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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, 2000.
[ ] 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 of (I.R.S. Employer Identification No.)
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 8,501,045 shares of Common Stock held by
non-affiliates of the Registrant as of February 28, 2001 was $251,578,226 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).
As of February 28, 2001, Registrant had outstanding 12,731,373 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 2001 Annual Meeting of
Stockholders.
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TABLE OF CONTENTS
ITEM PAGE
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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.................................................. 21
6. SELECTED FINANCIAL DATA.............................................. 22
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.................................. 23
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........... 27
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.......................... 29
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE.................................. 29
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT................... 29
11. EXECUTIVE COMPENSATION............................................... 29
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT........................................................... 29
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS....................... 29
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K............................................................. 30
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PART I
ITEMS 1 and 2. BUSINESS and PROPERTIES
The "Company" or "Prima" is used in this report to refer to Prima
Energy Corporation and its consolidated subsidiaries. Items 1 and 2 contain
"forward-looking statements" and 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" beginning on page 19.
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 more
recent years, the Company's activities, through its wholly owned subsidiaries,
have expanded to include oil and gas property operations, oilfield services, and
natural gas gathering, marketing and trading.
The Company organizes its activities in operating segments that consist
of the acquisition, exploration, development and operation of oil and gas
properties and the development, production and sale of oil and natural gas,
providing oil field services for wells which it operates and for third parties
and the marketing and trading of third party natural gas. During 2000, the
Company began developing gas gathering and compression operations, which segment
was not material to Prima's operations at December 31, 2000. Prima's oil and gas
exploration, development and production activities are conducted by Prima Oil &
Gas Company, a wholly owned subsidiary. The following wholly owned subsidiaries
of Prima Oil & Gas Company conduct activities for the Company as noted: oilfield
services by Action Oil Field Services, Inc. and Action Energy Services, crude
oil and natural gas marketing and trading by Prima Natural Gas Marketing, Inc.
and natural gas gathering and compression by Arete Gathering Company, LLC. For a
more detailed discussion of the Company's business segments, including revenues
earned from third parties, operating earnings and total assets, see Note 8 of
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 400,000 net acres 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 "Developed
Properties" beginning on page 5.
The Board of Directors of Prima approved two separate three for two
stock splits of its common stock in 2000. The first three for two stock split
was to stockholders of record on February 10, 2000, distributed February 24,
2000. As a result, the number of shares of common stock outstanding increased
from 5,645,586 to 8,468,112 on the distribution date. The second three for two
stock split was to stockholders of record on November 27, 2000, distributed on
December 11, 2000. As a result, the number of shares of common stock outstanding
increased from 8,522,812 to 12,783,373 on the distribution date. All share and
per share amounts included in this Form 10-K have been restated to show the
retroactive effects of the stock splits.
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At December 31, 2000, the Company reported the following:
o $104,900,000 of assets.
o 176.5 Bcfe of proved reserves with a pretax present value discounted at
10% ("PV10") of $576 million using average year end prices of $7.51 per
Mcf of natural gas and $26.48 per barrel of oil held constant over the
estimated economic life of each of the proved properties, and a PV10 of
$263 million using an alternate price case based upon five-year forward
prices averaging $3.78 per Mcf and $22.21 per barrel.
o Net income of $21,895,000.
o Cash flow provided by operating activities of $36,376,000.
o 2000 average daily production of 23,724 Mcf of natural gas and 1,202
barrels of crude oil (30,943 Mcfe or 5,156 BOE) per day.
o 2000 average price realizations of $3.63 per Mcf of natural gas, and
$29.29 per barrel of crude oil.
o Operations of 564 wells representing approximately 90% of the wells in
which Prima owns a working interest.
o 26,900 gross, 21,300 net developed acres,
o 489,000 gross, 334,000 net undeveloped acres.
The Company has identified over 2,000 potential development,
exploitation and exploration opportunities on its acreage which include
drilling, recompletion and refracturing projects. Prima plans to continue to
identify, develop and exploit opportunities in all areas of its activity over
the next few years.
STRATEGY
OBJECTIVE. The Company attempts to create shareholder value by identifying,
evaluating and seizing opportunities where we 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.
ACREAGE. Prima attempts to acquire leasehold acreage at reasonable costs with
attractive terms in prospective areas. The Company can potentially benefit from
its own activities as well as from the activities of other operators in these
areas.
OPERATIONS. It is an objective of the Company to operate, when justified, the
oil and gas properties in which it has economic interests. Prima believes that,
with the responsibility of operator, it is in a better position to control
costs, safety, timeliness and quality of work, and other factors affecting the
economics of a well.
EXPLOITATION. The Company intends to continue its exploitation efforts in all
areas of activity. In the Denver Basin, we plan to continue well refracturing,
restimulation and development drilling as warranted by ongoing results and
economic success. Prima has been drilling wells in the Denver Basin for nineteen
years, and refracturing wells in the area for over six years. We believe we have
the knowledge and experience to continue this profitable activity in the future.
We also plan to continue exploitation activity in the Powder River Basin for
both conventional and coal seam reservoirs, as well as the Wind River Basin,
depending upon the merit of each activity and timing due to regulatory
considerations. These activities are generally lower to moderate risk endeavors
that meet our economic criteria.
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EXPLORATION. The Company typically allocates 5 to 20% of its capital
expenditures budget on 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'
wells and acreage. The objective of our exploration activities is to expose a
portion of our capital to higher risk projects where the potential warrants the
higher risk. These activities could have a more significant impact on the value
of the Company although the likelihood of success is lower as compared to
exploitation activities.
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, 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 has the objective for this
activity to be a separate profit center for work performed for third parties. We
have been involved in various aspects of the well servicing business for 13
years in the Denver Basin, and in 1999 started an oilfield drilling and service
company in the Powder River Basin.
MERGER, ACQUISITION AND DIVESTITURE. The Company in its ordinary course of
business regularly reviews merger, acquisition and divestiture opportunities
related to the oil and gas industry which can enhance its current business.
DEVELOPED PROPERTIES
DENVER BASIN
LOCATION, OPERATIONS AND ACREAGE. Prima's activities in the Denver Basin are
located primarily in the Wattenberg Area which encompasses in excess of 1,000
square miles, and is located from 20 to 55 miles northeast of Denver, Colorado.
Prima also owns leasehold interests on 4,480 acres and conducts operations at
Denver International Airport from seven wells it has drilled and completed.
Prima operated 379 wells in the Denver Basin (including those at DIA) as of
December 31, 2000. Our leasehold position in the Denver Basin at that date was
17,400 gross, 14,400 net, developed acres, with an additional 15,000 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 the Codell and Niobrara. The Codell and Niobrara blanket large
areas of the field at depths of approximately 7,000 to 7,300 feet and have
moderate porosity and low permeability. The formations require fracture
stimulation, to establish economic production. Recoverable reserves in any
individual wellbore are controlled by reservoir quality, thickness and fracture
stimulation techniques. Our Denver Basin wells produce natural gas, natural gas
liquids, and crude oil. Natural gas liquids (propane, butane, ethane, isobutane,
pentane) are processed out of the well stream and sold separately by the third
party gatherer/purchaser, but are included in our per Mcf price at the wellhead.
Natural gas 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. Our crude oil in this area is sweet crude and commands a premium to the
Eastern Colorado and West Texas Intermediate postings. The 2000 production from
Prima's Denver Basin properties accounted for approximately 78% of total oil and
gas revenues, with natural gas averaging 16,486 Mcf per day and crude oil
averaging 1,122 barrels per day net to Prima's interest.
RESERVES, FINDING AND DEVELOPMENT COSTS. The Denver Basin represented 42% of
Prima's year end proved reserves on an Mcfe basis. Codell/Niobrara wells drilled
and completed in this area cost approximately $280,000 and target approximately
270 to 300 MMcfe per well. Finding and development
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costs for these wells are approximately $1 per BOE. At year end 2000, the
Company controlled approximately 220 potential drillsites with 56 classified as
proved undeveloped reserves. The Company's strategy has been to selectively
drill wells utilizing advanced drilling and completion techniques, improved
marketing, and cost controls in an attempt to enhance the wells economics and
prove additional acreage. There is no assurance that these locations will
ultimately be drilled, or that wells drilled will ultimately prove to be
commercially productive.
CODELL/NIOBRARA REFRACTURING. Advancements in refrac stimulation technology
(putting a new fracture treatment in a producing formation of 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, and availability of Section 29 tax credits of approximately
$0.65 per Mcf on production through the year 2002, for restimulation. Refracs
completed by Prima in 2000 have resulted in average daily incremental production
rates of 125 Mcf of natural gas and 12 barrels of oil per day. The refracs cost
approximately $115,000 and target approximately 150 MMcfe. Finding and
development costs for these incremental reserves average approximately $0.70 to
$0.80 per Mcfe.
2000 ACTIVITY. During 2000 the Company refractured 61 wells (56.1 net). We
focused activity on refracs given favorable economics and efficiency of the
operations. The refracs typically do not involve acquiring new leases, gas sales
contracts, or surface access agreements. Prima also focused its attention on the
drilling of 30 gross (29.4 net) Codell/Niobrara wells during the year, of which
29 were successfully completed and placed on production. The Company also
recompleted new producing intervals in eight wells (7.7 net) during the year,
including seven Sussex Formation recompletions and both a Codell/Niobrara and a
J-sand recompletion in one well.
FUTURE ACTIVITY. The Company intends to continue its development and
exploitation activities in the Denver Basin. We have budgeted 60 Codell/Niobrara
refrac stimulations during 2001. We also intend to drill approximately 30
Codell/Niobrara wells in the Wattenberg Area in 2001, with approximately 12 of
these scheduled during the first quarter. The Company has budgeted to drill
three additional J-Sand wells on the eastern portion of the Denver International
Airport property. Our recompletion efforts will continue with six planned in
2001. Prima anticipates capital expenditures in the Denver Basin in 2001 of
approximately $16 million.
POWDER RIVER BASIN
COALBED METHANE
LOCATION, OPERATIONS, ACREAGE. The coalbed methane ("CBM") play in the Powder
River Basin is prospective over a vast geographic area encompassing
approximately 3 million acres in northeastern Wyoming. The Company is currently
involved in drilling, gathering and compression, and well servicing activities
in the area. According to the Wyoming Oil & Gas Commission, over 6,300 CBM wells
have been drilled with approximately 4,100 wells producing an estimated 498 MMcf
of natural gas per day as of October 31, 2000. We believe approximately 70
drilling rigs are being utilized, making this the most active play in the United
States. Prima holds a significant leasehold position that stretches from the
southernmost part of the play to its known limits on the northern end. The
leasehold position is generally close to the gathering and transportation
infrastructure in the basin as it runs south to north, and in several instances,
is relatively close to areas of known production. At December 31, 2000, Prima
held 5,900 gross, 5,800 net developed acres, with an additional 146,000 gross,
136,000 net undeveloped prospective acres in this play. Our acreage is
approximately 79% federal, 9% state, and 12% fee (private) leases. The federal
leases have an initial ten year term, the state leases have a five year term,
and fee leases vary from a few months to several years.
FORMATION AND PRODUCTION. Coals are located in the Fort Union formation at
depths ranging from 200 to 2,000 feet, and vary in thickness from a few feet to
over 175 feet. It is common to encounter multiple coal zones between these
depths. The methane in coal beds is adsorbed, or saturated, within the coal
layers and held in place by water within the coals. When water is produced from
the coal seam, the pressure gradient
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is reduced, allowing the gas to desorb from the coal. Operators in the area have
experienced dewatering times that range from a few days to over one year, and
the dewatering time is influenced by well density, coal depth, permeability,
well location and other factors. Production rates have ranged from a few Mcf to
over 1,000 Mcf per day, and average approximately 130 Mcf per day/per well. The
gas from this area is generally slightly less than 1,000 Btu per Mcf, and may
require carbon dioxide extraction to meet interstate pipeline gas quality
specifications. The Wyoming Oil and Gas Conservation Commission has adopted 80
acre per well field spacing for this play.
RESERVES, FINDING AND DEVELOPMENT COSTS. Powder River Basin Coalbed Methane
represented 47% of Prima's year end reserves on an Mcfe basis. CBM wells cost
from $60,000 to $85,000 to drill, equip and complete through the sales meter
depending on location and depth, exclusive of gathering, lateral and compression
costs. A typical well is anticipated to have ultimate reserves of 150 to 500
MMcf, with finding and development costs estimated to be $0.25 to $0.40 per Mcf.
At year end 2000, the Company's independent engineers classified 141 wells as
proved developed non-producing and classified 347 locations as proved
undeveloped reserves. The Company cautions that its deliverability and reserves
per well may vary considerably depending on location, thickness of coal, 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. Based on independent engineering estimates, the
Company believes it has a potential inventory of over 2,000 drill sites in this
play. There is no assurance that these wells will be drilled or that those
drilled will ultimately develop economic reserves.
PERMITS - DRILLING, WATER DISCHARGE AND AIR QUALITY. Drilling permits for the
CBM play are issued by the Wyoming Oil & Gas Commission for wells located on
state and private lands. The Bureau of Land Management ("BLM") issues drilling
permits on federal leaseholds following completion of environmental impact
studies. The first such study 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 is essentially a moratorium on issuing drilling permits
for federal leaseholds pending completion of a second environmental impact study
("EIS"). The EIS, which provides for the drilling of approximately 50,000 wells,
is currently underway with a record of decision expected in the early part of
2002. The Company anticipates much greater accessibility to its federal acreage
after this second study is completed. In the interim, Prima has access to over
200 drilling permits on its state, private and federal land which will allow the
Company to conduct its budgeted drilling program through the first half of 2002.
