.
In August 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations." SFAS No. 143 provides the accounting requirements for
retirement obligations associated with long-lived assets and requires the fair
value of a liability for an asset retirement obligation be recognized in the
period in which it is incurred if a reasonable estimate of fair value can be
made. The associated asset retirement costs are capitalized as part of the
carrying costs of the asset. SFAS No. 143 is effective for fiscal years
beginning after June 15, 2002, and early adoption is permitted. The Company is
currently assessing, but has not yet determined, the impact of SFAS No. 143 on
its consolidated results of operations, cash flows or financial position.
In October 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that
long-lived assets be measured at the lower of carrying amount or fair value less
costs to sell, whether reported in continuing operations or in discontinued
operations. Therefore, discontinued operations will no longer be measured at net
realizable value or include amounts for operating losses that have not yet
occurred. SFAS No. 144 is effective for financial statements issued for fiscal
years beginning after December 15, 2001 and generally is to be applied
prospectively. Management does not believe the adoption of this statement will
have a material effect on the Company's financial position or results of
operations.
2. AVAILABLE FOR SALE SECURITIES
The Company's available for sale securities are comprised of
marketable equity securities, including closed-end bond funds. For the years
ended December 31, 2001 and 2000, the Company sold securities with a market
value of $166,000 and $57,000 which resulted in realized losses of $1,000 and
$18,000, respectively. The net unrealized gain or loss on securities at December
31, 2001 and 2000 is included in accumulated other comprehensive income, net of
46
deferred income taxes of $(20,000) and $(75,000), respectively. The change in
net unrealized gain or loss on securities for the years ended December 31, 2001
and 2000 was as follows:
2001 2000
--------- ---------
Net unrealized gain (loss), beginning of year ....................... $(201,000) $(389,000)
Net unrealized gain (loss), end of year ............................. (53,000) (201,000)
--------- ---------
Net change in unrealized gain or loss ............................... $ 148,000 $ 188,000
========= =========
The components of fair value as of December 31, 2001 and 2000 were as follows:
2001 2000
---------- ----------
Cost (including reinvested distributions) ........................... $ 2,471,000 $ 2,512,000
Gross unrealized gains .............................................. 88,000 43,000
Gross unrealized losses ............................................. (141,000) (244,000)
----------- -----------
Fair value .......................................................... $ 2,418,000 $ 2,311,000
=========== ===========
3. EARNINGS PER SHARE AND COMMON STOCK
The following table reconciles the numerator and denominator used in
the calculation of basic and diluted net income per share.
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ---------- -----------
Year Ended December 31, 2001:
Basic Net Income per Share ............................. $23,768,000 12,731,181 $ 1.87
Effect of Stock Options ................................ 0 487,970 ===========
----------- ----------
Diluted Net Income per Share ........................... $23,768,000 13,219,151 $ 1.80
=========== ========== ===========
Year Ended December 31, 2000:
Basic Net Income per Share ............................. $21,895,000 12,748,917 $ 1.72
Effect of Stock Options ................................ 0 544,006 ===========
----------- ----------
Diluted Net Income per Share ........................... $21,895,000 13,292,923 $ 1.65
=========== ========== ===========
Year Ended December 31, 1999:
Basic Net Income per Share ............................. $ 9,027,000 12,854,196 $ 0.70
Effect of Stock Options ................................ 0 282,647 ===========
----------- ----------
Diluted Net Income per Share ........................... $ 9,027,000 13,136,843 $ 0.69
=========== ========== ===========
The Board of Directors of Prima approved two separate three for two
stock splits of the Company's common stock during 2000. All share and per share
amounts included in these financial statements have been restated to show the
retroactive effects of the stock splits.
During 2000, the Company purchased 108,150 shares of its common stock
for its treasury for $1,935,000. The Board of Directors authorized the
retirement of 431,199 shares of common stock held in the treasury as of December
31, 2000. These shares were returned to an authorized but unissued status. In
January 2001, the Board approved a repurchase program of up to 5% of the
Company's common stock then outstanding, or approximately 640,000 shares. In
2001, the Company purchased 155,351 treasury shares for $3,866,000. This
represents approximately 1.2% of the shares then outstanding, or 24% of the
shares authorized under the repurchase program.
47
During 2000, the shareholders of Prima approved an increase in the
number of authorized shares of common stock from 12,000,000 to 18,000,000
shares. During 2001, the shareholders approved an additional increase to
35,000,000 authorized shares.
4. DERIVATIVE ACTIVITIES
Crude oil and natural gas futures, options and swaps, and basis swaps,
are used from time to time in order to hedge the price of a portion of the
Company's production and to lock in the basis from NYMEX to the Rocky Mountains.
These cash flow hedging derivatives are entered into to mitigate the risk of
fluctuating oil and natural gas prices and fluctuating basis differentials,
which can adversely affect operating results. The Company uses only conventional
derivative instruments and attempts to manage its credit risk by entering into
derivative contracts only with financial institutions that are believed to be
reputable and which carry an investment grade rating. While such hedges can
reduce the adverse effects of oil and gas price declines, they may also limit
the benefits of price increases.