A significant delay in the issuance of additional drilling permits on federal
acreage would significantly impact the Company's long range plans. An
Environmental Assessment provides for the issuance of approximately 2,500
special drainage permits on federal leasehold pending completion of the EIS.
Water from the play is generally discharged on the surface and is potable
(drinking water quality). Water discharge permits are issued by the Wyoming
Department of Environmental Quality ("DEQ"). Issuance of water discharge permits
slowed during the 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. The Company believes it has water permits, or recharge wells
adequate to continue its drilling program. Air discharge permits are also issued
by the DEQ, and take approximately 4 to 5 months to be issued. The Company has
not encountered difficulties to date acquiring air permits for natural gas fired
compressors in the CBM play.
NATURAL GAS TRANSPORTATION INFRASTRUCTURE. The transportation infrastructure in
this basin is currently capable of moving over 1.3 Bcf (1,300,000 Mcf) of
natural gas on a daily basis. MIGC, Inc. has a high pressure pipeline running
the expanse of the play from north to south which is capable of flowing up to
135,000 Mcf per day. In the northern end of the basin, Bighorn Gas Gathering,
LLC has completed and placed in service a high pressure header system capable of
moving up to 250,000 Mcf per day. Also in the northern end of the play,
Williston Basin Interstate Pipeline Company has a high pressure pipeline which
can transport up to 35,000 Mcf per day. Thunder Creek Gas Services, LLC, and
Fort Union Gas Gathering LLC
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have each completed high pressure header systems capable of moving 450,000 Mcf
per day each from the central portion to the southernmost portion of the basin
at an area generally known as Glenrock. From Glenrock, the natural gas can
access KM Interstate, and Wyoming Interstate Pipeline's Medicine Bow Lateral
with subsequent connections into the interstate pipeline grid including:
Colorado Interstate Gas Company, Front Range, Williams and Trailblazer pipelines
at the Cheyenne Hub (Rockport) which provides access to markets from California
to the Mid-Continent. The Medicine Bow Lateral, which connects from Glenrock to
Rockport, currently is capable of moving approximately 400,000 Mcf per day. The
construction of a loop of this system is underway, with a fall 2001 expected
completion. This looping will provide an estimated 600,000 Mcf per day of
additional capacity. At the Cheyenne Hub, Trailblazer pipeline is adding
compression and pipe to increase capacity to the mid-continent by 300,000 Mcf
per day with an anticipated in-service date by December 2002. In addition,
potential new pipeline expansion projects have been announced by Northern
Border, Colorado Interstate Gas Company and Williams. These projects are
currently seeking support, firm transportation commitments, and as such, no
plans to build have been announced. At year end 2000, the Company estimates that
about 550,000 Mcf per day of coal seam 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 has,
however, made firm sales arrangements from its Stones Throw and Kingsbury areas
mentioned below to a third party who owns and controls firm header and pipeline
capacity from the basin.
2000 ACTIVITY. During 2000, Prima drilled 153 gross (152.3 net) CBM wells in
this play. The Company has drilled a total of 198 gross CBM wells since
inception of its activity in the play and through February 28, 2001. In 2000,
Prima drilled a high density of wells in two areas in anticipation of dewatering
and starting production, Stones Throw and Kingsbury discussed in more detail
below. We also continue to drill science wells on our prospects to determine
depth and number of coal seams, coal thickness, pressure data, permeability, gas
content, desorption data and other information pertinent to evaluating our
position in the play. These wells will, in part, determine our next areas of
high density drilling. The Company continues to review well and lease
acquisition opportunities in the area on a regular basis.
Stones Throw Area. The Company has drilled 112 CBM wells in this area located
approximately 30 miles north of Gillette, Wyoming. These wells are drilled in
high density with the goals of dewatering and producing CBM gas. To produce the
gas, the wells must be hooked-up to a low pressure gathering system and
compression, commonly referred to as "screw compression", which holds wellhead
pressures to 5 psia, or less. The gas must then move through a gathering system
where, at its terminus, gas needs to be boosted up to about 1,400 psia so it can
enter a high pressure header system line in the area. This high pressure boost
is commonly referred to as "reciprocating compression." Prima's wholly owned
gathering company, Arete Gathering Company, at year end had installed two screw
and one reciprocating compressor to facilitate first production. The Company
anticipates installing additional compression, and having 110 wells producing
into the gathering system by the end of the first half of 2001. The
gathering/compression system is currently designed to flow up to 14,000 Mcf per
day, but can be expanded to 21,000 Mcf per day if warranted. The Company
cautions that these wells must be dewatered and are in various phases of
producing and being connected to the gathering system which will affect the
actual amount of gas being produced. We have secured a firm sales agreement with
a significant marketer and holder of header and pipeline capacity for gas
produced from this area. The contract is for five years and has market based
(spot), rather than fixed, pricing.
Kingsbury Area. In 2000, Prima drilled 30 CBM wells in this area located
approximately 20 miles northwest of Gillette, Wyoming. The wells are generally
drilled in high density with first production anticipated by the third quarter
2001. We have a less significant acreage position in this area compared to
Stones Throw, and have elected to have the low pressure gathering installed by a
third party that already has gathering and compression in the area to collect a
third party producer's wells. Construction to extend the mentioned gathering
system to our wells began in the first quarter of 2001. Prima has arranged a
market based firm sales agreement providing a 10 year term with the gathering
company, which holds firm transport downstream of the gathering system on header
and pipeline systems.
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FUTURE ACTIVITY. The Company anticipates drilling between 175 and 200 CBM wells
in 2001. A portion of these wells will be drilled in Stones Throw and Kingsbury
if warranted by results. The majority of wells are expected to be drilled in
dense groupings where we intend to dewater and produce wells. We caution that
the actual number of wells drilled could be less. We intend to continue our well
drilling and servicing business, and to participate in low pressure gathering
from the wellhead to the headers in the Powder River CBM play. Our capital
budget for 2001 in the coalbed methane play is approximately $18 million.
CONVENTIONAL
LOCATION, OPERATIONS, ACREAGE. Prima owns the deep rights (below the coals) in
approximately 152,000 gross, 147,000 net acres in the Powder River Basin. We
currently operate 13 of the 16 conventional reservoir wells in which we have an
interest, or 81% of the wells in which we have ownership. Prima has been active
in lease acquisition, drilling and production from conventional reservoirs in
the Powder River Basin since 1994. The Company is credited with finding the
Cedar Draw Field approximately 21 miles northwest of Gillette, Wyoming as a
field extension to Amos Draw, where we operated six wells and had a non-operated
interest in two wells at year end.
FORMATIONS AND PRODUCTION. At December 31, 2000, Prima produced from two
formations in the conventional play, the Muddy formation located at a depth of
approximately 9,500 to 9,800 feet, and the Turner formation at about 10,000
feet. Both of these formations are localized in nature, have moderate porosity
and permeability, and require fracture or stimulation to establish economic
production. Natural gas from these two formations averages approximately 1,280
Btu per Mcf. The production stream includes natural gas, natural gas liquids,
and sweet crude oil which is sold at a premium to posted prices for Wyoming
crude oil. During 2000, production from Prima's conventional Powder River Basin
properties accounted for approximately 11% of total oil and gas revenues, with
natural gas averaging 3,447 Mcf per day and crude oil averaging 71 barrels per
day net to our interest.
RESERVES, FINDING AND DEVELOPMENT COSTS. The Powder River Basin conventional
play represented approximately 8% of Prima's year end reserves on an Mcfe basis.
Muddy formation wells in this area cost from $750,000 to $850,000 to drill and
complete, and average 1.2 to 1.5 Bcfe per well. Historical finding and
development costs for Muddy formation wells have averaged approximately $0.60
per Mcfe. At year end 2000, the Company carried one proved developed
non-producing location and three well locations as proved undeveloped in its
reserve report for conventional reservoirs in this area.
2000 ACTIVITY. Prima drilled one (1.0 net) operated well to the Muddy formation
in 2000. The well was drilled in the second quarter and completed as a producer.
The Company also participated in three (1.5 net) non-operated Muddy formation
wells in the fourth quarter. Two of these wells were dry holes, and one was
completed as a producer with initial sales in the first quarter of 2001.
FUTURE ACTIVITY. The Company currently intends to participate in three or four
conventional wells in 2001. The Company also intends to continue its evaluation
of other prospects and leads in the conventional play.
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. Our activity in the area is primarily as a non-operated working
interest owner, although we 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 41,000 gross, 25,000 net
undeveloped acres at year end 2000.
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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 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
altogether, 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. Approximately 82% of the Company's production from this
area was from the Lance formation at year end 2000. The Fort Union, which
appears sporadically at shallow depths, can be identified on the way down to the
Lance or Lakota/Muddy, and has been drilled 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
index, or spot prices. The crude oil sells for a premium to posting for Wyoming
crude oil in this area. At year end 2000, the Wind River Basin represented
approximately 11% of Prima's total oil and gas revenues, with natural gas
averaging 3,771 Mcf and crude oil 9 barrels per day.
RESERVES, FINDING AND DEVELOPMENT COSTS. The Wind River Basin represents
approximately 3% of Prima's year end reserves 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 have the objective of 15 to 18 Bcfe per
well. The year end 2000 reserve report for this area includes three proved
undeveloped locations, and eleven proved developed non-producing opportunities.
Our activity in this area is determined to a large extent by the operator of the
property, who proposes well or recompletion operations pursuant to standard
industry operating agreements. Prima reviews each opportunity and elects whether
or not to participate in the activity depending on economic and geologic merit,
and has participated in over 95% of all activity proposed in the area.
2000 ACTIVITY. Prima participated in the drilling of one gross (0.06 net) well
in Cave Gulch during 2000. We participated in one Lance formation well that was
completed as a producer, and one Frontier/Lakota/Muddy well which was in the
process of an attempted completion during the first quarter of 2001.
FUTURE ACTIVITY. Activity in the Cave Gulch area has decelerated as the field
reaches its limits of known areal extent and producing formations. Future
activity, generally proposed by a third party operator of the area, should be
limited. Prima expects limited capital expenditure in this area for new drilling
or recompletions during 2001, although it will review each opportunity presented
based on its geologic and economic merit.
UNDEVELOPED PROPERTIES
Prima owns interests in the properties described below. While these properties
are predominately undeveloped acreage holdings, the Company either plans
activities or is aware of activities planned by others which could benefit the
Company. There is no assurance any of the activities will occur or, if
undertaken, will result in favorable developments.
Coyote Flats-Wasatch Plateau Prospect. Prima currently owns or controls
approximately 77,000 gross, 73,000 net acres on the Wasatch Plateau in central
Utah. The Company's leasehold position is located approximately 12-15 miles
northwest of the prolific Drunkard's Wash coalbed methane ("CBM") field.
Drunkard's Wash, which is under active development by major independent
operators, produces from the Ferron coals and is expected to ultimately produce
in excess of 1.25 Tcf of gas. The primary CBM target on Prima's lease block is
the Emery coal formation. The block contains total Emery coal thicknesses of up
to 178 feet. Significant gas shows have been reported by operators of
conventional wells that have been drilled in this area. The Emery coals are
found across the majority of the lease position at depths ranging from 2,500 to
5,000 feet. Gas shows have been reported in the Emery coals as deep as 8,500
feet on the Company's lease block. The lease block is also on trend with CBM
production from the Blackhawk coal formation at the Castlegate field
approximately 10-12 miles to the east. Blackhawk coals are present under the
lease block at depths ranging from 1,000 to 5,000 feet and thickness of up to
150 feet. Gas shows have also been reported from this interval.
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In addition to the CBM potential of the block, significant gas shows have been
reported from the Ferron sandstones and the Mancos shale. The Clear Creek field
4-10 miles south of the lease position has produced more than 126 Bcf of gas
from the Ferron sandstone. The Dakota sandstone is also productive 25-30 miles
south of the block at Flat Canyon field.
The Company plans to begin testing and evaluating this block later this year.
Prima has participated for a 37.5% non-operated working interest in a CBM well
in the Helper field located north of Price, Utah. The well was placed on
production in late January and is currently producing between 150 and 250 Mcf
per day. The well is completed in the Ferron coals between 1,800 and 1,900 feet.
Brooks Draw Prospect. Prima owns approximately 21,600 gross and net acres in
this prospect located in Natrona County, Wyoming. The position is prospective
for natural gas and oil from the highly fractured Niobrara, Turner and Newcastle
(Muddy) Formations. In 2000, a third party operator drilled several horizontal
wells in this area in an effort to intersect more fractures from a well bore.
Another third party operator in the area has drilled a horizontal test well in
the Newcastle Formation. According to a press release issued by one of the
participants, this well was drilled to a measured depth of 10,578 feet in the
Newcastle Formation. On two separate 72 hour tests, the well flowed between 203
and 345 barrels of oil per day and 525 to 575 Mcf per day of 1,490 Btu gas.
Prima plans to monitor activity closely in this area, and may participate in
well(s) where our acreage is included within the spacing units of wells proposed
by other operators. While initial reports from the area are encouraging,
ultimate economics of the play are not clearly defined at this early stage of
development.
Hell's Half Acre Prospect. This prospect is a seismically defined structure
located approximately 10 miles south of the Cave Gulch field along the Owl Creek
Thrust in Natrona County, Wyoming. The structure is believed to have potential
in formations ranging from the Ft Union Formation at about 3,000 feet through
the Madison Formation at greater than 22,000 feet. The Company owns
approximately 15,700 gross, 5,400 net undeveloped acres in this prospect. We
have agreed to participate in the drilling of a well to approximately 12,700
feet to test the Upper Cretaceous formations over a portion of the prospect this
year.
Merna Prospect. Prima owns approximately 72,000 gross, 28,000 net undeveloped
acres in this prospect located in Sublette County, Wyoming. The acreage is
believed to be primarily prospective for natural gas development from the
overpressured Lance Formation at a depth of approximately 13,000 feet. Prima has
entered into an agreement with a third party to support that party's effort to
reenter and attempt to complete one well and drill a second well on offsetting
acreage. In exchange for the information obtained in these wells, Prima has
agreed to allow the third party to participate in the drilling of a test well on
a small portion of Prima's lease position within the next 18 months. Operations
on the initial reentry are scheduled to begin this summer.
Christmas Meadows Prospect. This prospect is located in Summit County, Utah on
the north slope of the Uintah mountains approximately 30 miles south of
Evanston, Wyoming. The prospect is a seismically defined feature found in the
Utah portion of the Overthrust Belt. Prima owns or controls a 50% farm-out
interest in the Table Top Federal Unit which consists of approximately 23,000
acres. The project has been delayed for several years because a 400 acre tract
immediately adjacent to the drillsite has not been made available for leasing
while the U.S. Forest Service has conducted an environmental impact study and a
revision of the area forest plan. Prima and its partners intend to cause a well
to be drilled on the unit as soon as the situation with the unleased tract has
been resolved.
Klondike/Hinge Play. This play is located in the Big Horn Basin of northern
central Wyoming. The Company owns approximately 102,000 gross, 26,000 net
undeveloped acres in the play. The play is exploratory in nature and is
prospective for both crude oil and natural gas production. A third party
operator owning approximately 75% interest in this acreage position has advised
Prima that it intends to propose the drilling of up to three wells in 2001.
Prima will review each proposed well, and decide whether or not to participate
based upon geological and economic merit.
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Jim Hill Draw Prospect. Prima is participating with a 15% interest in the 7,600
acre Jim Hill Draw unit in Converse County, Wyoming. The objective of this
prospect is the Muddy sandstone found at approximately 12,100 feet with
secondary objectives in the shallower Frontier and the deeper Dakota sandstones.
The prospect is located about one mile west of the Sand Dunes field which has
produced more that 24 million barrels of oil and 56 Bcf of gas. The proposed
test well on this prospect is approximately one mile west of a Marathon Oil
Company well that has produced in excess of 2 million barrels of oil and more
than 4 Bcf of gas. The operator has proposed to drill the initial test well on
this prospect this spring.
East Lost Hills Prospect. During the second quarter of 1998, the Company
participated for a 6.25% interest in a deep Temblor Formation exploratory well
located in the San Joaquin Basin of central California. The well drilled, the
#1-17 Bellevue, is located in Kern County California and was to be drilled to a
depth of 18,500 feet pursuant to fully endorsed exploration and standard
industry operating agreements. During the drilling of the well, a dispute arose
as to Prima's ownership in the prospect which remains unresolved. The operator
of the well takes the position that Prima breached the agreement and forfeited
its interest in the prospect and all future development. The agreements included
an Area of Mutual Interest and provisions for leasehold assignments and
participation in subsequently acquired acreage. The Company is monitoring the
situation and intends, based on advice of counsel, to take appropriate actions
to protect the shareholders' interests.
RESERVES
The Company's net proved reserves are approximately 87% attributable to
natural gas, and 13% to crude oil. The net proved reserves were estimated at
year-end 2000 by the following independent engineering firms:
Netherland, Sewell and Associates, Inc. (Denver Basin and Powder River
Basin)
Ryder Scott Company (Wind River Basin)
The table below sets forth the Company's estimated quantities of proved
reserves, all of which are located in the continental United States, and the
present value of estimated future net cash flows from these reserves on a
non-escalated basis. The quantities and values are based on prices in effect at
year end ($7.51, $1.90 and $2.13 per Mcf of natural gas and $26.48, $24.68 and
$10.31 per barrel of oil at December 31, 2000, 1999 and 1998, respectively). The
future net cash flows were discounted by ten percent per year as of the end of
each of the last three fiscal periods. The ten percent discount factor is
specified by the Securities and Exchange Commission and is not necessarily the
most appropriate discount rate. Present value, no matter what rate is used, is
materially affected by assumptions as to timing of future production, which may
prove to be inaccurate. For further information concerning the reserves and the
discounted future net cash flows from these reserves, see Note 12 of the Notes
to Consolidated Financial Statements.
December 31,
------------------------------------------
2000 1999 1998
------------ ------------ ------------
Estimated proved natural gas reserves (Mcf)...... 154,172,000 124,111,000 71,207,000
Estimated proved oil reserves (barrels).......... 3,729,000 3,268,000 2,826,000
Present value of estimated future net cash
flows (before future income tax expense)....... $576,052,000 $108,551,000 $ 65,318,000
Standardized measure of discounted
future net cash flows.......................... $371,121,000 $75,466,000 $ 51,426,000
The present value of estimated future net cash flows before future
income tax expense was also calculated using an alternate price case based upon
five-year forward prices averaging $3.78 per Mcf of natural gas and $22.21 per
barrel of oil. The resulting PV10 using these prices was $263 million at
December 31, 2000 for the Company's proved reserves.
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There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above table represents estimates only.
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 estimate 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 justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately produced. There has been 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, 2000. 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 present value of estimated future net cash
flows and the standardized measure of discounted future net cash flows.
Since January 1, 2000, 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 23,724 Mcf per day
for the year ended December 31, 2000 compared to 19,625 Mcf per day for the year
ended December 31, 1999 and 17,742 Mcf per day during the year ended December
31, 1998. Net oil production averaged 1,202 barrels per day for the year ended
December 31, 2000 compared to 882 barrels per day during the year ended December
31, 1999 and 784 barrels per day during the year ended December 31, 1998. The
following table summarizes information with respect to the Company's producing
oil and gas properties for each of these periods.
Year Ended December 31,
------------------------------------
2000 1999 1998
--------- --------- ---------
Quantities Sold:
Natural gas (Mcf) ...................... 8,683,000 7,163,000 6,476,000
Oil (barrels) .......................... 440,000 322,000 286,000
Average Sales Price:
Natural gas (per Mcf) .................. $ 3.63 $ 2.10 $ 2.00
Oil (per barrel) ....................... $29.29 $17.42 $12.71
Average production (lifting) costs per
equivalent Mcf (1) .................... $ 0.53 $ 0.42 $ 0.40
----------
(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).
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PRODUCTIVE WELLS
The following table summarizes total gross and net productive wells for
the Company at December 31, 2000.
Productive Wells
----------------------------------
Oil Gas
---------------- ----------------
Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------
Operated:
Colorado ......... 9 8.5 370 316.6
Wyoming .......... 0 0.0 14 12.4
Non-operated:
Colorado ......... 0 0.0 21 8.6
Wyoming .......... 0 0.0 32 2.7
----- ----- ----- -----
Total (3) ..... 9 8.5 437 340.3
===== ===== ===== =====
Additionally, the Company has a royalty interest in 194 of the gross
wells reported above in which it owns a working interest. Also, the Company has
royalty interests in an additional 41 gross wells which 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) Wells are classified as oil wells or gas wells according to their
predominate production stream. Multiple completions are counted as one
well.
DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 2000, 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 .......... 17,400 14,400 15,000 13,000
Green River Basin ..... 0 0 80,000 34,000
Powder River Basin .... 6,900 6,700 190,000 179,000
Wind River Basin ...... 1,100 150 41,000 25,000
Other Basins .......... 1,500 50 61,000 57,000
------- ------- ------- -------
Total ................. 26,900 21,300 489,000 334,000
======= ======= ======= =======
----------
(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.
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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. 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, 2001................. 12,000 10,000
December 31, 2002................. 14,000 6,000
December 31, 2003................. 17,000 11,000
December 31, 2004................. 54,000 29,000
December 31, 2005................. 81,000 50,000
December 31, 2006 and later....... 273,000 200,000
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities
for the years ended December 31, 2000, 1999 and 1998 is set forth below:
2000 1999 1998
---------------- ---------------- ----------------
Gross Net Gross Net Gross Net
------ ------ ------ ------ ------ ------
Development:
Productive .... 181 179.69 33 27.14 30 10.52
Dry ........... 3 2.00 1 0.75 2 0.31
------ ------ ------ ------ ------ ------
184 181.69 34 27.89 32 10.83
====== ====== ====== ====== ====== ======
Exploratory:
Productive .... 5 4.90 9 6.19 4 3.05
Dry ........... 0 0.00 0 0.00 2 1.06
------ ------ ------ ------ ------ ------
5 4.90 9 6.19 6 4.11
====== ====== ====== ====== ====== ======
Total:
Productive .... 186 184.59 42 33.33 34 13.57
Dry ........... 3 2.00 1 0.75 4 1.37
------ ------ ------ ------ ------ ------
189 186.59 43 34.08 38 14.94
====== ====== ====== ====== ====== ======
Since December 31, 2000 and through February 28, 2001, the Company has
drilled or participated in six gross (5.96 net) wells drilled and 17 gross (16.0
net) refracs in the Denver Basin. Four of the new wells were on production and
two were waiting on completion. All of the refracs were back on production. The
Company also drilled 27 gross (26.1 net) wells in the Powder River Basin coalbed
methane play. These wells were waiting on pipeline hook-up.
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 consider and 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
2000. We did, however, have financial hedges providing for a fixed price on a
portion of our natural gas production in the fourth quarter of 2000 and the
first quarter of 2001, which hedges are discussed in "Risk Management" below.
Prima has one significant
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purchaser of its natural gas in the Denver Basin, Duke Energy Field Services,
LLC ("Duke"), who accounted for 36% of the Company's total consolidated revenues
for the year. Duke is not affiliated with Prima, and while loss of this 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 for sale, but has not
contracted for downstream transportation on a firm basis. As such, we have no
liability to pay reservation (demand) charges for header or pipeline capacity,
or assurance that our gas can flow every day, although no significant
curtailment of production occurred in 2000. Prima trades the basis, or
difference in price from pipeline to pipeline, to protect itself should pipeline
capacity out of the Rocky Mountain Region fill and gas in the area become
discounted as it seeks markets in other regions of the country. At year end
2000, Prima had financially traded basis for a portion of its 2001 production as
noted below in "Risk Management." In its areas of activity, Prima also engages
in trading natural gas, purchasing and reselling 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 open 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 2000. In 2000, total revenues from the sale of Prima's natural gas
production were $31,542,000, or 71% of oil and gas sales and 60% 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 due to quality and low
availability of domestic barrels for purchase. The contracts are generally month
to month in duration. The point of sale for our crude oil is at the well, from
which oil is trucked by the purchaser to pipelines or refineries. During 2000,
one purchaser, Ultramar Diamond Shamrock ("UDS"), accounted for approximately
21% of Prima's total consolidated revenues for the year. Prima is not affiliated
with UDS, and believes that it can sell its crude to other purchasers should we
lose UDS as a customer. In 2000, total revenues from the sale of Prima's crude
oil were $12,895,000, or 29% of oil and gas sales and 25% of consolidated
revenues.
RISK MANAGEMENT. To hedge its natural gas and crude oil production as well as
buy for resale activity, the Company from time to time uses futures and energy
swaps. The purpose of these hedges is to provide market price protection in the
volatile environment of natural gas and crude oil pricing. During 2000, Prima
hedged approximately 1% of its estimated natural gas production at an average
fixed price of $6.25 per MMBtu, and approximately 5% of its estimated crude oil
production at an average fixed price of $36.44 per barrel. The Company also from
time to time protects itself by locking in the NYMEX to CIG basis differential.
This type of trade is done to protect the Company from an expanding basis, or
difference in price, should natural gas supplies exceed pipeline capacity out of
the Rocky Mountain region. They also allow the Company to hedge its production
during the contract period by selling corresponding NYMEX futures contracts and
thus securing a price equal to the NYMEX sales price minus the basis
differential. The basis differential contracts provide for the Company to
receive funds if the closing basis differential for the given month is greater
than the locked-in basis differential, and to pay funds if the differential is
less. During 2000, the Company locked-in the NYMEX to CIG basis differential on
approximately 8% of its 2000 production at an average differential of ($0.32).
See "Quantitative and Qualitative Disclosures about Market Risk" beginning on
page 27 of this report for additional disclosures, including the Company's open
derivative positions as of February 28, 2001.
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OILFIELD SERVICES
Prima conducts its oilfield services business under the name of Action
Oilfield Services in Colorado and Action Energy Services in Wyoming, both wholly
owned subsidiaries of the Company.
ACTION OILFIELD SERVICES. Action Oilfield Services ("AOS") has been active in
the Denver Basin since 1986. We own a field office and yard near LaSalle,
Colorado, and are conveniently located to service wells in the Denver Basin. AOS
owns various well servicing equipment including completion rigs, a swab rig,
tractor trailer rigs for water hauling, and oilfield rental equipment including
pumps, tanks, work strings, and blow out preventers. During 2000, we experienced
strong utilization of our people and equipment due to well recompletions,
re-works and drilling in the area. We intend to continue and grow our well
servicing activities in the Denver Basin. AOS provides services for Prima as
well as third party operators in the area. For the year ended December 31, 2000,
33% 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 2000 were
$4,184,000, or 8% of consolidated revenues.