The Company has entered into various cash flow hedges related to its
oil and gas production. Some of these derivatives qualify for hedge accounting,
while others are non-qualifying. The following table summarizes the income
statement effects of these transactions in 2001, 2000 and 1999:
2001 2000 1999
---------- ---------- ----------
Realized gains (losses) on derivatives qualifying for
hedge accounting, included in oil and gas sales ........... $3,381,000 $ 42,000 $ (180,000)
Realized gains on non-qualifying hedges ..................... 2,057,000 -- --
Unrealized gains on non-qualifying hedges ................... 4,378,000 -- --
---------- ---------- ----------
Aggregate amounts reported on consolidated
statements of income ...................................... $9,816,000 $ 42,000 $ (180,000)
========== ========== ==========
In addition, the Company had $94,000 of unrealized mark-to-market gains
as of December 31, 2001 on derivatives qualifying for hedge accounting, which
amount has been included in other comprehensive income for 2001. The realized
gains on derivatives that qualified for hedge accounting, which were included in
oil and gas sales, related to approximately 24%, 1% and 15% of the Company's
natural gas production in 2001, 2000 and 1999, respectively, and 19%, 5% and
25%, respectively, of its oil production for the same three years.
As of December 31, 2001, the Company had recorded a current asset of
$4,472,000, representing the aggregate unrealized mark-to-market gains for its
open derivative positions, which are summarized below:
Market Total Volumes Contract Unrealized
Time Period Index (MMBtu) Price Gains
----------- ------ ------------ -------- ----------
Natural Gas Futures
January 1 - March 31, 2002 .................... NYMEX 1,900,000 3.6201 $ 1,935,000
April 1 - June 30, 2002 ....................... NYMEX 2,300,000 3.1525 1,089,000
July 1 - September 30, 2002 ................... NYMEX 2,100,000 3.2136 892,000
October 1 - December 31, 2002 ................. NYMEX 1,000,000 3.3076 393,000
January 1 - February 28, 2003 ................. NYMEX 300,000 3.6300 103,000
Natural Gas Basis Swaps
November - December, 2002 ..................... NYMEX/CIG 600,000 0.3400 24,000
January 1, 2003 - March 31, 2003 ............. NYMEX/CIG 900,000 0.3400 36,000
-----------
Total Unrealized Gains ............................. $ 4,472,000
===========
Oil and gas prices are volatile and the market value of these
derivatives will change as the underlying commodity futures prices change.
Mark-to-market adjustments could result in significant earnings volatility. The
actual gains or
48
losses realized will depend on the applicable futures prices in effect at the
time such positions expire or are closed. The table above excludes commodity
positions with Enron North America Corp, which filed for bankruptcy protection
in December 2001. Prima's unrealized gain on derivatives due from Enron totaled
approximately $241,000 when the Company terminated the contract under default
provisions in the agreement. Although this amount was reflected in gains on
derivative instruments in 2001, the full amount was reserved for and reflected
as an impairment expense in the same period.
5. INCOME TAXES
The provision for income taxes consists of the following components:
2001 2000 1999
------------ ------------ ------------
Current:
Federal ................................................ $ 2,067,000 $ 2,114,000 $ 5,340,000
State .................................................. (275,000) 102,000 1,118,000
------------ ------------ ------------
1,792,000 2,216,000 6,458,000
------------ ------------ ------------
Deferred:
Federal ................................................ 8,732,000 6,656,000 (4,828,000)
State .................................................. 782,000 382,000 (652,000)
------------ ------------ ------------
9,514,000 7,038,000 (5,480,000)
------------ ------------ ------------
Tax credits ................................................. (391,000) 281,000 2,057,000
------------ ------------ ------------
Provision for income taxes .................................. $ 10,915,000 $ 9,535,000 $ 3,035,000
============ ============ ============
The provision for income taxes includes $265,000 of current expense
that was netted in the cumulative effect of change in accounting method. During
2001, 2000 and 1999, the Company recognized income tax deductions of $1,979,000,
$1,946,000 and $1,247,000, respectively, from the exercise of nonqualified stock
options. Stockholders' equity has been credited in the amount of $732,000,
$720,000 and $477,000 for the income tax benefit of these deductions. During
2001, the Company recognized taxable income of $207,000 from short-swing
profits. Stockholders' equity has been reduced in the amount of $77,000 for the
current income tax expense associated with this income.