ACTION ENERGY SERVICES. In the first quarter of 1999, Prima formed Action Energy
Services ("AES") to conduct well drilling and servicing activities in the Powder
River Basin. AES has an office and yard leased in Gillette, Wyoming. In addition
to well services traditionally offered by the Company, AES has six drilling
rigs. We intend to engage in both drilling and well servicing activities in the
Powder River Basin. Our services are offered to both Prima and third parties in
the area. During 2000, 43% of AES's revenues were from activities performed on
wells owned by Prima, and these revenues are accounted for in the same manner
noted for AOS. AES's third party revenues were $2,094,000 in 2000, and
represented 4% of the Company's consolidated revenues.
GATHERING SERVICES
ARETE GATHERING COMPANY, LLC. Prima formed Arete Gathering Company, LLC
("Arete") in the third quarter of 2000 to provide compression and gathering
services to the coalbed methane play in the Powder River Basin. At year end
2000, Arete was in the process of installing its first gathering system in
Prima's Stones Throw Area. As of the first quarter of 2001, Arete had installed
three low pressure screw compressors and one high pressure reciprocating
compressor to receive Prima's initial production from the area. The Stones Throw
area gathering system is designed initially to handle up to 14,000 MMBtu per
day, but can be expanded up to 21,000 MMBtu per day given its present design,
and approved air permits for compressors. The Company anticipates installing a
total of 5 to 6 screw compressors and 2 to 3 reciprocating compressors to handle
natural gas volumes from the area. We anticipate building additional systems in
the Powder River Basin as warranted by the size of our acreage block, proximity
to header systems and pipeline, and other factors which affect the economics of
each project. The Company cautions that in areas where it does not have a
significant and contiguous acreage block, and where other third party gathering
systems have already been installed, we may elect not to have Arete build a
gathering system. In areas where Arete has installed gathering, we will offer
gathering services to third parties.
PHYSICAL PROPERTIES
The Company leases its Denver office space at an average annual rate of
approximately $275,000 per year. 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, 2000 of $200,000.
Prima has also leased office space with shop and yard 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 $2,342,000 at December 31, 2000.
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The Company owns 160 acres of land in Weld County, Colorado near
LaSalle, Colorado. A 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,
2000, was $196,000. The service company and field operations own related
equipment, including completion rigs, swab rigs, tractor trailer rigs used for
water hauling, oilfield rental equipment and various oil field vehicles with a
net book value of $2,142,000 at December 31, 2000.
The Company is a 6% limited partner in a real estate limited
partnership which currently owns approximately 22 acres of undeveloped land in
Phoenix, Arizona, for investment and capital appreciation. The partnership owns
the 22 acres free and clear. The book value of this partnership interest was
$257,000 at December 31, 2000.
EMPLOYEES AND OFFICES
As of December 31, 2000, the Company had 134 full-time employees,
including 33 in its Denver office and 101 field employees. Of the field
employees, Action Oilfield Services employed 46 people, Action Energy Services
employed 38 people, and 17 were employed in Prima's field land, production and
pumping activities. Prima field employees handled work for Arete Gathering
Company. The Company believes its relations with its employees are good. Prima
also contracts the services of independent consultants involved in land,
geology, engineering, accounting, regulatory affairs, and other disciplines as
needed. The Company's principal executive offices are located at 1099 18th
Street, Suite 400, Denver, Colorado 80202.
ITEM 3. LEGAL PROCEEDINGS
The Company is engaged from time to time in legal proceedings in the
normal course of its daily business. At December 31, 2000, the Company does not
believe, based upon advise from legal counsel, that an adverse ruling in any
legal proceeding currently pending would have a material impact on the Company's
financial statements.
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, 2000.
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CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
Prima is including the following cautionary statement to take advantage
of the "safe harbor" provisions of the Private Securities Litigation Reform Act
of 1995 for any forward-looking statement made by, or on behalf of, the Company.
The factors identified in this cautionary statement are important factors (but
not necessarily all of the important factors) that could cause actual results to
differ materially from those expressed in any forward-looking statement made by,
or on behalf of, the Company. Where any such forward-looking statement includes
a statement of the assumptions or bases underlying such forward-looking
statement, the Company cautions that, while it believes such assumptions or
bases to be reasonable and makes them in good faith, assumed facts or bases
almost always vary from actual results, and the differences between assumed
facts or bases and actual results can be material, depending upon the
circumstances. Where, in any forward-looking statement, the Company, or its
management, expresses an expectation or belief as to the future results, such
expectation or belief is expressed in good faith and believed to have a
reasonable basis, but there can be no assurance that the statement of
expectation or belief will result, or be achieved or accomplished. The Company
does not undertake to update, revise or correct any of the forward-looking
information. Taking into account the foregoing, the following are identified as
important risk factors that could cause actual results to differ materially from
those expressed in any forward-looking statement made by, or on behalf of, the
Company:
VOLATILITY OF OIL AND NATURAL GAS PRICES. Historically, oil and natural
gas prices have been volatile and are likely to continue to be volatile. Prices
are affected by, among other things, market supply and demand factors, market
uncertainty, and actions of the United States and foreign governments and
international cartels. These factors are beyond the control of the Company.
During 2000, average oil and natural gas prices realized by the Company were 68%
and 73% higher than those received in 1999. To the extent that oil and gas
prices decline, the Company's revenues, cash flows, earnings and operations
would be adversely impacted. 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 independent engineers. These estimates are based on several
assumptions that the Securities and Exchange Commission requires oil and natural
gas companies to use, including for example, constant oil and natural gas
prices. 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 any oil or natural gas reserves
located by the Company in the future 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.
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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
42% of the Company's proved reserves at December 31, 2000, were located in the
Wattenberg Area of the Denver Basin, where wells are characterized by relatively
rapid decline rates. Additionally, approximately 46% of the Company's total
proved reserves at December 31, 2000, were undeveloped. Recovery of such
reserves will require significant capital 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.
HEDGING ACTIVITIES. Part of the Company's business strategy is to
periodically use both commodity futures contracts and price and basis swaps to
hedge the impact of the volatility of oil and natural gas prices on a portion of
its production and gas marketing activities. In certain circumstances,
significant reductions in production, due to unforeseen events, could require
the Company to make payments under the hedge agreements even though such
payments are not offset by production. To reduce this risk, the Company strives
to keep a percentage of its production unhedged. Hedging will also prevent the
Company from receiving the full advantage of increases in oil or natural gas
prices above the amount specified in the hedge agreement. Based upon average
daily production during 2000, the Company's hedge agreements covered
approximately 1% and 5% of the Company's daily average natural gas and oil
production, respectively.
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, atomic 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. 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 effect 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.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED STOCKHOLDER
MATTERS
(a) PRINCIPAL MARKET OR MARKETS. 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, 2000 and 1999. These prices
have been restated to reflect the effect of the three for two split of Prima's
common stock distributed on February 24, 2000 and the three for two split of
Prima's common stock distributed on December 11, 2000.
Year Ended December 31, 2000 HIGH LOW
---------------------------- ------- -------
Quarter Ended March 31, 2000.................. $18.500 $10.500
Quarter Ended June 30, 2000................... 36.917 15.167
Quarter Ended September 30, 2000.............. 37.833 20.708
Quarter Ended December 31, 2000............... 39.917 23.083
Year Ended December 31, 1999
----------------------------
Quarter Ended March 31, 1999.................. $ 6.944 $ 5.584
Quarter Ended June 30, 1999................... 10.111 5.778
Quarter Ended September 30, 1999.............. 11.389 9.167
Quarter Ended December 31, 1999............... 12.333 9.222
On February 28, 2001, the closing sale price for the Company's common
stock was $29.50 per share.
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.
(b) APPROXIMATE NUMBER OF HOLDERS OF COMMON STOCK. Prima's common
stockholders of record at February 28, 2001 totaled 1,054.
(c) DIVIDENDS. 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 2000, 1999 or 1998. 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.
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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.
Year Ended December 31,
--------------------------------------------------------
2000 1999 1998 1997 1996
-------- -------- -------- -------- --------
(in thousands, except per share data)
Income Statement Data:
Revenues:
Oil and gas sales ....................... $ 44,437 $ 20,644 $ 16,612 $ 17,840 $ 14,657
Oilfield services ....................... 6,278 4,974 4,148 3,214 2,269
Trading revenues ........................ 0 2,318 3,956 15,999 10,001
Interest, dividend and other ............ 1,464 1,286 4,378 854 794
-------- -------- -------- -------- --------
52,179 29,222 29,094 37,907 27,721
-------- -------- -------- -------- --------
Expenses:
Depreciation, depletion
and amortization:
Oil and gas properties ................ 6,150 4,650 6,260 4,935 4,210
Property and equipment ................ 1,054 817 616 497 334
Lease operating expense ................. 2,623 2,012 2,041 1,720 1,511
Ad valorem and production taxes ......... 3,421 1,765 1,272 1,355 981
Cost of oilfield services ............... 4,585 3,377 2,701 2,368 1,759
Cost of trading ......................... 0 2,827 3,936 15,323 9,060
General and administrative .............. 2,916 1,712 1,143 972 912
-------- -------- -------- -------- --------
20,749 17,160 17,969 27,170 18,767
-------- -------- -------- -------- --------
Income before income taxes ................ 31,430 12,062 11,125 10,737 8,954
Provision for income taxes ................ 9,535 3,035 3,060 2,635 2,285
-------- -------- -------- -------- --------
Net Income ................................ $ 21,895 $ 9,027 $ 8,065 $ 8,102 $ 6,669
======== ======== ======== ======== ========
Basic Net Income per Share ................ $ 1.72 $ 0.70 $ 0.62 $ 0.62 $ 0.51
======== ======== ======== ======== ========
Diluted Net Income per Share .............. $ 1.65 $ 0.69 $ 0.61 $ 0.61 $ 0.50
======== ======== ======== ======== ========
Cash Dividends per Share .................. $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.07
======== ======== ======== ======== ========
Balance Sheet Data (at end of period):
Total assets .............................. $104,900 $ 72,665 $ 66,866 $ 57,921 $ 48,006
Net property and equipment ................ 70,597 44,467 55,607 43,181 32,325
Long-term debt ............................ 0 0 120 240 0
Stockholders' equity ...................... 80,298 58,908 51,308 43,214 35,273
Working capital ........................... 25,718 21,408 5,467 7,952 7,863
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
This Item 7 contains "forward-looking statements" and 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 and estimates of future net cash flows attributable to proved reserves
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" beginning on page 19.
The following discussion is intended to assist in understanding the
Company's financial position and results of operations for each year in the
three year period ended December 31, 2000. The Consolidated Financial Statements
and notes thereto should be referred to in conjunction with this discussion.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal internal sources of liquidity are cash flows
generated from operations and existing cash and cash equivalents. Net cash
provided by operating activities totaled $36,376,000 for the year ended December
31, 2000, compared to $12,006,000 for the year ended December 31, 1999 and
$16,789,000 for the year ended December 31, 1998. Net working capital at
December 31, 2000 was $25,718,000 as compared to $21,408,000 at December 31,
1999. Current assets were $34,046,000 at December 31, 2000 compared to
$27,941,000 at December 31, 1999. Current liabilities were $8,328,000 at
December 31, 2000 compared to $6,533,000 at December 31, 1999. The Company had
gross proceeds from the sales of oil and gas properties and other equipment and
sales of securities of $27,871,000 in 1999. On January 21, 1999, Prima closed on
the sale of all of its interest in the Bonny Field acreage, wells, and gathering
system for $26 million ($20 million net of income taxes).
The Company has external borrowing capacity of $8,000,000 through an
unsecured line of credit with a commercial bank, all of which is available to be
drawn.
The Company invested $31,952,000 in additions to oil and gas properties
during the year ended December 31, 2000, compared to $18,617,000 during the year
ended December 31, 1999 and $18,147,000 during the year ended December 31, 1998.
During 2000, $29,332,000 was paid for the Company's share of development well
costs and recompletions, $642,000 for exploratory costs, $1,741,000 for
acquisitions of unproved properties and $237,000 for purchases of proved
properties. Other uses of funds in 2000 included $1,613,000 for purchases of
oilfield service equipment, facilities and office equipment, $1,935,000 for
treasury stock purchases and $249,000 for purchases of marketable securities.
The standardized measure of discounted future net cash flows of the
Company's proved oil and natural gas reserves increased to $371,121,000 at
December 31, 2000 as compared to $75,466,000 at December 31, 1999 and
$51,426,000 at December 31, 1998. Estimated future net cash flows from proved
oil and natural gas reserves increased to $975,940,000 at December 31, 2000
compared to $190,008,000 at December 31, 1999 and $115,801,000 at December 31,
1998. Oil reserve volumes at December 31, 2000 increased 14% and natural gas
reserve volumes increased 24% compared to December 31, 1999. On an Mcf
equivalent basis, 2000 reserves increased 23% to 176,546,000 Mcfe. The weighted
average natural gas price received at December 31, 2000 on Company production
was $7.51 per Mcf, an increase of $5.61 per Mcf compared to December 31, 1999.
The year end weighted average oil price was $26.48 per barrel, an increase of
$1.80 per barrel compared to December 31, 1999.
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The present value of estimated future net cash flows before future
income tax expense ("PV10") was $576 million at December 31, 2000, using the
above referenced year end prices for oil and natural gas. The PV10 was also
calculated using an alternate price case based upon five-year forward prices
averaging $3.78 per Mcf of natural gas and $22.21 per barrel of oil. The
resulting PV10 using these prices was $263 million at December 31, 2000 for the
Company's proved reserves.
At December 31, 2000, the Company estimated that capital expenditures
of $61,828,000 would be required to develop the Company's proved undeveloped and
proved developed non-producing reserves over the next several years.
Approximately $437,984,000, net of future development costs, of the estimated
future net cash flows of the Company's proved oil and gas reserves at December
31, 2000 were proved undeveloped reserves.
The Board of Directors of Prima approved two separate three for two
stock splits of the Company's common stock during 2000. The first was to
shareholders of record on February 10, 2000, distributed February 24, 2000. The
number of shares of common stock outstanding increased from 5,645,586 to
8,468,112 on February 24, 2000. The second was to shareholders of record on
November 27, 2000, distributed December 11, 2000. The number of shares of common
stock outstanding increased from 8,522,812 to 12,783,373 on December 11, 2000.
All share and per share amounts included in this Form 10-K have been restated to
show the retroactive effects of the stock splits.
The Company regularly reviews opportunities for acquisition of assets
or companies related to the oil and gas industry which could expand or enhance
its existing business. The Company expects its operations, including
acquisitions and drilling prospects, will be financed by funds provided from
operations, working capital, various cost-sharing arrangements, borrowings under
its line of credit or from other financing alternatives.
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. To the extent that oil and gas prices
decline, the Company's revenues, cash flows, earnings and operations would be
adversely impacted. The Company is unable to accurately predict future oil and
natural gas prices.
NEW ACCOUNTING PRONOUNCEMENTS
During June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards
for derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If certain conditions are met, a derivative may be
specifically designated as (a) a hedge of the exposure to changes in the fair
value of a recognized asset or liability or an unrecognized firm commitment, (b)
a hedge of the exposure to variable cash flows of a forecasted transaction, or
(c) a hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an available-for-sale security, or a
foreign-currency-denominated forecasted transaction. The accounting for changes
in the fair value of a derivative (gains and losses) depends on the intended use
of the derivative and the resulting designation. The Company adopted SFAS 133 on
January 1, 2001. The adoption of SFAS 133 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.
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25
RESULTS OF OPERATIONS
2000 VS 1999
For the year ended December 31, 2000, the Company earned net income 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
for the year ended December 31, 1999. Expenses 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.
Oil and gas sales for the year ended December 31, 2000 were $44,437,000
compared to $20,644,000 for the year ended December 31, 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 the year ended December 31, 2000 compared
to $2.10 per Mcf for the year ended December 31, 1999, an increase of $1.53 per
Mcf or 73%. The average price received per barrel of oil sold was $29.29 for
2000 compared to $17.42 for 1999, an increase of $11.87 per barrel or 68%.
During the year ended December 31, 2000, the Company hedged approximately 5% of
its oil production and 1% of its natural gas production. The purpose of these
hedges is to provide market price protection in the volatile environment of oil
and natural gas spot pricing. 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. During the year ended December 31, 1999, the Company hedged approximately
25% of its oil production and 15% of its natural gas production. Hedging losses
of $180,000 were included in oil and gas revenues for the year, which decreased
the average price received per barrel of oil by $0.17 and per Mcf of natural gas
by $0.02.
Oil and gas depletion charges are affected by capitalized costs,
estimated future development costs, production levels and changes in reserve
estimates. 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, 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 reflects higher drilling and operating costs
experienced during the fourth quarter of 2000. Depreciation of other fixed
assets was $1,054,000 and $817,000 for 2000 and 1999, respectively, and is
attributable to depreciation of service equipment, furniture and equipment and
buildings. Depreciation expense on these assets increased $237,000, or 29%, due
primarily to acquisitions of oilfield service equipment in 1999 and 2000.
Lease operating expenses ("LOE") were $2,623,000 for the year ended
December 31, 2000 compared to $2,012,000 for the year ended December 31, 1999.
Ad valorem and production taxes were $3,421,000 and $1,765,000 for the same
periods. Production taxes increase with higher production volumes and increased
product prices. Total lifting costs (LOE plus ad valorem and production taxes)
were 14% of oil and gas revenues and $0.53 per Mcfe for 2000 compared to 18% and
$0.42 for 1999.
Oilfield service revenues of $6,278,000 and $4,974,000 for the years
ended December 31, 2000 and 1999, respectively, represent the revenues from
third parties earned by Action Oilfield Services, Inc. and Action Energy
Services, wholly owned subsidiaries. These revenues include well servicing fees
from drilling, completion and swab rigs, trucking, water hauling, rental
equipment and other related activities. Revenues increased $1,304,000, or 26%
for 2000. Cost of oilfield services were $4,585,000 in 2000 compared to
$3,377,000 for 1999, an increase of $1,208,000 or 36%. Utilization levels in the
Wattenberg Area, where Action Oilfield Services is active, continue to be
strong. Action Energy Services was formed in March 1999 to provide services in
the Powder River Basin area of Wyoming. For the years ended December 31, 2000
and 1999, 37% and 26%, respectively, of the gross fees billed by the service
companies were for Company owned wells. The Company's share of fees paid to its
service companies on owned wells and the costs associated with providing the
services are eliminated in consolidation.
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26
Trading revenues and cost of trading represented 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 had no
buy-for-resale contracts in place during the year ended December 31, 2000.
General and administrative expense ("G&A"), net of third party
reimbursements, totaled $2,916,000 for the year ended December 31, 2000 compared
to $1,712,000 for the year ended December 31, 1999, an increase of $1,204,000 or
70%. In prior periods, the Company had presented management and operator fees as
revenue. These fees were earned pursuant to the Company's role as operator for
approximately 372 oil and gas wells located primarily in the Wattenberg Area of
Weld County, Colorado. The Company is paid operating fees by the other working
interest owners in the properties. Fees fluctuate with the number of wells
operated, the percentage working interest in a property owned by third parties,
and the amount of drilling activity during the period. In 2000, these fees were
reclassified and presented as reductions in G&A for all periods presented.
Management and operator fees were $426,000 and $619,000 during 2000 and 1999,
respectively. The Company's G&A expense has otherwise increased due to expansion
of the Company's area of operations. The Company capitalized geological and
geophysical costs of $180,000 during each of 2000 and 1999. Additionally, the
Company capitalized G&A costs of $1,200,000 and $780,000 in 2000 and 1999,
respectively, related primarily to its expansion in the Powder River Basin.
The provision for income taxes was $9,535,000 for the year ended
December 31, 2000 compared to $3,035,000 for the year ended December 31, 1999.
The effective tax rate was 30.3% in 2000 compared to 25.2% in 1999. The
Company's effective tax rates are 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 Company's effective tax
rate increased primarily because income before income taxes increased
$19,368,000 or 161% for 2000, while the permanent differences did not increase
proportionately.
1999 VS 1998
For the year ended December 31, 1999, the Company earned net income of
$9,027,000, or $0.69 per diluted share, on revenues of $29,222,000, compared to
net income of $8,065,000, or $0.61 per diluted share, on revenues of $29,094,000
for the year ended December 31, 1999. Expenses were $17,160,000 for 1999
compared to $17,969,000 for 1998. Revenues increased $128,000 or less than 1%,
expenses decreased $809,000 or 5% and net income increased $962,000 or 12% in
1999. During 1998, the Company received proceeds of $3,850,000 from the early
termination of a gas sales contract, which increased earnings by $2,500,000 and
earnings per diluted share by $0.19. Exclusive of this transaction, net income
for 1998 would have been $5,565,000 and earnings per diluted share would have
been $0.42.
Oil and gas sales for the year ended December 31, 1999 were $20,644,000
compared to $16,612,000 for the year ended December 31, 1998, an increase of
$4,032,000 or 24%. This increase was due to higher product prices and increased
production. The Company's net natural gas production was 7.2 Bcf for 1999
compared to 6.5 Bcf in 1998, an increase of 0.7 Bcf or 11%. The Company sold all
of its interests in the wells at the Bonny Field effective January 1, 1999.
Natural gas production increases net of Bonny were 16%. Net oil production was
322,000 barrels in 1999 compared to 286,000 barrels for 1998, an increase of
36,000 barrels or 13%. On an Mcfe basis, the Company's production for 1999
increased 900,000 Mcfe or 11%. The average price received per Mcf of natural gas
sold was $2.10 for the year ended December 31, 1999 compared to $2.00 per Mcf
for the year ended December 31, 1998, an increase of $.10 per Mcf or 5%.
Approximately 5% of the natural gas production for the year ended December 31,
1998, was attributable to production sold under a fixed contract price of $5.90
per MMBtu. The average price for the Company's natural gas production exclusive
of the fixed price contract gas was $1.81 per Mcf for the year ended December
31, 1998. The average price received per barrel of oil sold was $17.42 for 1999
compared to $12.71 for 1998, an increase of $4.71 per barrel or 37%. During the
year ended December 31, 1999, the Company hedged approximately 25% of its oil
production and 15% of its natural gas production. Hedging losses of $180,000 are
included in oil and gas revenues for the year, which decreased the average price
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27
received per barrel of oil by $0.17 and per Mcf of natural gas by $0.02. During
the year ended December 31, 1998, the Company hedged approximately 44% of its
natural gas production. Hedging losses of $112,000 decreased the average price
received per Mcf of natural gas by $0.02. No oil was hedged during this period.
The Company's depletion of oil and gas properties was $4,650,000 or
$0.51 per Mcfe on 9,093,000 equivalent Mcf produced in 1999, compared to
$6,260,000 or $0.76 per Mcfe on 8,193,000 equivalent Mcfe produced in 1998. The
lower depletion rate for 1999 reflects crediting capitalized costs of oil and
gas properties with the proceeds from the Bonny sale. The reserves from the
wells at the Bonny Field represented 6% of Prima's year end 1998 reserves.
Depreciation of other fixed assets was $817,000 and $616,000 for 1999 and 1998,
respectively, and is attributable to depreciation of service equipment,
furniture and equipment and buildings. Depreciation expense on these assets
increased $201,000, or 33%, due primarily to acquisitions of oilfield service
equipment in 1999.
Lease operating expenses ("LOE") were $2,012,000 for the year ended
December 31, 1999 compared to $2,041,000 for the year ended December 31, 1998.
Ad valorem and production taxes were $1,765,000 and $1,272,000 for the same
periods. Production taxes increase with higher production volumes and increased
product prices. Total lifting costs (LOE plus ad valorem and production taxes)
were 18% of oil and gas revenues and $0.42 per BOE for 1999 compared to 20% and
$0.40 for 1998.
Oilfield service revenues were $4,974,000 and $4,148,000 for the years
ended December 31, 1999 and 1998, respectively, an increase of $826,000, or 20%.
Cost of oilfield services were $3,377,000 for the year ended December 31, 1999
compared to $2,701,000 for the year ended December 31, 1998, an increase of
$676,000 or 25%. For the years ended December 31, 1999 and 1998, 26% and 21%,
respectively, of the gross fees billed by the service companies were for Company
owned wells.
Trading revenues were $2,318,000 for 1999 compared to $3,956,000 for
1998, a decrease of $1,638,000 or 41%. The Company marketed 1,311,000 MMBtus of
third party gas in 1999 compared to 1,823,000 MMBtus in 1998, a decrease of
512,000 MMBtus or 28%. Costs of trading were $2,827,000 for 1999 compared to
$3,936,000 for 1998, a decrease of $1,109,000 or 28%.
G&A, net of third party reimbursements, totaled $1,712,000 for the year
ended December 31, 1999 compared to $1,143,000 for the year ended December 31,
1998, an increase of $569,000 or 50%. Third party management and operator fees
for the years ended December 31, 1999 and 1998 were $619,000 and $1,044,000,
respectively, a decrease of $425,000 or 41%. The Company's G&A expense has
increased due to expansion of the Company's area of operations. The Company
capitalized geological and geophysical costs of $180,000 during each of 1999 and
1998. Additionally, the Company capitalized G&A costs of $780,000 and $380,000
in 1999 and 1998, respectively, related primarily to its expansion in the Powder
River Basin.
The provision for income taxes was $3,035,000 for the year ended
December 31, 1999 compared to $3,060,000 for the year ended December 31, 1998.
The effective tax rate was 25.2% in 1999 compared to 27.5% in 1998.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in the prices
received from sales of oil and natural gas. The Company's primary risk
management strategy is to partially mitigate the risk of adverse changes in its
cash flows caused by decreases in oil and natural gas prices by entering into
derivative commodity instruments, including commodity futures contracts and
price swaps. By hedging only a portion of its market risk exposures, the Company
is able to participate in the increased earnings and cash flows associated with
increases in oil and natural gas prices; however, it is exposed to risk on the
unhedged portion of its oil and natural gas production.
27
28
Historically, the Company has attempted to hedge the exposure related
to its forecasted oil and natural gas production in amounts which it believes
are prudent based on the prices of available derivatives and, in the case of
production hedges, the Company's deliverable volumes. The Company does not use
or hold derivative instruments for trading purposes nor does it use derivative
instruments with leveraged features. The Company's derivative instruments are
designed and effective as hedges against its identified risks, and do not of
themselves expose the Company to market risk because any adverse change in the
cash flows associated with the derivative instrument is accompanied by an
offsetting change in the cash flows of the hedged transaction.
Notes 1 and 6 to the financial statements provide further disclosure
with respect to derivatives and related accounting policies.
All derivative activity is carried out by personnel who have
appropriate skills, experience and supervision. The personnel involved in
derivative activity must follow prescribed trading limits and parameters that
are regularly reviewed by the Company's Chief Executive Officer. All hedges or
open positions are reviewed by the Chief Executive Officer before they are
committed to, and significant positions are reviewed by the Company's Board of
Directors. The Company uses only well-known, conventional derivative instruments
and attempts to manage its credit risk by entering into financial contracts with
reputable financial institutions.