The significant components of deferred tax assets and liabilities
included in the balance sheet are as follows:
2001 2000
----------- -----------
Deferred Tax Assets:
Minimum tax credit carryforwards ................................... $ 1,727,000 $ 1,336,000
State income taxes ................................................. 663,000 395,000
Other .............................................................. 68,000 109,000
----------- -----------
Total Deferred Tax Assets .......................................... 2,458,000 1,840,000
----------- -----------
Deferred Tax Liabilities :
Intangible drilling costs .......................................... 21,259,000 13,916,000
Derivatives ........................................................ 1,655,000 0
Depreciation ....................................................... 641,000 492,000
Land held for investment ........................................... 370,000 0
Other .............................................................. 677,000 362,000
----------- -----------
Total Deferred Tax Liabilities ..................................... 24,602,000 14,770,000
----------- -----------
Net Deferred Tax Liabilities (including current component of
$1,778,000 in 2001) ................................................ $22,144,000 $12,930,000
=========== ===========
49
A reconciliation of income tax computed at the federal statutory tax
rate to the Company's effective tax rate is as follows:
2001 2000 1999
---- ---- ----
Federal statutory income tax rate ........................... 34.0% 34.0% 34.0%
Percentage depletion ........................................ (1.2) (1.5) (2.2)
Section 29 credits .......................................... (3.0) (3.1) (10.5)
State taxes, net of federal benefits ........................ 1.0 1.0 2.6
Other ....................................................... 0.7 (0.1) 1.3
---- ---- ----
Effective tax rate ...................................... 31.5% 30.3% 25.2%
==== ==== ====
At December 31, 2001, the Company had minimum tax credit carryforwards
of approximately $1,727,000, which may by carried forward indefinitely.
6. SEGMENT INFORMATION
The Company organizes its activities in operating segments that
consist of 1) the acquisition, exploration, development and operation of oil and
gas properties and the development, production and sale of oil and natural gas,
2) providing oil field services for wells which it operates and for third
parties and 3) the marketing and trading of third party natural gas (which
activity has not been actively conducted since 1999). The Company's activities
are located primarily in the Rocky Mountain region of the United States, which
is one geographic area.
The information below presents the operating segment data for the
Company on the basis used by management in deciding how to allocate resources
and in assessing performance. The following table sets forth revenues, operating
earnings before income taxes, identifiable assets, depreciation, depletion and
amortization expense and capital expenditures for the years ended December 31,
2001, 2000 and 1999. This information is presented on the basis used by
management, which is the same basis used in the preparation of the Company's
consolidated financial statements.
2001 2000 1999
------------- ------------- -------------
Revenues
Oil & gas (including gains on derivative instruments) ..... $ 50,983,000 $ 44,437,000 $ 20,644,000
Oilfield services ......................................... 12,207,000 9,912,000 6,764,000
Marketing and trading ..................................... 0 0 2,318,000
------------- ------------- -------------
63,190,000 54,349,000 29,726,000
Corporate revenues ........................................ 1,214,000 1,464,000 1,286,000
Intersegment sales ........................................ (4,117,000) (3,634,000) (1,790,000)
------------- ------------- -------------
Per financial statements ............................... $ 60,287,000 $ 52,179,000 $ 29,222,000
============= ============= =============
Operating Earnings
Oil & gas (including gains on derivative instruments) ..... $ 34,913,000 $ 32,243,000 $ 12,217,000
Oilfield services ......................................... 2,083,000 844,000 984,000
Marketing and trading ..................................... 0 0 (511,000)
------------- ------------- -------------
36,996,000 33,087,000 12,690,000
Corporate earnings ........................................ (3,189,000) (1,657,000) (628,000)
------------- ------------- -------------
Per financial statements ............................... $ 33,807,000 $ 31,430,000 $ 12,062,000
============= ============= =============
Identifiable Assets
Oil & gas ................................................. $ 100,200,000 $ 72,747,000 $ 44,321,000
Oilfield services ......................................... 7,218,000 6,044,000 6,184,000
------------- ------------- -------------
107,418,000 78,791,000 50,505,000
Corporate assets .......................................... 28,026,000 26,109,000 22,160,000
------------- ------------- -------------
Per financial statements ............................... $ 135,444,000 $ 104,900,000 $ 72,665,000
============= ============= =============
50
2001 2000 1999
------------- ------------- -------------
Depreciation, Depletion and Amortization Expense
Oil and gas ............................................... $ 9,190,000 $ 6,150,000 $ 4,650,000
Oilfield services ......................................... 1,284,000 982,000 750,000
------------- ------------- -------------
10,474,000 7,132,000 5,400,000
Corporate ................................................. 85,000 72,000 67,000
------------- ------------- -------------
Per financial statements ............................... $ 10,559,000 $ 7,204,000 $ 5,467,000
============= ============= =============
Capital Expenditures
Oil and gas ............................................... $ 35,248,000 $ 31,952,000 $ 18,617,000
Oilfield services ......................................... 1,866,000 1,524,000 2,819,000
------------- ------------- -------------
37,114,000 33,476,000 21,436,000
Corporate ................................................. 92,000 89,000 38,000
------------- ------------- -------------
Per financial statements ............................... $ 37,206,000 $ 33,565,000 $ 21,474,000
============= ============= =============
Total revenue by operating segment includes both sales to unaffiliated
customers, as reported in the Company's consolidated income statement, and
intersegment sales, which are oilfield services provided to Company-owned wells,
which are eliminated in consolidation. Oilfield services revenue is priced and
accounted for consistently for both unaffiliated and intersegment sales.