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
hedging positions. It is not possible to accurately predict future movements in
oil and natural gas prices.
The Company periodically hedges a portion of the price risk associated
with the sale of its oil and natural gas production through the use of
derivative commodity instruments, which consist of commodity futures contracts
and price swaps. These instruments reduce the Company's exposure to decreases in
oil and natural gas prices on the hedged portion of its production by enabling
it to effectively receive a fixed price on its oil and natural gas sales. For
the period January 1, 2001 through February 28, 2001, the Company settled
derivative positions at a net gain of $515,000. This will be reflected in the
first quarter 2001 financial statements as an adjustment to natural gas prices
realized during the period. As of February 28, 2001, the Company had the
following open derivative positions in place:
Monthly Volume Unrealized
Type of Derivative (MMBtu) or (Bbls) Term Gain (Loss)
------------------------ ----------------- --------------------- ----------
Natural gas futures 300,000 April 2001 $140,300
Natural gas basis swaps 200,000 April 2001 10,000
Crude oil calls sold 15,000 April 2001 6,150
Natural gas basis swaps 240,000 April - November 2001 676,800
Crude oil calls sold 10,000 May 2001 3,700
Natural gas futures 200,000 May - September 2001 201,400
During 2000, the Company sold 440,000 barrels of oil. A hypothetical
decrease of $2.93 per barrel (10% of the average price received during the year)
would decrease the Company's production revenues by $1,289,000 during 2001,
assuming that oil production remains at 2000 levels. The Company sold 8.7 Bcf of
natural gas in 2000. A hypothetical decrease of $.36 per Mcf (10% of the average
price received during the year) would decrease the Company's production revenues
by $3,132,000 for 2001, assuming that natural gas production remains at 2000
levels.
28
29
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
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 16, 2001 and is hereby
incorporated by reference.
29
30
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 ................................................... 31
Consolidated Balance Sheets at December 31, 2000 and 1999 ...................... 32
Consolidated Statements of Income for the years ended
December 31, 2000, 1999 and 1998........................................... 34
Consolidated Statements of Comprehensive Income for the years ended
December 31, 2000, 1999 and 1998........................................... 35
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 2000, 1999 and 1998........................................... 36
Consolidated Statements of Cash Flows for the years ended
December 31, 2000, 1999 and 1998........................................... 37
Notes to Consolidated Financial Statements for the years ended
December 31, 2000, 1999 and 1998........................................... 38
(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.
EXHIBIT NO. DOCUMENT
3 Certificate of Amendment of the Certificate of
Incorporation of Prima Energy Corporation
(incorporated by reference as Exhibit 3.1 to Form
10-Q filed November 13, 2000)
10 Agreement of Lease between Denver-Stellar Associates
LP, Landlord and Prima Energy Corporation, Tenant,
effective December 1, 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, 2000, the
Company filed the following reports on Form 8-K:
o Report dated October 24, 2000, updating the Company's activities in the
Denver and Powder River Basins.
o Report dated November 7, 2000, reporting the declaration of a three for
two stock split of the Company's common stock. Record date for the
stock split was November 27, 2000 and the distribution date was
December 11, 2000.
o Report dated January 31, 2001, disclosing its preliminary capital
expenditures budget for 2001.
o Report dated February 15, 2001, reporting year end 2000 oil and natural
gas reserves and year 2000 production data.
30
31
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, 2000 and
1999, 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, 2000. 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, 2000 and 1999, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 2000 in conformity with accounting principles generally accepted in the
United States of America.
DELOITTE & TOUCHE LLP
March 9, 2001
Denver, Colorado
31
32
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2000 AND 1999
ASSETS
2000 1999
------------- -------------
CURRENT ASSETS
Cash and cash equivalents .............................. $ 20,382,000 $ 18,883,000
Available for sale securities, at market ............... 2,311,000 1,949,000
Receivables (net of allowance for doubtful
accounts: 2000, $44,000; 1999, $45,000) ............. 8,902,000 5,284,000
Tubular goods inventory ................................ 1,409,000 837,000
Other current assets ................................... 1,042,000 988,000
------------- -------------
Total current assets ............................. 34,046,000 27,941,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ...................... 109,652,000 77,700,000
Less accumulated depreciation,
depletion and amortization .......................... (43,935,000) (37,785,000)
------------- -------------
Oil and gas properties - net ..................... 65,717,000 39,915,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ............................. 7,664,000 6,814,000
Furniture and equipment ................................ 729,000 659,000
Field office, shop and land ............................ 473,000 481,000
------------- -------------
8,866,000 7,954,000
Less accumulated depreciation .......................... (3,986,000) (3,402,000)
------------- -------------
Property and equipment - net ..................... 4,880,000 4,552,000
------------- -------------
OTHER ASSETS ........................................... 257,000 257,000
------------- -------------
$ 104,900,000 $ 72,665,000
============= =============
See accompanying notes to consolidated financial statements.
32
33
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 2000 AND 1999
LIABILITIES AND STOCKHOLDERS' EQUITY
2000 1999
------------- -------------
CURRENT LIABILITIES
Accounts payable ....................................... $ 3,207,000 $ 2,085,000
Amounts payable to oil and gas property owners ......... 2,501,000 1,499,000
Ad valorem and production taxes payable ................ 1,857,000 1,210,000
Income taxes payable ................................... 0 1,051,000
Accrued and other liabilities .......................... 763,000 384,000
Current portion of note payable ........................ 0 304,000
------------- -------------
Total current liabilities ........................ 8,328,000 6,533,000
DEFERRED EXPENSE ....................................... 40,000 0
AD VALOREM TAXES, non-current .......................... 3,213,000 1,516,000
DEFERRED INCOME TAXES .................................. 13,021,000 5,708,000
------------- -------------
Total liabilities ................................ 24,602,000 13,757,000
------------- -------------
COMMITMENTS AND CONTINGENCIES (Note 9)
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; 18,000,000
shares authorized; 12,793,373 and
13,178,896 shares issued ............................ 192,000 198,000
Additional paid-in capital ............................. 1,760,000 5,628,000
Retained earnings ...................................... 78,472,000 56,577,000
Accumulated other comprehensive income (loss) .......... (126,000) (244,000)
Treasury stock, 0 and 322,305 shares at cost ........... 0 (3,251,000)
------------- -------------
Stockholders' equity - net ....................... 80,298,000 58,908,000
------------- -------------
$ 104,900,000 $ 72,665,000
============= =============
See accompanying notes to consolidated financial statements.
33
34
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998
----------- ----------- -----------
REVENUES
Oil and gas sales ............................ $44,437,000 $20,644,000 $16,612,000
Oilfield services ............................ 6,278,000 4,974,000 4,148,000
Trading revenues ............................. 0 2,318,000 3,956,000
Interest, dividend and other income .......... 1,464,000 1,286,000 4,378,000
----------- ----------- -----------
52,179,000 29,222,000 29,094,000
----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ....... 6,150,000 4,650,000 6,260,000
Depreciation of property and equipment .... 1,054,000 817,000 616,000
Lease operating expense ...................... 2,623,000 2,012,000 2,041,000
Ad valorem and production taxes .............. 3,421,000 1,765,000 1,272,000
Cost of oilfield services .................... 4,585,000 3,377,000 2,701,000
Cost of trading .............................. 0 2,827,000 3,936,000
General and administrative ................... 2,916,000 1,712,000 1,143,000
----------- ----------- -----------
20,749,000 17,160,000 17,969,000
----------- ----------- -----------
INCOME BEFORE INCOME TAXES ................... 31,430,000 12,062,000 11,125,000
PROVISION FOR INCOME TAXES ................... 9,535,000 3,035,000 3,060,000
----------- ----------- -----------
NET INCOME ................................... $21,895,000 $ 9,027,000 $ 8,065,000
=========== =========== ===========
BASIC NET INCOME PER SHARE ................... $ 1.72 $ 0.70 $ 0.62
=========== =========== ===========
DILUTED NET INCOME PER SHARE ................. $ 1.65 $ 0.69 $ 0.61
=========== =========== ===========
See accompanying notes to consolidated financial statements.
34
35
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998
------------ ------------ ------------
Net income ................................................. $ 21,895,000 $ 9,027,000 $ 8,065,000
------------ ------------ ------------
Other comprehensive income:
Unrealized gain (loss) on available-for-sale securities .... 170,000 (551,000) 12,000
Deferred income tax benefit (expense) related to
unrealized gain on available-for-sale securities .......... (70,000) 175,000 (3,000)
Reclassification adjustment for (gains) losses
included in net income ................................... 18,000 81,000 (2,000)
------------ ------------ ------------
118,000 (295,000) 7,000
------------ ------------ ------------
COMPREHENSIVE INCOME ....................................... $ 22,013,000 $ 8,732,000 $ 8,072,000
============ ============ ============
See accompanying notes to consolidated financial statements.
35
36
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Treasury
Stock Capital Earnings Income (Loss) Stock Total
-------- ----------- ----------- -------------- ----------- -----------
BALANCES, January 1, 1998............. $196,000 $ 4,276,000 $39,485,000 $ 44,000 $ (787,000) $43,214,000
Net income............................ 8,065,000 8,065,000
Exercise of stock options............. 0 23,000 23,000
Tax benefit from exercise of non-
qualified stock options............ 9,000 9,000
Other comprehensive income............ 7,000 7,000
Treasury stock purchased.............. (10,000) (10,000)
-------- ----------- ----------- --------- ----------- -----------
BALANCES, December 31, 1998........... 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
======== =========== =========== ========= =========== ============
See accompanying notes to consolidated financial statements.
36
37
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
2000 1999 1998
------------ ------------ ------------
OPERATING ACTIVITIES
Net income ................................................. $ 21,895,000 $ 9,027,000 $ 8,065,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization ................ 7,204,000 5,467,000 6,876,000
Deferred income taxes ................................... 7,319,000 2,281,000 2,238,000
Current taxes from sale of oil and gas properties ....... 0 (5,704,000) 0
Other ................................................... 745,000 551,000 (104,000)
Changes in operating assets and liabilities:
Receivables ........................................... (3,618,000) (588,000) 985,000
Inventory ............................................. (572,000) (225,000) 270,000
Other current assets .................................. (129,000) (374,000) (265,000)
Accounts payable and payables to owners ............... 2,124,000 489,000 (1,375,000)
Production taxes payable .............................. 2,344,000 86,000 81,000
Income taxes payable .................................. (1,051,000) 1,051,000 0
Accrued and other liabilities ......................... 115,000 (55,000) 18,000
------------ ------------ ------------
Net cash provided by operating activities .......... 36,376,000 12,006,000 16,789,000
------------ ------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties ........................ (31,952,000) (18,617,000) (18,147,000)
Purchases of other property ................................ (1,613,000) (2,673,000) (1,275,000)
Purchases of securities .................................... (249,000) (497,000) (540,000)
Proceeds from sales of property ............................ 223,000 27,483,000 130,000
Proceeds from sales of securities .......................... 57,000 388,000 28,000
------------ ------------ ------------
Net cash provided by (used in)
investing activities ............................ (33,534,000) 6,084,000 (19,804,000)
------------ ------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ................................... (1,935,000) (2,454,000) (10,000)
Proceeds from exercise of stock options .................... 592,000 845,000 23,000
Repayment of long-term debt ................................ 0 (120,000) (120,000)
------------ ------------ ------------
Net cash used in financing activities .............. (1,343,000) (1,729,000) (107,000)
------------ ------------ ------------
Increase (decrease) in cash and cash equivalents ........... 1,499,000 16,361,000 (3,122,000)
Cash and cash equivalents, beginning of year ............... 18,883,000 2,522,000 5,644,000
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year ..................... $ 20,382,000 $ 18,883,000 $ 2,522,000
============ ============ ============
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
============
See accompanying notes to consolidated financial statements.
37
38
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998
1. ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES
BUSINESS
Prima Energy Corporation ("Prima") is an independent oil and gas
company primarily engaged in the exploration for, 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
principally conducted 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, 2000.
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.
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 $2,722,000, $4,725,000 and $810,000 for
the years ended December 31, 2000, 1999 and 1998, respectively. Cash paid for
interest in 2000, 1999 and 1998 was $15,000, $37,000 and $20,000, respectively.
AVAILABLE FOR SALE SECURITIES
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.
INVENTORY
Inventory consists of various tubular goods 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 specific identification method.
38
39
OIL AND GAS PROPERTIES
The Company utilizes the full cost method of accounting for oil and gas
activities. Under this method, subject to a limitation based on estimated value,
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 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.
During January 1999, Prima sold all of its interests in the Bonny Field
located in Yuma County, Colorado, for approximately $26 million. Assets sold
included non-operated working interests ranging from 15.5% to 33.3% in 134
producing wells, interests in 16,253 gross acres and a 15.5% interest in the
gathering system for this field. The Company served as managing venturer and
operator of the gathering system through December 31, 1998. At year end 1998,
the Bonny Field represented approximately 6% of Prima's year end reserves.
Proceeds from the sale were reflected as a reduction in the carrying value of
oil and gas properties with no gain or loss recognized.
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 year end prices of oil and natural gas to
estimated future production of proved oil and gas reserves as of year end, less
estimated future expenditures to be incurred in developing and producing the
proved reserves and assuming continuation of existing economic conditions. 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 the equipment
sold upon abandonment of such properties. The Company's estimates are based upon
its historical experience and upon review of current properties and restoration
obligations.
PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost. Renewals and betterments
which 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, 3 to 15 years,
of the assets. 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 has
not recognized any impairment losses.