Identifiable assets by operating segment are those assets that are
used in the Company's operations in each segment. Corporate assets are
principally cash, cash equivalents and available for sale securities.
Following is a table summarizing the percentage of sales made to each
customer that accounted for over 10% of the Company's consolidated revenues.
Although the loss of any of these customers could have a material adverse effect
on the Company, the Company believes it would be able to locate other customers
for the purchase of its production and may be able to secure additional
marketing opportunities.
2001 2000 1999
---- ---- ----
Oil and Gas:
Duke Energy Field Services, Inc. .......................... 31% 36% 28%
Valero Energy (formerly Ultramar Diamond Shamrock) ........ 16 21 15
7. COMMITMENTS AND CONTINGENCIES
The Company entered into a seven-year office space lease, effective
December 1, 2000. Office lease expense totaled $282,000, $187,000 and $155,000
for the years ended December 31, 2001, 2000 and 1999, respectively. Future
minimum annual rentals under the non-cancelable operating lease for the
remainder of the seven-year term are as follows:
Year ending December 31, 2002 ................................................. $ 285,000
Year ending December 31, 2003 ................................................. 288,000
Year ending December 31, 2004 ................................................. 317,000
Year ending December 31, 2005 ................................................. 317,000
Year ending December 31, 2006 ................................................. 317,000
Year ending December 31, 2007 ................................................. 290,000
----------
$1,814,000
==========
From time to time the Company may be involved in litigation that
arises in the normal course of business operations. As of the date of this
report, the Company is not a party to any litigation that it believes could
reasonably be expected to have a material adverse effect on the business or
results of operations.
51
8. BENEFIT PLANS
EMPLOYEE STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan and the
Prima Energy Corporation 2001 Stock Incentive Plan, 2,650,000 shares of Prima's
common stock are reserved for issuance to key employees at fair market value on
the date of grant. Options granted to date under the plan vest ratably over
three to five years, and expire ten years from the date of grant. At December
31, 2001, options to acquire 1,037,950 shares of the Company's common stock were
outstanding. The exercise prices, which equaled the market price of the stock on
the date of grant, range from $3.93 to $33.25 per share, with a weighted average
price of $11.14 per share. No options were granted in 2000. As of December 31,
2001, the weighted average remaining contractual life of the options outstanding
is 5 years, 4 months. A summary of options granted, exercised and outstanding
during the three years ended December 31, 2001 is as follows:
Number Weighted Average
of Shares Exercise Prices
--------- ---------------
Balance at December 31, 1998 ........................................ 1,182,375 $ 5.15
Granted during 1999 ................................................. 30,375 9.39
Exercised ........................................................... (208,125) 4.06
---------
Outstanding at December 31, 1999 .................................... 1,004,625 5.50
Exercised in 2000 ................................................... (92,650) 5.62
---------
Outstanding at December 31, 2000 .................................... 911,975 5.57
Granted during 2001 ................................................. 216,000 32.55
Exercised ........................................................... (86,425) 5.26
Forfeited ........................................................... (3,600) 14.08
---------
Outstanding at December 31, 2001 .................................... 1,037,950 11.14
=========
Exercisable at December 31, 1999 .................................... 622,350 4.48
Exercisable at December 31, 2000 .................................... 654,125 4.70
Exercisable at December 31, 2001 .................................... 652,225 5.03
NON-EMPLOYEE DIRECTORS' STOCK OPTION PLAN
Under the Prima Energy Corporation Non-Employee Directors' Stock
Option Plan 225,000 shares of Prima's common stock are reserved for issuance to
non-employee directors at fair market value on the date of grant of a stock
option. Upon the effective date of the plan, or upon election as a non-employee
director, 22,500 options are granted each non-employee director. On each
anniversary date of the initial grant, an additional 5,625 options are granted
to each non-employee director for as long as they continue to serve on the
Board. Options vest ratably over five years, and expire ten years from the date
of grant. At December 31, 2001, options to acquire 135,000 shares of the
Company's common stock were outstanding under the plan, at exercise prices
ranging from $6.67 to $32.33 per share. As of December 31, 2001, the weighted
average remaining contractual life of the options outstanding is eight years. A
summary of options granted, exercised and outstanding during the three years
ended December 31, 2001 is as follows:
52
Number Weighted Average
of Shares Exercise Prices
--------- ---------------
Balance at December 31, 1998 ........................................ 90,000 $ 6.67
Granted during 1999 ................................................. 22,500 9.83
--------
Outstanding at December 31, 1999 .................................... 112,500 7.30
Granted during 2000 ................................................. 61,875 24.96
Exercised during 2000 ............................................... (4,500) 6.67
Forfeited during 2000 .............................................. (23,625) 7.42
--------
Outstanding at December 31, 2000 .................................... 146,250 14.77
Granted during 2001 ................................................ 22,500 25.45
Exercised during 2001 ............................................... (10,125) 7.02
Forfeited during 2001 .............................................. (23,625) 7.46
--------
Outstanding at December 31, 2001 .................................... 135,000 18.15
========
Exercisable at December 31, 1999 .................................... 18,000 6.67
Exercisable at December 31, 2000 .................................... 30,375 7.02
Exercisable at December 31, 2001 .................................... 42,750 12.26
SUMMARY OF OUTSTANDING OPTIONS
The following table summarizes information about stock options outstanding at
December 31, 2001 on a combined basis for the employee and non-employee
directors' plans:
Stock Options Outstanding Stock Options Exercisable
----------------------------------------------------- ----------------------------------
Weighted-
Number Average Weighted- Number Weighted-
Range of Outstanding at Remaining Average Exercisable at Average
Share Prices 12/31/01 Contractual Life Exercise Price 12/31/01 Exercise Price
------------ -------------- ---------------- -------------- -------------- --------------
$ 3.93 - 4.41 476,750 2.4 $4.14 476,750 $4.14
6.67 - 9.83 401,450 6.7 7.26 206,375 7.06
21.75 - 24.75 61,875 8.8 23.08 9,000 22.75
29.90 - 33.25 232,875 9.2 32.46 2,850 32.08
--------- -------
1,172,950 5.5 11.83 694,975 5.36
========= =======
RECOGNITION OF COMPENSATION EXPENSE
Prima has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"). Accordingly, no compensation costs have been
recognized for the Employee Stock Option Plan or the Non-Employee Directors'
Stock Option Plan. For disclosure purposes, the fair value of options is
measured at the date of grant using the Black-Scholes option valuation model,
which was developed for use in estimating the fair value of traded options that
have no vesting restrictions and are fully transferable. Such option valuation
models also require the input of highly subjective assumptions, including the
projected life of the options and expected stock price volatility. Because the
Company's employee and directors' stock options have characteristics
significantly different from those of traded options, and because changes in the
subjective input assumptions can materially affect the estimated fair value,
these valuation models do not necessarily provide a reliable measure of the fair
value of such stock options.
53
The following assumptions were utilized to estimate the fair values on
the dates of grant of options issued during the three years ended December 31,
2001, using the Black-Scholes Valuation Model:
2001 2000 1999
---- ---- ----
Expected dividend yield ..................................... 0% 0% 0%
Expected price volatility ................................... 43% 76% 37%
Risk free interest rate ..................................... 5.1% 6.1% 6.8%
Expected life of options (in years) ......................... 6 9 9
Based on the above, the estimated weighted average fair values of
employee stock options granted during 2001 and 1999 were $16.04 and $5.54,
respectively. No employee stock options were granted in 2000. The weighted
average fair values of non-employee directors' options granted during 2001, 2000
and 1999 were $12.49, $20.47 and $5.54, respectively.
For purposes of pro forma disclosures, the estimated fair values of
option grants are amortized to expense over the options' vesting periods. Had
compensation expense been determined based on the estimated fair values at the
grant dates for options awarded through December 31, 2001, consistent with the
provisions of SFAS 123, the Company's net income and net income per share would
have been adjusted to the pro forma amounts indicated below.
2001 2000 1999
----------- ----------- ----------
Net Income
As reported ........................................... $23,768,000 $21,895,000 $9,027,000
Pro forma ............................................. 23,359,000 21,585,000 8,750,000
Basic net income per share
As reported ........................................... $ 1.87 $ 1.72 $ 0.70
Pro forma ............................................. $ 1.83 $ 1.69 $ 0.68
Diluted net income per share
As reported ........................................... $ 1.80 $ 1.65 $ 0.69
Pro forma ............................................. $ 1.77 $ 1.62 $ 0.67
EMPLOYEE STOCK OWNERSHIP PLAN
The Company has an Employee Stock Ownership Plan ("ESOP"), which is
administered pursuant to a Trust Agreement. The ESOP is qualified under Section
401(a) of the Internal Revenue Code of 1986, as amended, and is for the benefit
of all eligible employees of the Company. Allocations to participants are made
annually as of the last day of the plan's year, September 30, and are allocated
among the participants in proportion to their eligible compensation for the
year. Contributions are payable at a minimum rate of 5% of eligible salaries.
Through September 30, 1993, the ESOP provided for contributions to be made
quarterly and to be used to purchase Prima common stock on the open market.
Effective October 1, 1993, the ESOP was amended to allow fully vested employees
the option to direct the Trustees to diversify a portion of their investments by
selling a limited percent of Prima common stock and investing the proceeds, as
well as their contributions, in various diversified investment options. The ESOP
benefits all full-time employees and provides for vesting in increments over six
years. For the years ended December 31, 2001, 2000 and 1999, the Company
expensed $316,000, $283,000 and $224,000, respectively, of Company contributions
to the Plan.
9. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited
partnership that owns approximately 22 acres of undeveloped land in Phoenix,
Arizona for investment and capital appreciation. The partnership owns the 22
acres free and clear. One of the general partners of the partnership is a
company controlled by a brother of the Company's president. The Company
participated on the same basis as the other limited partners. This transaction
was approved by the disinterested members of the Company's Board of Directors.
The carrying value of this investment at December 31, 2001 and 2000 was
$257,000. During the three years ended December 31, 2001, the Company did not
make any capital contributions to the partnership, nor did it receive any
distributions therefrom.
54
Certain of the Company's directors and officers have participated,
either individually or through entities which they control, in oil and gas
properties in which the Company has an interest. These participations, which
have been on a working interest basis, have been in prospects or properties
originated or acquired by the Company. In some cases, the interests sold to
affiliated and non-affiliated participants were sold on a promoted basis
requiring these participants to pay a disproportionate share of well costs. Each
of the participations by directors and officers has been on terms no less
favorable to the Company than it could have obtained from non-affiliated
participants. It is expected that joint participations with the Company will
continue to occur from time to time in the future. All participations by the
officers and directors have and will continue to be approved by the
disinterested members of the Company's Board of Directors.
At any point in time, there are receivables and payables with officers
and directors that arise in the ordinary course of business as a result of
participations in jointly held oil and gas properties. Amounts due to or from
officers and directors resulting from billings of joint interest costs or
receipts of production revenues on these properties are handled on terms
pursuant to standard industry joint operating agreements which are no more or
less favorable than similar transactions with unrelated parties.
The Company acquired oil and gas leases covering 26,680 net
undeveloped acres in June 2000 from a company controlled by a director of Prima
for a negotiated price of $12 per net acre, or a total of $320,000. Additional
acreage in the same general area were subsequently acquired from this director
at cost. The aggregate amounts paid for these property interests, including the
initial acquisition totaled $290,000 in 2001 and $376,000 in 2000. All leases
acquired were subject to an overriding royalty reserved by the director or
entities controlled by him of 3% or less, depending on the net revenue interest
of the leases, proportionately reduced to the working interest acquired. The
disinterested members of the Board of Directors approved the transactions.
10. SUBSEQUENT EVENT
On March 5, 2002, the Company sold all of its producing wells in the
Stone's Throw CBM project in the northern Powder River Basin, along with
associated gathering system facilities and approximately 35,000 net undeveloped
acres in the Stone's Throw area. Net proceeds from the transaction totaled
$13,539,000 after normal closing adjustments. Approximately $11,746,000 of the
proceeds were closed into an escrow account with a qualified intermediary, to
preserve the opportunity to consummate a tax-free like-kind exchange if suitable
properties to acquire can be identified within 45 days and purchased within six
months. If a tax-free exchange is not consummated, the Company's current income
taxes for 2002 could increase by up to $1,400,000.
11. SUPPLEMENTARY OIL AND GAS INFORMATION
The Company's oil and gas operations are conducted entirely in the
United States, primarily in the Rocky Mountain region. Certain information
concerning these activities follows:
COSTS INCURRED -- Costs incurred in oil and gas property acquisition,
exploration and development activities and related depletion per equivalent
unit-of-production were as follows:
2001 2000 1999
----------- ----------- -----------
Acquisition costs:
Unproved properties .................................... $ 2,114,000 $ 1,741,000 $ 3,347,000
Proved properties ...................................... 400,000 237,000 123,000
Exploration costs ........................................... 1,620,000 642,000 1,731,000
Development costs ........................................... 31,114,000 29,332,000 13,416,000
----------- ----------- -----------
Total .................................................. $35,248,000 $31,952,000 $18,617,000
=========== =========== ===========
Amortization per equivalent
Mcf of production ....................................... $ 0.77 $ 0.54 $ 0.51
=========== =========== ===========
55
COSTS NOT BEING AMORTIZED -- Oil and gas property costs not being
amortized at December 31, 2001 consisted of $13,132,000 of leasehold costs. The
Company anticipates that substantially all unevaluated costs will be classified
as evaluated costs within five years.