TRADING
The Company recognizes revenues and costs on natural gas trading
transactions at the point in time when gas is physically delivered and title is
transferred to the purchaser. During January 1998, the Company received proceeds
of $3,850,000 from the early termination of a long term natural gas supply
contract. The transaction released Prima's substantial dedication of natural gas
reserves and has been reflected in other income in the consolidated statement of
income. There were no natural gas trading activities in 2000.
RISK MANAGEMENT
The Company periodically uses commodity futures contracts and price
and/or basis swaps to hedge the impact of natural gas and oil price fluctuations
on a portion of its production and gas marketing activities. In order to qualify
for hedge accounting, the item to be hedged must expose the Company to price
risk (which is the sensitivity of the Company's income for one or more future
periods to changes in oil and gas spot
39
40
prices) and the financial contract must reduce the price exposure of the Company
and be designated as a hedge. Further, since the financial contracts for the
sale of oil and gas relate to anticipated transactions, the significant
characteristics and expected terms of the anticipated transaction must be
identified (i.e., expected date of the transaction, the commodity involved, and
the expected quantity to be purchased or sold) and it must be probable that the
anticipated transaction will occur. Gains and losses on hedging transactions are
deferred until the physical transaction occurs for financial reporting purposes.
Deferred gains and losses are evaluated in connection with the physical
transaction underlying the hedge position. Gains or losses on hedging activities
are recorded in the income statement as adjustments of the revenue or cost of
the underlying physical transaction. Hedging activities are reported as
operating activities in the statements of cash flows.
When the Company enters into swaps or commodities transactions that do
not correspond to anticipated physical transactions (anticipated physical
transactions include committed gas marketing activities or production from
producing wells), the transactions do not qualify for hedge accounting. In that
event, the Company records the instruments at fair value and gains or losses are
recorded as fair values fluctuate compared to cost.
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. Oil and gas industry legislation and administrative
regulations are periodically changed for a variety of political, economic and
other reasons. As of December 31, 2000, the Company had not been fined or cited
for any violations of governmental regulations which would have a material
adverse effect upon the financial condition, capital expenditures, earnings or
competitive position of the Company in the oil and gas industry.
MANAGEMENT, OPERATOR AND OILFIELD SERVICE FEES
The Company recognizes income from operating wells for third parties
pursuant to the applicable operating agreements when the services are performed.
Oilfield services fees are recognized as income when the services are performed
for third parties.
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
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133") is effective January
1, 2001 for the Company. SFAS 133 establishes accounting and reporting standards
for derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. If the derivative is designated as a fair-value
hedge, the changes in the fair value of the derivative and the hedged item will
be recognized in earnings. If the derivative is designated as a cash-flow hedge,
changes in the fair value of the derivative will be recorded in other
comprehensive income and will be recognized in the income statement when the
hedged item affects earnings. SFAS 133 defines new requirements for designation
and documentation of hedging relationships
40
41
as well as ongoing effectiveness assessments in order to use hedge accounting.
For a derivative that does not qualify as a hedge, changes in fair value will be
recognized in earnings.
The Company adopted SFAS 133 on January 1, 2001. In connection with the
adoption of SFAS 133, all derivatives within the Company were identified
pursuant to SFAS 133 requirements. The Company determined that all of its oil
and gas commodity swaps and futures contracts should be designated as cash flow
hedges. Since the Company's swaps and futures contracts are designated as cash
flow hedges, changes in the fair value of the derivatives will be recognized in
other comprehensive income until the hedged item is recognized in earnings.
Hedge effectiveness will be measured based on the relative changes in the fair
value between the derivative contract and the hedged item over time. Any changes
in fair value resulting from ineffectiveness, as defined by SFAS 133, will be
recognized immediately in current earnings.
The Company also has basis swaps to protect against a significant
decrease in prices received in the Rocky Mountains versus NYMEX settlement at
Henry Hub. Changes in fair value, to the extent these basis swaps are not
associated with production and a NYMEX futures contract, will be
marked-to-market and recognized in earnings immediately.
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.
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).
2. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
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 of those investments.
Natural gas derivative contracts were not recorded on the balance sheet
at December 31, 2000. The fair value of the Company's current asset was
estimated to be $1,241,000 and the fair value of its current liability was
estimated to be $549,000 as a result of these contracts. The estimated fair
value of the natural gas derivative contracts is determined by multiplying the
difference between year end natural gas prices and the hedge contract price by
the quantities under contract. At December 31, 1999, there were no outstanding
hedges.
3. AVAILABLE FOR SALE SECURITIES
The Company's available for sale securities are comprised of marketable
equity securities. For the years ended December 31, 2000 and 1999, the Company
sold securities with a market value of $57,000 and $388,000 which resulted in
realized losses of $18,000 and $81,000, respectively. The net unrealized gain or
loss on securities at December 31, 2000 and 1999 is included in accumulated
other comprehensive income, net of deferred income taxes of $(75,000) and
$(145,000), respectively. The change in net unrealized gain or loss on
securities for the years ended December 31, 2000 and 1999 was determined as
follows:
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42
2000 1999
----------- -----------
Net unrealized gain (loss), beginning of year .... $ (389,000) $ 81,000
Net unrealized gain (loss), end of year .......... (201,000) (389,000)
----------- -----------
Net change in unrealized gain or loss ............ $ 188,000 $ (470,000)
=========== ===========
The components of fair value as of December 31, 2000 and 1999 are as follows:
2000 1999
----------- -----------
Cost (including reinvested distributions) ........ $ 2,512,000 $ 2,338,000
Gross unrealized gains ........................... 43,000 0
Gross unrealized losses .......................... (244,000) (389,000)
----------- -----------
Fair value ....................................... $ 2,311,000 $ 1,949,000
=========== ===========
4. NOTES PAYABLE AND LINE OF CREDIT
The Company had two notes payable at December 31, 1999 totaling
$304,000. Both notes were paid in full during the year ended December 31, 2000
pursuant to their terms.
Prima maintains an $8,000,000 unsecured line of credit with a
commercial bank. The line of credit, which matures on May 1, 2001, bears
interest at the bank's prime rate (9.5% at December 31, 2000 and 8.5% at
February 28, 2001), with interest payable monthly. At December 31, 2000 and
1999, there were no amounts outstanding under the line of credit.
5. EARNINGS PER SHARE
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, 2000:
Basic Net Income per Share ...... $21,895,000 12,748,917 $1.72
=====
Effect of Stock Options ......... 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 ......... 282,647
----------- -----------
Diluted Net Income per Share .... $ 9,027,000 13,136,843 $0.69
=========== =========== =====
Year Ended December 31, 1998:
Basic Net Income per Share ...... $ 8,065,000 12,986,647 $0.62
=====
Effect of Stock Options ......... 296,352
----------- -----------
Diluted Net Income per Share .... $ 8,065,000 13,282,999 $0.61
=========== =========== =====
The Board of Directors of Prima approved two separate three for two
stock splits of the Company's common stock during 2000. The first was to
shareholders of record on February 10, 2000, distributed February 24, 2000. The
number of shares of common stock outstanding increased from 5,645,586 to
8,468,112 on February 24, 2000. The second was to shareholders of record on
November 27, 2000, distributed December 11, 2000. The number of shares of common
stock outstanding increased from 8,522,812 to 12,783,373 on December 11, 2000.
All share and per share amounts included in these financial statements have been
restated to show the retroactive effects of the stock splits.
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43
During 2000, the Company purchased 108,150 shares of its common stock
for the 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 new repurchase program of up to 5% of the
common stock then currently outstanding. In January 2001, the Company purchased
62,000 treasury shares for $1,625,000.
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.
6. RISK MANAGEMENT
Crude oil and natural gas futures, options and swaps are used from time
to time in order to hedge the price of a portion of the Company's production and
purchases for resale. This is done to mitigate the risk of fluctuating oil and
natural gas prices which can adversely affect operating results. These
transactions have been entered into with major financial institutions, thereby
minimizing credit risk. The Company hedged approximately 1%, 15% and 44% of its
natural gas production in 2000, 1999 and 1998. The Company hedged approximately
5% and 25% of its oil production in 2000 and 1999. No oil was hedged in 1998.
Net hedging gains and losses of $42,000, $(180,000) and $(112,000) were
recognized in 2000, 1999 and 1998, respectively. The Company had open positions
at December 31, 2000 as follows:
Volume Unrealized
Type of Derivative (MMBtu) Term Gain (Loss)
----------------------- --------- --------------------- ------------
Natural gas futures 350,000 January 2001 $(569,700)
Natural gas basis swaps 360,000 January 2001 317,000
Natural gas futures 100,000 February 2001 21,100
Natural gas basis swaps 360,000 February - March 2001 333,000
Natural gas basis swaps 1,920,000 April - November 2001 590,400
7. INCOME TAXES
The provision for income taxes consists of the following components:
Year Ended December 31,
-------------------------------------
2000 1999 1998
---------- ---------- ----------
Current:
Federal........................... $2,114,000 $5,340,000 $ 679,000
State............................. 102,000 1,118,000 143,000
---------- ---------- ----------
2,216,000 6,458,000 822,000
========== ========== ==========
Deferred:
Federal........................... 6,656,000 (4,828,000) 2,440,000
State............................. 382,000 (652,000) 321,000
---------- ---------- ----------
7,038,000 (5,480,000) 2,761,000
========== ========== ==========
Tax credits.......................... 281,000 2,057,000 (523,000)
---------- ---------- ----------
Provision for income taxes........... $9,535,000 $3,035,000 $3,060,000
========== ========== ==========
During 2000, 1999 and 1998, the Company recognized income tax
deductions of $1,946,000, $1,247,000 and $23,000, respectively, from the
exercise of nonqualified stock options. Stockholders' equity has been credited
in the amount of $720,000, $477,000 and $9,000 for the income tax benefit of
these deductions.
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The significant components of deferred tax assets and deferred tax
liabilities included in the balance sheet are as follows:
2000 1999
----------- -----------
Deferred Tax Assets:
Minimum tax credit carryforwards .... $ 1,336,000 $ 1,617,000
State income taxes .................. 395,000 261,000
Other ............................... 109,000 180,000
----------- -----------
Total Deferred Tax Assets ........... 1,840,000 2,058,000
----------- -----------
Deferred Tax Liabilities:
Intangible drilling costs ........... 13,916,000 6,780,000
Depreciation ........................ 492,000 287,000
Other ............................... 362,000 533,000
----------- -----------
Total Deferred Tax Liabilities ...... 14,770,000 7,600,000
----------- -----------
$12,930,000 $ 5,542,000
=========== ===========
A reconciliation of income tax computed at the federal statutory tax
rate to the Company's effective tax rate is as follows:
Year Ended December 31,
------------------------
2000 1999 1998
---- ---- ----
Federal statutory income tax rate ....... 34.0% 34.0% 34.0%
Percentage depletion .................... (1.5) (2.2) (1.7)
Section 29 credits ...................... (3.1) (10.5) (7.9)
State taxes, net of federal benefits .... 1.0 2.6 2.7
Other ................................... (0.1) 1.3 0.4
---- ---- ----
Effective tax rate .................. 30.3% 25.2% 27.5%
==== ==== ====
At December 31, 2000, the Company had minimum tax credit carryforwards
of approximately $1,336,000, which may by carried forward indefinitely.
8. 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. 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,
2000, 1999 and 1998. 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.
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2000 1999 1998
------------ ------------ ------------
Revenues
Oil and gas ....................................... $ 44,437,000 $ 20,644,000 $ 16,612,000
Oilfield services ................................. 9,912,000 6,764,000 5,222,000
Marketing and trading ............................. 0 2,318,000 7,806,000
------------ ------------ ------------
Total ........................................... 54,349,000 29,726,000 29,640,000
Corporate revenues ................................ 1,464,000 1,286,000 528,000
Intersegment sales ................................ (3,634,000) (1,790,000) (1,074,000)
------------ ------------ ------------
Per financial statements ....................... $ 52,179,000 $ 29,222,000 $ 29,094,000
============ ============ ============
Operating Earnings
Oil and gas ....................................... $ 32,243,000 $ 12,217,000 $ 7,039,000
Oilfield services ................................. 844,000 984,000 1,007,000
Marketing and trading ............................. 0 (511,000) 3,854,000
------------ ------------ ------------
Total ........................................... 33,087,000 12,690,000 11,900,000
Corporate earnings ................................ (1,657,000) (628,000) (775,000)
------------ ------------ ------------
Per financial statements ........................ $ 31,430,000 $ 12,062,000 $ 11,125,000
============ ============ ============
Identifiable Assets
Oil and gas ....................................... $ 65,717,000 $ 39,915,000 $ 52,946,000
Oilfield services ................................. 5,482,000 5,757,000 3,160,000
Marketing and trading ............................. 0 0 282,000
------------ ------------ ------------
Total ........................................... 71,199,000 45,672,000 56,388,000
Corporate assets .................................. 33,701,000 26,993,000 10,478,000
------------ ------------ ------------
Per financial statements ........................ $104,900,000 $ 72,665,000 $ 66,866,000
============ ============ ============
Depreciation, Depletion and Amortization Expense
Oil and gas ....................................... $ 6,150,000 $ 4,650,000 $ 6,260,000
Oilfield services ................................. 851,000 627,000 447,000
------------ ------------ ------------
Total ........................................... 7,001,000 5,277,000 6,707,000
Corporate ......................................... 203,000 190,000 169,000
------------ ------------ ------------
Per financial statements ........................ $ 7,204,000 $ 5,467,000 $ 6,876,000
============ ============ ============
Capital Expenditures
Oil and gas ....................................... $ 31,952,000 $ 18,617,000 $ 18,147,000
Oilfield services ................................. 1,235,000 2,600,000 933,000
------------ ------------ ------------
Total ........................................... 33,187,000 21,217,000 19,080,000
Corporate ......................................... 378,000 257,000 342,000
------------ ------------ ------------
Per financial statements ........................ $ 33,565,000 $ 21,474,000 $ 19,422,000
============ ============ ============
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
and 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, receivables and available for sale securities.