RESULTS OF OPERATIONS -- Results of operations for oil and gas
producing activities were as follows:
2001 2000 1999
----------- ----------- -----------
Revenues
Oil and gas sales ......................................... $44,548,000 $44,437,000 $20,644,000
Gains on derivative instruments, net ...................... 6,435,000 0 0
----------- ----------- -----------
50,983,000 44,437,000 20,644,000
----------- ----------- -----------
Expenses
Depletion of oil and gas properties ....................... 9,190,000 6,150,000 4,650,000
Lease operating expense ................................... 3,295,000 2,623,000 2,012,000
Ad valorem and production taxes ........................... 3,344,000 3,421,000 1,765,000
Impairment of natural gas swap ............................ 241,000 0 0
----------- ----------- -----------
16,070,000 12,194,000 8,427,000
----------- ----------- -----------
Income before income taxes .................................. 34,913,000 32,243,000 12,217,000
Income tax expense .......................................... 10,998,000 9,770,000 3,079,000
----------- ----------- -----------
Income from oil and gas producing activities ................ $23,915,000 $22,473,000 $ 9,138,000
=========== =========== ===========
SUPPLEMENTAL OIL AND GAS RESERVE INFORMATION (UNAUDITED)
The reserve information presented below is based on estimates of net
proved reserves as of December 31, 2001 that were prepared by the Company's
engineers and audited by Netherland, Sewell and Associates, Inc., independent
petroleum engineers, and estimates at the end of 2000 and 1999 that were
prepared or audited in part by Netherland, Sewell and Associates, Inc. and in
part by Ryder Scott Company, independent petroleum engineers. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures.
Oil and gas reserve engineering must 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 estimates is a function of
the quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may require revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately produced.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those proved reserves expected to be
recovered through existing wells with existing equipment and operating methods.
56
ANALYSES OF CHANGES IN PROVED RESERVES - The following table sets
forth information regarding the Company's estimated net total proved and proved
developed oil and gas reserve quantities:
2001 2000 1999
---------------- ------------------ -------------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------ ------- ------ ------- ------
Proved reserves:
Beginning of year .................... 3,729 154,172 3,268 124,111 2,826 71,207
Purchases of oil and
gas reserves in place .............. -- 2,388 1 5 8 167
Net exchanges of oil and gas
reserves in place ................. 10 (2,051) 14 125 8 153
Revisions of previous
estimates ......................... (611) (44,495) (259) (5,969) (83) (2,604)
Extensions, discoveries
and other additions .............. 697 14,485 1,145 44,583 862 68,160
Production .......................... (431) (9,277) (440) (8,683) (322) (7,163)
Sales of oil and gas
reserves in place ................ -- -- -- -- (31) (5,809)
-------- -------- -------- -------- -------- --------
End of year ......................... 3,394 115,222 3,729 154,172 3,268 124,111
======== ======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year ................... 2,945 77,385 2,521 54,079 2,305 51,538
End of year ......................... 2,949 69,168 2,945 77,385 2,521 54,079
YEAR-END OIL AND GAS PRICES -- Oil and natural gas prices in effect at
each year end used in calculating reserve estimates were as follows:
2001 2000 1999
---- ---- ----
Natural gas (per Mcf) ....................................... $1.94 $ 7.51 $ 1.90
Oil (per barrel) ............................................ 19.71 26.48 24.68
STANDARDIZED MEASURE - The following table presents the standardized
measure of discounted future net cash flows related to proved oil and gas
reserves.
2001 2000 1999
--------------- --------------- ---------------
Future cash inflows ......................................... $ 290,303,000 $ 1,256,037,000 $ 316,417,000
Future production costs ..................................... (90,816,000) (218,269,000) (90,302,000)
Future development costs .................................... (42,863,000) (61,828,000) (36,107,000)
--------------- --------------- ---------------
Future net cash flows ....................................... 156,624,000 975,940,000 190,008,000
10% discount factor ......................................... (64,719,000) (399,888,000) (81,457,000)
Discounted future income taxes .............................. (25,104,000) (204,931,000) (33,085,000)
--------------- --------------- ---------------
Standardized measure of discounted future net cash
flows .................................................... $ 66,801,000 $ 371,121,000 $ 75,466,000
=============== =============== ===============
57
A summary of changes in the standardized measure of discounted future
net cash flows is as follows:
2001 2000 1999
------------- ------------- -------------
Standardized measure of discounted future net
cash flows, beginning of year ............................ $ 371,121,000 $ 75,466,000 $ 51,426,000
Sales of oil and gas, net of production costs and
taxes .................................................... (34,057,000) (38,392,000) (16,867,000)
Net changes in prices and production costs .................. (469,638,000) 358,936,000 23,719,000
Extensions, discoveries, and improved recovery,
less related costs ....................................... 8,680,000 169,062,000 42,530,000
Development costs incurred during the year .................. 19,920,000 12,128,000 6,373,000
Changes in estimated future development costs ............... 11,381,000 922,000 2,267,000
Revisions of previous quantity estimates .................... (46,997,000) (29,713,000) (3,901,000)
Purchases of reserves in place .............................. 1,088,000 349,000 244,000
Net exchanges of reserves in place .......................... (7,429,000) 3,409,000 233,000
Sales of reserves in place .................................. 0 0 (12,885,000)
Other ....................................................... (4,207,000) (16,747,000) (3,624,000)
Accretion of discount ....................................... 37,112,000 7,547,000 5,143,000
Net changes in future income taxes .......................... 179,827,000 (171,846,000) (19,192,000)
------------- ------------- -------------
Standardized measure of discounted future net
cash flows, end of year ................................... $ 66,801,000 $ 371,121,000 $ 75,466,000
============= ============= =============
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 2001 and 2000.
Three Months Ended
---------------------------------------------------
3/31/01 6/30/01 9/30/01 12/31/01
------- ------- ------- --------
Year Ended December 31, 2001
Revenues ......................................... $18,470,000 $14,188,000 $17,175,000 $10,454,000
Gross profit ..................................... 11,638,000 7,948,000 10,005,000 3,002,000
Income before income tax and cumulative
effect of change in accounting principle ....... 11,975,000 8,221,000 10,242,000 3,369,000
Net income ....................................... 8,676,000 5,671,000 7,067,000 2,354,000
Basic net income per share ....................... 0.68 0.45 0.56 0.18
Diluted net income per share ..................... 0.65 0.43 0.54 0.18
Three Months Ended
---------------------------------------------------
3/31/00 6/30/00 9/30/00 12/31/00
------- ------- ------- --------
Year Ended December 31, 2000
Revenues ....................................... $10,677,000 $12,081,000 $13,264,000 $16,157,000
Gross profit ................................... 5,483,000 6,470,000 7,609,000 10,404,000
Net income ..................................... 4,184,000 4,811,000 5,569,000 7,331,000
Basic net income per share ..................... 0.33 0.38 0.44 0.57
Diluted net income per share ................... 0.32 0.36 0.42 0.55
58
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual
Report on Form 10-K to be signed on its behalf by the undersigned, thereunto
duly authorized, in Denver, Colorado on the 19th day of March, 2002.
PRIMA ENERGY CORPORATION
By: /s/ Richard H. Lewis
---------------------------
Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this Annual Report on Form 10-K has been signed below by the following persons
in the capacities indicated and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Richard H. Lewis March 19, 2002
-------------------------------
Richard H. Lewis Chairman of the Board,
President, Treasurer,
(Principal Executive Officer)
/s/ Neil L. Stenbuck March 19, 2002
-------------------------------
Neil L. Stenbuck Executive Vice President - Finance
(Principal Financial Officer) and
Director
/s/ Sandra J. Irlando March 19, 2002
-------------------------------
Sandra J. Irlando Vice President - Accounting
(Principal Accounting Officer)
/s/ James R. Cummings March 19, 2002
-------------------------------
James R. Cummings Director
/s/ Douglas J. Guion March 19, 2002
-------------------------------
Douglas J. Guion Director
/s/ Catherine James Paglia March 19, 2002
-------------------------------
Catherine James Paglia Director
/s/ George L. Seward March 19, 2002
-------------------------------
George L. Seward Director
INDEX TO EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
------- -----------
3 Certificate of Incorporation of Prima energy Corporation, Delaware,
as filed August 18, 1988. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)
3 Certificate of Amendment of Certificate of Incorporation of Prima
Energy Corporation filed May 1, 1989. (Incorporated by reference to
Annual Report on Form 10-K for Prima Energy Corporation dated June
30, 1989.)
3 Bylaws of Prima Energy Corporation. (Incorporated by reference to
Registration of Securities of Certain Successor Issuers on Form 8-B
dated January 20, 1989.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated June 30,
1997.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated September
30, 2000.)
3 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation. (Incorporated by reference to Quarterly
Report on Form 10-Q for Prima Energy Corporation dated June 30,
2001 and filed August 14, 2001.)
4 Rights Agreement dated as of May 23, 2001, between Prima Energy
Corporation and Computershare Trust Company, Inc., as Rights Agent,
including the form of Certificate of Designation, Powers,
Preferences and Rights of Series A Participating Preferred Stock
dated May 29, 2001, as Exhibit A, the Form of Right Certificate, as
Exhibit B, and the Summary of Rights to Purchase Preferred Shares.
(Incorporated by reference to Current Report on Form 8-K for Prima
Energy Corporation dated May 23, 2001 and filed June 6, 2001.)
10 Prima Energy Corporation Employee Stock Ownership Plan
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation dated June 30, 1989.)
10 Prima Energy Corporation 1993 Stock Incentive Plan. (Incorporated
by reference to Annual Report on Form 10-K for Prima Energy
Corporation dated December 31, 1993.)
10 Agreement of Lease between Denver-Stellar Associates LP, Landlord
and Prima Energy Corporation, Tenant, effective December 1, 2000.
(Incorporated by reference to Annual Report on Form 10-K for Prima
Energy Corporation dated December 31, 2000.)
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP
(b) REPORTS ON FORM 8-K
During the quarter ended and subsequent to December 31, 2001, the
Company filed the following reports on Form 8-K:
o Report dated November 13, 2001, reporting earnings for the quarter and
nine months ended September 30, 2001, and providing an update on
operating activities and commodity hedging.
o Report dated March 4, 2002, reporting year-end 2001 reserves, year 2002
estimated capital expenditures, and the sale of assets.
o Report dated March 20, 2002, reporting year-end 2001 financial results
and providing an update of operating activities and commodity hedging
transactions.