The following customers have each accounted for over 10% of the
Company's consolidated revenues and are from the identified operating segment.
Following is a table summarizing the percentage of sales made to each customer.
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.
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2000 1999 1998
---- ---- ----
Oil and Gas:
Duke Energy Field Services, Inc. .... 36% 28% 19%
Ultramar Diamond Shamrock ........... 21 15 n/a
Marketing and Trading:
Colorado Power Partnership .......... n/a n/a 25
9. COMMITMENTS AND CONTINGENCIES - OFFICE LEASE
The Company signed a new lease and relocated its office space effective
December 1, 2000. The new lease is for a term of seven years, with an option to
renew for an additional five years. Rental expense, net of sublease rental
income in 1998, totaled $187,000, $155,000 and $126,000 for the years ended
December 31, 2000, 1999 and 1998, respectively. Future minimum annual rentals
under the non-cancelable operating lease for the initial seven year term are as
follows:
Year ending December 31, 2001................... $ 130,000
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
----------
$1,944,000
==========
10. BENEFIT PLANS
EMPLOYEE STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan, 1,350,000
shares of Prima's common stock are reserved for issuance to key employees at
fair market value on the date of grant. Options granted under the plan vest at
20% per year for five years, and expire 10 years from the date of grant. At
December 31, 2000, options to acquire 911,975 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 $3.92 to $9.39 per share, with a
weighted average price of $5.47 per share. The weighted average fair value of
options granted during 1999 and 1998 was $5.54 and $3.71, respectively. No
employee stock options were granted in 2000. As of December 31, 2000, the
weighted average remaining contractual life of the options outstanding is 5
years, 2 months. A summary of options granted, exercised and outstanding during
1998, 1999 and 2000 is as follows:
Number Weighted Average
of Shares Exercise Prices
--------- ---------------
Balance at December 31, 1997 ........ 798,750 $4.09
Granted during 1998 ................. 389,250 7.30
Exercised or canceled ............... (5,625) 4.15
---------
Outstanding at December 31, 1998 .... 1,182,375 5.15
Granted during 1999 ................. 30,375 9.39
Exercised or canceled ............... (208,125) 4.06
---------
Outstanding at December 31, 1999 .... 1,004,625 5.50
Exercised or canceled ............... (92,650) 5.62
---------
Outstanding at December 31, 2000 .... 911,975 5.47
=========
Exercisable at December 31, 1998 .... 684,000 4.04
Exercisable at December 31, 1999 .... 622,350 4.48
Exercisable at December 31, 2000 .... 655,925 4.71
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NON-EMPLOYEE DIRECTORS' STOCK OPTION PLAN
The Board of Directors adopted and the shareholders approved the Prima
Energy Corporation Non-Employee Directors' Stock Option Plan effective
September 18, 1998. The plan reserves 225,000 shares of Prima's common stock 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 under the plan vest at 20% per year for five years, and
expire 10 years from the date of grant. At December 31, 2000, options to acquire
146,250 shares of the Company's common stock were outstanding under the plan.
The exercise prices range from $6.67 to $32.33 per share. The weighted average
fair value of options granted during 2000, 1999 and 1998 was $20.47, $5.54 and
$3.39, respectively. As of December 31, 2000, the weighted average remaining
contractual life of the options outstanding is 8 years, 7 months. A summary of
options granted, exercised and outstanding during 1998, 1999 and 2000 is as
follows:
Number Weighted Average
of Shares Exercise Prices
--------- ---------------
Balance at December 31, 1997 ........ 0 n/a
Granted during 1998 ................. 90,000 $ 6.67
--------
Outstanding 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
========
Exercisable at December 31, 1998 .... 0 n/a
Exercisable at December 31, 1999 .... 18,000 6.67
Exercisable at December 31, 2000 .... 30,375 7.02
RECOGNITION OF COMPENSATION EXPENSE
The Company 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. Had compensation expense been determined based on the fair
value at the grant date for the options awarded in 2000, 1999 and 1998 and 1995
consistent with the provisions of SFAS 123, considering the vesting thereof, the
Company's net income and net income per share would have been reduced to the pro
forma amounts indicated below:
2000 1999 1998
----------- ---------- ----------
Net income
As reported ............... $21,895,000 $9,027,000 $8,065,000
Pro forma ................. 21,585,000 8,750,000 7,999,000
Basic net income per share
As reported ............... $ 1.72 $ 0.70 $ 0.62
Pro forma ................. 1.69 0.68 0.62
Diluted net income per share
As reported ............... $ 1.65 $ 0.69 $ 0.61
Pro forma ................. 1.62 0.67 0.61
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The fair value of the options for disclosure purposes was estimated on
the date of the grant using the Black-Scholes Model with the following
assumptions:
2000 1999 1998
---- ---- ----
Expected dividend yield ................ 0% 0% 0%
Expected price volatility .............. 76% 37% 30%
Risk free interest rate ................ 6.1% 6.8% 5.5%
Expected life of options (in years) .... 9 9 9
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 investment options. The ESOP benefits
all full-time employees and includes six year, 100% vesting provisions. For the
years ended December 31, 2000, 1999 and 1998, the Company expensed $283,000,
$224,000 and $193,000, respectively, of contributions payable to the Plan.
11. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited
partnership which currently 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, 2000 and 1999 was
$257,000. During the three years ended December 31, 2000, the Company did not
make any capital contributions to the partnership, nor receive any distributions
therefrom.
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 these same transactions with unrelated parties.
The Company, a director of Prima and an unrelated third party were
working interest owners in the wells at the Bonny Field and joint venturers in
Bonny Gathering Company. The director sold his interest in
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the wells and the joint venture at the same time as the Company and the
unrelated third party. The director participated in the original development of
the field in 1982 and in the construction and the renovation of the gathering
system and continued as a working interest owner and joint venturer until the
sale in January 1999.
In June 2000, the Company acquired 26,680 net acres from a company
controlled by a director of Prima for a negotiated price of $12 per net acre (a
total cost to the Company of $320,000). Subsequent lease acquisitions by Prima
were made at cost, including third party costs. Total cost of all leases
acquired in 2000 was $376,000. All leases acquired were subject to an overriding
royalty reserved by the director and other entities controlled by him, of 3% or
less, depending on the net revenue interest of the leases and proportionate to
the working interest acquired. The transaction was approved by the disinterested
members of the Board of Directors.
12. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
Year Ended December 31,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Acquisition costs:
Unproved properties ........................... $ 1,741,000 $ 3,347,000 $ 5,169,000
Proved properties ............................. 237,000 123,000 394,000
Exploration costs ............................... 642,000 1,731,000 1,082,000
Development costs ............................... 29,332,000 13,416,000 11,502,000
----------- ----------- -----------
Total ........................................ $31,952,000 $18,617,000 $18,147,000
=========== =========== ===========
Amortization per equivalent
Mcf of production ............................. $ 0.54 $ 0.51 $ 0.76
=========== =========== ===========
Results of operations for oil and gas producing activities are as
follows:
Year Ended December 31,
-----------------------------------------
2000 1999 1998
----------- ----------- -----------
Revenues
Oil and gas sales ............................. $44,437,000 $20,644,000 $16,612,000
----------- ----------- -----------
Expenses
Lease operating expense ....................... 2,623,000 2,012,000 2,041,000
Ad valorem and production taxes ............... 3,421,000 1,765,000 1,272,000
Depletion of oil and gas properties ........... 6,150,000 4,650,000 6,260,000
----------- ----------- -----------
12,194,000 8,427,000 9,573,000
----------- ----------- -----------
Income before income taxes ...................... 32,243,000 12,217,000 7,039,000
Income tax expense .............................. 9,770,000 3,079,000 1,936,000
----------- ----------- -----------
Income from oil and gas producing activities .... $22,473,000 $ 9,138,000 $ 5,103,000
=========== =========== ===========
The reserve information presented below was prepared by independent
engineers for the years ended December 31, 2000, 1999 and 1998. 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.
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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.
Proved oil and gas reserves of the Company, all of which are located
in the United States, are as follows:
Year Ended December 31,
-------------------------------------------------------------------------
2000 1999 1998
--------------------- --------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
-------- -------- -------- -------- -------- --------
Proved reserves:
Beginning of year ................ 3,268 124,111 2,826 71,207 3,358 63,490
Purchases of oil and
gas reserves in place .......... 40 684 16 318 26 492
Revisions of previous
estimates ...................... (259) (5,969) (83) (2,600) (938) (5,163)
Extensions, discoveries and
other additions ................ 1,145 44,583 862 68,160 666 18,877
Production ....................... (440) (8,683) (322) (7,163) (286) (6,476)
Sales of oil and gas reserves
in place ....................... (25) (554) (31) (5,811) 0 (13)
-------- -------- -------- -------- -------- --------
End of Year ...................... 3,729 154,172 3,268 124,111 2,826 71,207
======== ======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year ................ 2,521 54,079 2,305 51,538 2,286 48,139
End of year ...................... 2,945 77,385 2,521 54,079 2,305 51,538
Oil and natural gas prices in effect at each year end used in
calculating reserve estimates are as follows:
2000 1999 1998
------ ------ ------
Natural gas (per Mcf)........ $ 7.51 $ 1.90 $ 2.13
Oil (per barrel)............. 26.48 24.68 10.31
Standardized measures of discounted future net cash flows relating to
proved oil and gas reserves are as follows:
Year Ended December 31,
----------------------------------------------------
2000 1999 1998
-------------- -------------- --------------
Future cash inflows ................... $1,256,037,000 $ 316,417,000 $ 181,082,000
Future production costs ............... (218,269,000) (90,302,000) (44,940,000)
Future development costs .............. (61,828,000) (36,107,000) (20,341,000)
-------------- -------------- --------------
Future net cash flows ................. 975,940,000 190,008,000 115,801,000
10% discount factor ................... (399,888,000) (81,457,000) (50,483,000)
Discounted future income taxes ........ (204,931,000) (33,085,000) (13,892,000)
-------------- -------------- --------------
Standardized measure of discounted
future net cash flows .............. $ 371,121,000 $ 75,466,000 $ 51,426,000
============== ============== ==============
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The principal sources of change in the standardized measure of
discounted future net cash flows are as follows:
Year Ended December 31,
-------------------------------------------------
2000 1999 1998
------------- ------------- -------------
Beginning standardized measure ..................... $ 75,466,000 $ 51,426,000 $ 58,149,000
Sales of oil and gas produced,
net of production costs ......................... (38,392,000) (16,867,000) (13,299,000)
Net changes in prices and production costs ......... 326,085,000 22,566,000 (17,963,000)
Extensions, discoveries, and improved
recovery, less related costs .................... 169,061,000 42,530,000 16,262,000
Development costs incurred during the year ......... 12,128,000 6,373,000 4,829,000
Changes in estimated future development costs ...... 921,000 2,267,000 4,192,000
Revisions of previous quantity
estimates and other ............................. (13,608,000) (6,362,000) (10,521,000)
Purchases of reserves in place ..................... 4,439,000 469,000 464,000
Sales of reserves in place ......................... (680,000) (12,886,000) (1,000)
Accretion of discount .............................. 7,547,000 5,143,000 5,815,000
Net change in income taxes ......................... (171,846,000) (19,193,000) 3,499,000
------------- ------------- -------------
Ending standardized measure ........................ $ 371,121,000 $ 75,466,000 $ 51,426,000
============= ============= =============
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 2000 and 1999.
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
Three Months Ended
--------------------------------------------------------
3/31/00 6/30/00 9/30/00 12/31/00
----------- ----------- ----------- -----------
Year Ended December 31, 1999
Revenues ........................ $ 5,549,000 $ 6,697,000 $ 8,076,000 $ 8,900,000
Gross profit .................... 1,816,000 1,949,000 2,823,000 4,188,000
Net income ...................... 1,515,000 1,776,000 2,389,000 3,347,000
Basic net income per share ...... 0.12 0.14 0.19 0.26
Diluted net income per share .... 0.11 0.13 0.18 0.25
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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 13th day of March, 2001.
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 Chairman, President, Treasurer, March 13, 2001
------------------------- (Principal Executive and
Richard H. Lewis Financial Officer)
/s/ Robert E. Childress Director March 13, 2001
-------------------------
Robert E. Childress
/s/ James R. Cummings Director March 13, 2001
-------------------------
James R. Cummings
/s/ Douglas J. Guion Director March 13, 2001
-------------------------
Douglas J. Guion
/s/ Catherine B. James Director March 13, 2001
-------------------------
Catherine B. James
/s/ George L. Seward Director March 13, 2001
-------------------------
George L. Seward
/s/ Sandra J. Irlando Vice President of Accounting March 13, 2001
------------------------- and Controller
Sandra J. Irlando
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INDEX TO EXHIBITS
EXHIBIT NO. DOCUMENT
3 Certificate of Amendment of the Certificate of
Incorporation of Prima Energy Corporation
(incorporated by reference as Exhibit 3.1 to Form
10-Q filed November 13, 2000)
10 Agreement of Lease between Denver-Stellar Associates
LP, Landlord and Prima Energy Corporation, Tenant,
effective December 1, 2000
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP