<PAGE> 1
================================================================================
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, 1999.
[ ] 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)
1801 BROADWAY, SUITE 500, 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 4,912,428 shares of Common Stock held by
non-affiliates of the Registrant as of March 10, 2000 was $109,608,550 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).
As of March 10, 2000, Registrant had outstanding 8,467,744 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 2000 Annual Meeting of
Stockholders.
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
ITEM PAGE
- ---- ----
PART I
<S> <C>
1. and 2. BUSINESS and PROPERTIES ........................................ 3
3. LEGAL PROCEEDINGS ...................................................... 16
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS .................... 16
PART II
5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS .................................................... 19
6. SELECTED FINANCIAL DATA ................................................ 20
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS .................................... 21
7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ............ 26
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA ............................ 27
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE .................................... 27
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT .................... 27
11. EXECUTIVE COMPENSATION ................................................ 27
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT ............................................................ 27
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS ........................ 27
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K .............................................................. 28
</TABLE>
2
<PAGE> 3
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, 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 17.
GENERAL - THE COMPANY
Prima was incorporated in April 1980 as a start-up company 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.
Prima's oil and gas exploration, development and production activities
are conducted by Prima Oil & Gas Company, a wholly owned subsidiary. Crude oil
and natural gas marketing and trading is conducted by Prima Natural Gas
Marketing, Inc., a wholly owned subsidiary of Prima Oil & Gas Company. Action
Oil Field Services, Inc. and Action Energy Services, wholly owned subsidiaries
of Prima Oil & Gas Company, are involved in various aspects of the oilfield
service and drilling business.
The Board of Directors of Prima approved a three for two stock split of
its common stock 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 5,645,341 to 8,467,744 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 split.
Prima remains focused on the Rocky Mountain Region as its area of
expertise. The Company's oil and gas operating activities are conducted in the
Denver Basin in northeast Colorado, the Powder River Basin in northeast Wyoming,
and the Wind River Basin in central Wyoming. Prima operates wells in each of
these areas, with the majority of operated wells being located in the Denver
Basin. We have been active in the Denver Basin since 1982, operate 359 wells in
the area, and remain a significant producer in the play. We own both operated
and non-operated interests in the Powder River and Wind River Basins, and have
been active in the areas for the past several years. Prima also has leased
undeveloped acreage in the Green River Basin located in southwest Wyoming and
the Big Horn Basin of north central Wyoming.
Prima has established a significant leasehold position of approximately
148,000 gross, 138,000 net acres in the shallow coalbed methane play located in
the Powder River Basin. We believe this is one of the most active, visible, and
regulated plays in the United States. During 1999, the Company began evaluating
its acreage with selective drilling, and started well servicing activities in
this area. More detail is reported on our activity in this area under
"Properties - Powder River Basin Coalbed Methane" and "Oilfield Services" in
this document.
3
<PAGE> 4
At December 31, 1999, the Company reported the following:
o $72,665,000 of assets.
o 144 Bcfe (24 MMBOE) of proved reserves with a pretax present value
(discounted at 10%) of $109 million using average year end prices of
$24.68 per barrel and $1.90 per Mcf held constant over the estimated
economic life of each of the proved properties.
o Cash flow provided by operating activities was $12,006,000. Cash flow
was reduced by $5.7 million of income taxes paid resulting from the $26
million sale of the Bonny Field assets.
o 1999 average daily production of 19,625 Mcf of natural gas and 882
barrels of crude oil (24,911 Mcfe or 4,151 BOE) per day.
o 1999 average price realizations of $2.10 per Mcf of natural gas, and
$17.42 per barrel of crude oil.
o Operations of 372 wells representing 88% of the wells in which Prima
owns an interest.
o 21,226 gross, 15,439 net developed acres,
o 421,271 gross, 276,327 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 creating,
identifying and evaluating 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 producers in the
area.
OPERATIONS. It is an objective of the Company to operate, when possible, 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 eighteen
years, and refracturing wells in the area for over five 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.
EXPLORATION. The Company typically allocates 5 to 20% of its capital
expenditures budget on exploration activities. These activities may include
either drilling our own internally generated prospects or participating in other
producer's wells and acreage. The objective of our exploration activities is to
take a portion of our capital and expose it to higher risk projects where the
potential warrants the higher risk. These activities
4
<PAGE> 5
could have a 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 intends to own assets downstream
of the wellhead, including but not limited to gathering and compression
facilities. This will be done, where warranted, to improve overall project
economics and enable Prima to capture more of the value chain from wellhead to
burner tip. Prima anticipates investment in low pressure gathering and
compression in the Powder River Basin in 2000 and beyond. Prima may also gather,
compress and market third party gas.
WELL DRILLING AND SERVICING. Prima believes that it can better control the
timing and quality 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 during 1999 started an oilfield 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.
1999 DIVESTITURE
BONNY FIELD ASSETS. During January of 1999, Prima sold all of its interests in
the Bonny Field located in Yuma County, Colorado, for approximately $26 million.
The transaction had an effective date of January 1, 1999. Prima sold
non-operated working interests ranging from 15.5% to 33.3% in 134 producing
wells, its interests in 16,253 gross acres and a 15.5% interest in the gathering
system for this field. At year end 1998, the Bonny Field represented
approximately 6% of Prima's year end reserves and approximately 19% of
discounted cash flow from proved reserves. Funds from the sale were placed in a
like-kind exchange escrow account with a qualified intermediary pursuant to
Section 1031 of the Internal Revenue Code. Prima was unable to close on
qualifying properties within the time frame set forth by the Code. We estimate
federal and state income taxes on this transaction to be approximately $6
million after utilization of minimum tax credit carryforwards.
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 and conducts operations at Denver
International Airport. Prima operated 359 wells in the Denver Basin as of
December 31, 1999. Our leasehold position in the Denver Basin at that date was
17,066 gross, 13,762 net, developed acres, with an additional 19,747 gross,
18,408 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, or
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
5
<PAGE> 6
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 sells at a premium to Rocky
Mountain spot price due to the Btu content and liquids upgrade. Our crude oil in
this area is sweet crude and commands a premium to the Eastern Colorado posting.
The 1999 production from Prima's Denver Basin properties accounted for
approximately 73% of total oil and gas revenues, with natural gas averaging
12,801 Mcf per day and crude oil averaging 791 barrels per day net to Prima's
interest.
RESERVES, FINDING AND DEVELOPMENT COSTS. The Denver Basin represented 46% of
Prima's year end reserves on a BOE basis. Codell/Niobrara wells drilled and
completed in this area cost approximately $250,000 and target approximately 50
MBOE per well. Finding and development costs for these wells are approximately
$5.00 to $6.00 per BOE. At year end 1999, the Company controlled approximately
160 potential drillsites with 44 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 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 $.65 per Mcf on production through the year
2002, for restimulation. Refracs completed in 1999 have resulted in production
increases of 850% per well, with average daily incremental production rates of
180 Mcf of natural gas and 10 barrels of oil per day. Finding and development
costs for these incremental reserves average from $4.00 to $5.00 per BOE.
1999 ACTIVITY. During 1999 the Company refractured 61 wells (53.7 net). We
focused the majority of our time in this area on this activity given favorable
economics and efficiency of the operations. The refracs typically do not involve
acquiring new leases, gas sales contracts, or surface access agreements. We also
drilled 14 gross (13.5 net) Codell/Niobrara, and 2 gross (2.0 net) J-Sand wells
east of Denver International Airport during the year, all of which have been
successfully competed and placed on production.
FUTURE ACTIVITY. The Company intends to continue its development and
exploitation activities in the Denver Basin. We have budgeted 55 Codell/Niobrara
refrac stimulations to be done during 2000. We also intend to drill
approximately 25 Codell/Niobrara wells in the Wattenberg Area in 2000, with
eight of these having been drilled during the first quarter. The Company has
budgeted to drill two additional J-Sand wells east of Denver International
Airport. Prima anticipates capital expenditure in the Denver Basin in 2000 of
approximately $12 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 of northeast Wyoming. The
Wyodak Environmental Impact Study ("EIS"), which was completed in 1999 to review
the potential environmental impacts of the play, covered an area of
approximately 2,000,000 acres. The Company is currently involved in drilling and
well servicing activities in the area. According to the Wyoming Oil & Gas
Commission, over 2,000 CBM wells have been drilled with approximately 1,500
wells producing an estimated 200 MMcf of natural gas per day as of December 31,
1999. We believe approximately 60 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-in 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, 1999, Prima held 148,000 gross, 138,000
6
<PAGE> 7
net acres in this play, including approximately 36,000 acres acquired in 1999.
Our acreage is approximately 78% federal, 10% 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.
REGULATION. Prima and other operators in this play were subject to a moratorium
on the issuance of drilling permits on federal acreage for the better part of
1998 and 1999. The moratorium resulted from the EIS for which the Record of
Decision was issued on November 18, 1999 by the Bureau of Land Management
("BLM"). The EIS was undertaken to review and analyze the environmental impacts
of approximately 5,900 wells on the eastern flank of the Powder River Basin.
Drilling permits were issued by the Wyoming Oil and Gas Conservation Commission
on state and fee acreage throughout 1999 and were not impacted by the moratorium
on drilling permits on federal acreage. The Company currently anticipates that
the approximate 5,900 cumulative wells allowed pursuant to the EIS, (which well
count includes wells drilled on federal, state and fee land), will be reached
over the next several months. The BLM has initiated a second EIS study which is
proposed to encompass the entire Wyoming portion of the basin, with an expected
time frame to complete the study and issue a record of decision of approximately
eighteen months. The second EIS is currently contemplating as many as 30,000
wells with the consideration of the impact of various increments thereof. An
Environmental Assessment is expected to provide from 1,000 to 1,500 special
drainage permits where federal leases are potentially being drained by
offsetting wells.
PERMITS - DRILLING, WATER DISCHARGE AND AIR QUALITY. During 1999, Prima
(including subsidiaries and affiliates) submitted applications for approximately
525 drilling permits on federal, state and fee leases. In the third quarter of
1999, the BLM allowed operators to submit Applications for Permits to Drill
("APD's") on federal acreage in anticipation of finalizing the EIS. The volume
of APD's submitted led the BLM to establish a lottery system to determine the
order in which the APD's are processed. Prima submitted APD's in accordance with
the procedures established by the BLM. In the fourth quarter of 1999, the BLM
stated that it had received more APD's than it could process, and that total
applications exceeded the number of wells that can be drilled under the initial
EIS. The BLM estimated that only approximately 1,000 of the APD's previously
submitted in the lottery system would be processed before the well limit of the
EIS was reached. The BLM has initiated a second EIS, which includes updating the
Buffalo Resource Management Plan, to provide for future development on federal
acreage. Through March 10, 2000, Prima had received 63 drilling permits on
Federal acreage and 150 on fee and state acreage. The Company believes it will
be issued additional Federal permits and that combined with fee and state
permits, will be able to conduct its planned operations pending update of the
second EIS. Air quality permits for compression used in gathering and
transportation of gas in the area are currently taking a minimum of 120 days to
process. Water produced from the coal seams is generally potable (of drinking
water quality) and is typically discharged on the surface in holding ponds or
drainage areas. Water discharge permits are issued by the Wyoming Department of
Environmental Quality. The Company believes it will be able to secure water
discharge permits in its areas of operation and has submitted or received
approvals for permits covering 233 wells through March 10, 2000.
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 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. 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 not adopted field spacing for
this play to date, but wells are typically drilled on 40 or 80 acre tracts.
RESERVES, FINDING AND DEVELOPMENT COSTS. Powder River Basin Coalbed Methane
represented 38% of Prima's year end reserves on a BOE basis. CBM wells may cost
from $40,000 to $75,000 to drill, equip and complete through the sales meter
depending on location and depth, exclusive of gathering lateral and
7
<PAGE> 8
compression costs. A typical well may have ultimate reserves of 300 to 400 MMcf,
with finding and development costs estimated to be $0.20 to $0.30 per Mcf.
Virtually all of the CBM reserves estimated by an independent engineering firm
at December 31, 1999 are proved undeveloped. 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. Prima 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.
NATURAL GAS TRANSPORTATION INFRASTRUCTURE. Significant transportation
infrastructure from the Powder River Basin to major sales points was installed
and placed in service in 1999. Thunder Creek Gas Services, LLC, and Fort Union
Gas Gathering LLC each completed construction and began service on 24 inch
diameter gas gathering header systems out of the basin to Glenrock, Wyoming in
the east central part of Wyoming. Each of these systems is designed to transport
450 MMcf per day. From Glenrock, the systems tie into existing pipelines and the
recently constructed 24 inch diameter Medicine Bow pipeline owned by Wyoming
Interstate Pipeline, a Coastal Company, which ties into the major interstate
pipeline corridor near Cheyenne, Wyoming. In the northern end of the basin, CMS
Gas Transmission and Storage completed construction of a gathering system
capable of moving up to 250 MMcf per day to the mentioned gathering header
systems. Williston Basin Interstate Pipeline Company owns an 8 inch
transportation line in the northern part of the basin, and MIGC, Inc. a 16 inch
transportation line in the basin. These two pipelines were in service prior to
the coalbed methane play to take conventional natural gas from the area. The
transportation infrastructure in this basin is currently capable of moving over
1 Bcf (1,000,000 Mcf) of natural gas on a daily basis. Natural gas sales from
California to the Mid-Continent can now be achieved by selling into the
interstate pipeline market through access to many pipelines including: Colorado
Interstate Gas Company, KN Interstate, Wyoming Interstate, Front Range,
Williams, Trailblazer, Williston Basin, and Northern Border. During the first
quarter of 2000, the Company estimates that 200,000 Mcf per day was flowing from
coalbed methane production. Prima has not made arrangements to transport gas on
the mentioned systems at this time.
1999 ACTIVITY. During 1999, Prima drilled 15 gross (15.0 net) CBM test wells in
this area to begin evaluation of our acreage. Many of the wells were drilled as
science wells 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. The Company regularly reviews
well and lease acquisition opportunities in the area, and as a result purchased
an additional 36,000 net acres in the play in 1999. This acreage number is
included in the total acreage figure reported above.
FUTURE ACTIVITY. The Company anticipates drilling approximately 200 coalbed
methane wells in 2000. The majority of these wells are expected to be drilled in
dense groupings where we intend to dewater and produce wells. First production
is anticipated in the third or fourth quarter of 2000. 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 this area. Our capital budget for 2000 in
the coalbed methane play is anticipated to be $12 million.
CONVENTIONAL
LOCATION, OPERATIONS, ACREAGE. Prima owns the deep rights (below the coals) in
approximately 136,910 gross, 130,206 net acres in the Powder River Basin. We
currently operate 12 of the 15 conventional reservoir wells in which we have an
interest, or 80% 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 for over five years, approximately three years before the
increased activity in the area due to the coalbed methane play. 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 five
wells and had a non-operated interest in three wells at year end.
8
<PAGE> 9
FORMATIONS AND PRODUCTION. At December 31, 1999, 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 and therefore receives a premium price. 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 in this area. During 1999,
production from Prima's conventional Powder River Basin properties accounted for
approximately 13% of total oil and gas revenues, with natural gas averaging
3,278 Mcf per day and crude oil averaging 78 barrels per day net to our
interest.
RESERVES, FINDING AND DEVELOPMENT COSTS. The Powder River Basin conventional
play represented approximately 10% of Prima's year end reserves on a BOE basis.
Muddy formation wells in this area cost from $750,000 to $850,000 to drill and
complete, and average 200 to 250 MBOE per well. Historical finding and
development costs for Muddy formation wells have averaged $4.00 to $5.00 per
BOE. At year end 1999, the Company carried three well locations as proved
undeveloped in its reserve report for conventional reservoirs in this area.
1999 ACTIVITY. Prima drilled three (2.75 net) operated wells to the Muddy
formation in 1999. Two of these have been completed and were producing at year
end, and one has been plugged and abandoned. In addition, we participated in two
(0.45 net) non-operated Muddy formation wells that were both completed and
producing by year end.
FUTURE ACTIVITY. The Company currently intends to drill three or four Muddy
Formation locations in 2000. We recently drilled and ran pipe on the first of
these wells. The well is scheduled for completion by the end of March 2000.
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, and has participated in the drilling of 27 wells through December
31, 1999. 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 three wells. Prima owns working interests ranging from 4.5%
to 24% in 27 gross (2.1 net wells) in the area. Our Wind River Basin acreage
position is 1,040 gross, 140 net developed acres, with 34,916 gross, 22,997 net
undeveloped acres at year end 1999.
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 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 93% of the Company's production from this area was
from the Lance and Lakota/Muddy formations at year end 1999. 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
14% of the locations where deeper wells have been drilled. The shallow Frontier
formation wells in the area have generally not been produced as low pressure
prevents them from entering higher pressure gathering lines in the area.
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 1999, the Wind River
Basin represented approximately 14% of Prima's total oil and gas revenues, with
natural gas averaging 3,546 Mcf and crude oil 13 barrels per day.
9
<PAGE> 10
RESERVES, FINDING AND DEVELOPMENT COSTS. The Wind River Basin represents
approximately 6% of Prima's year end 1999 reserves on a BOE basis. Lance
formation wells cost approximately $1.6 million to drill and complete, and
target approximately 400 MBOE per well. The deep Frontier/Lakota/Muddy wells
cost approximately $9.5 million per well, and have the objective of 2.5 to 3.0
MMBOE per well. A Fort Union well costs approximately $500,000 to drill with the
goal of approximately 165 MBOE per well. The year end 1999 reserve report for
this area includes six proved undeveloped locations, and seventeen proved
developed non-producing opportunities. Our activity in this area is determined
to a large extent by the operator of each 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
approximately 95% of all activity proposed in the area.
1999 ACTIVITY. Prima participated in the drilling of eight gross (0.5 net)
wells, and also in three gross (.2 net) recompletions during 1999. All of these
wells and recompletions were producing at year end. The Cave Gulch #1-29 LAK
which blew out in August of 1998 was returned to production in October 1999, and
at year end was producing 384 Mcf per day to Prima's 4.57% working interest.
FUTURE ACTIVITY. Prima currently anticipates participating in approximately six
gross (.4 net) wells in the Cave Gulch area in 2000. During the first quarter of
2000, we are participating in the drilling of the Cave Gulch #4-19 Lakota well
for an 11.24% working interest. This well is anticipated to cost approximately
$1 million to Prima's interest. The Company also anticipates participating in
seven gross (.42 net) recompletions in the Fort Union and Lance formations
during 2000. We caution that the actual amount of wells and recompletions could
vary significantly depending on geologic and economic review, the operators
potential change in planned activity, and other factors.
OTHER ACTIVITY
Prima owns 73,080 gross, 30,308 net, undeveloped lease acres in the
Greater Green River Basin located in west central Wyoming. The Company also
purchased 102,075 gross, 25,999 net undeveloped acres in the Big Horn Basin
located in north central Wyoming in 1999. We intend to monitor activity in these
areas, and continue developing various geologic and interpretative data.
RESERVES
The Company's net proved reserves are approximately 86% attributable
to natural gas, and 14% to crude oil. The net proved reserves are estimated or
audited by the following engineering consulting firms:
Netherland, Sewell and Associates, Inc. (Powder River Basin Coalbed
Methane as well as auditing the Denver Basin and Powder River Basin
Conventional reserves estimated by other engineering firms).
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 (averaging $24.68 per barrel of oil and $1.90 per Mcf of natural gas at
December 31, 1999 compared to $10.31 per barrel of oil and $2.13 per Mcf of
natural gas at December 31, 1998). 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 11 of the Notes to Consolidated Financial
Statements.
10
<PAGE> 11
<TABLE>
<CAPTION>
December 31,
------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Estimated proved natural gas reserves (Mcf) ................ 124,111,000 71,207,000 63,490,000
Estimated proved oil reserves (barrels) .................... 3,268,000 2,826,000 3,358,000
Present value of estimated future net cash
flows (before future income tax expense) ................. $108,551,000 $ 65,318,000 $ 75,540,000
Standardized measure of discounted
future net cash flows .................................... $ 75,466,000 $ 51,426,000 $ 58,149,000
</TABLE>
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, 1999. The Company sold its interests
in the wells at the Bonny Field in January 1999. These wells represented
approximately 6% of Prima's year end 1998 reserves on a BOE basis. 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, 1999, 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 19,625 Mcf per day
for the year ended December 31, 1999 compared to 17,742 Mcf per day for the year
ended December 31, 1998 and 14,641 Mcf per day during the year ended December
31, 1997. Net oil production averaged 882 barrels per day for the year ended
December 31, 1999 compared to 784 barrels per day during the year ended December
31, 1998 and 699 barrels per day during the year ended December 31, 1997. The
following table summarizes information with respect to the Company's producing
oil and gas properties for each of these periods.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
1999 1998 1997
--------- --------- ---------
<S> <C> <C> <C>
Quantities Sold:
Natural gas (Mcf) .................... 7,163,000 6,476,000 5,344,000
Oil (barrels) ........................ 322,000 286,000 255,000
Average Sales Price:
Natural gas (per Mcf) ................ $ 2.10 $ 2.00 $ 2.39
Oil (per barrel) ..................... $ 17.42 $ 12.71 $ 19.90
Average production (lifting) costs per
equivalent barrel (1) ............... $ 2.49 $ 2.43 $ 2.68
</TABLE>
- ----------
(1) Natural gas production has been converted to a common unit of
production (barrel of oil) on the basis of relative energy content (six
Mcf of natural gas to one barrel of oil).
11
<PAGE> 12
PRODUCTIVE WELLS
The following table summarizes total gross and net productive wells
for the Company at December 31, 1999.
<TABLE>
<CAPTION>
Productive Wells
-----------------------------------------------
Oil Gas
--------------------- ---------------------
Gross(1) Net(2) Gross(1) Net(2)
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Operated:
Colorado .......................... 8 7.5 351 291.7
Wyoming ........................... 0 0.0 13 11.4
Non-operated:
Colorado .......................... 0 0.0 21 8.6
Wyoming ........................... 0 0.0 29 2.5
-------- -------- -------- --------
Total (3) ...................... 8 7.5 414 314.2
======== ======== ======== ========
</TABLE>
Additionally, the Company has a royalty interest in 138 of the gross
wells reported above in which it owns a working interest. Also, the Company has
royalty interests in an additional 39 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. The totals include 190 dual or triple
completions. Multiple completions are counted as one well.
DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 1999, the Company held leased acreage as set forth
below:
<TABLE>
<CAPTION>
Developed Acreage (1) Undeveloped Acreage (2)
------------- --------- -----------------------
Location Gross (3) Net (4) Gross (3) Net (4)
- -------------------------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
Big Horn Basin ................. 0 0 102,075 25,999
Denver Basin ................... 17,066 13,762 19,747 18,408
Green River Basin .............. 0 0 73,080 30,308
Powder River Basin ............. 1,625 1,480 178,180 166,686
Wind River Basin ............... 1,040 140 34,916 22,997
Other Basins ................... 1,495 57 13,273 11,929
--------- --------- --------- ---------
Total .......................... 21,226 15,439 421,271 276,327
========= ========= ========= =========
</TABLE>
(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.
12
<PAGE> 13
(3) A gross acre is an acre in which a working interest is owned. The
number of gross acres is the total number of acres in which a working
interest is owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.
Many of the leases summarized in the table above as undeveloped acreage
will expire at the end of their respective primary terms unless production has
been obtained from the acreage subject to the lease prior to that date, in which
event the lease will remain in effect until the cessation of production. The
following table sets forth the expiration dates of the gross and net acres
subject to leases summarized in the table of undeveloped acreage.
<TABLE>
<CAPTION>
Acres Expiring
-------------------
Twelve Months Ending: Gross Net
------- -------
<S> <C> <C>
December 31, 2000 ................. 12,140 9,998
December 31, 2001 ................. 11,639 8,392
December 31, 2002 ................. 14,749 7,185
December 31, 2003 ................. 12,208 7,411
December 31, 2004 ................. 53,279 27,886
December 31, 2005 and later ....... 277,899 184,433
</TABLE>
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities
for the years ended December 31, 1999, 1998 and 1997 is set forth below:
<TABLE>
<CAPTION>
1999 1998 1997
---------------------- ---------------------- ----------------------
Gross Net Gross Net Gross Net
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive ....................... 33 27.14 30 10.52 46 33.74
Dry .............................. 1 0.75 2 0.31 0 0.00
-------- -------- -------- -------- -------- --------
34 27.89 32 10.83 46 33.74
======== ======== ======== ======== ======== ========
Exploratory:
Productive ....................... 9 6.19 4 3.05 0 0.00
Dry .............................. 0 0.00 2 1.06 4 2.70
-------- -------- -------- -------- -------- --------
9 6.19 6 4.11 4 2.70
======== ======== ======== ======== ======== ========
Total
Productive ....................... 42 33.33 34 13.57 46 33.74
Dry .............................. 1 0.75 4 1.37 4 2.70
-------- -------- -------- -------- -------- --------
43 34.08 38 14.94 50 36.44
======== ======== ======== ======== ======== ========
</TABLE>
Since December 31, 1999 and through March 10, 2000, the Company has
drilled or participated in wells as follows: eight gross and net wells drilled
and nineteen gross (17.55 net) refracs in the Denver Basin, eleven gross and net
wells in the Powder River Basin coalbed methane play, one gross and net well in
the Powder River Basin conventional play, and one reentry (.11 net) in the Wind
River Basin.
13
<PAGE> 14
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, and gas trading activities that consist of the purchase and
resale of natural gas. 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. Prima sells its natural gas to utilities, industrial end-users,
gathering and marketing aggregators, as well as marketing affiliates of
interstate pipeline companies. 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 1999. Prima has one significant purchaser of its natural
gas in the Denver Basin, Duke Energy Field Services, Inc. (Duke), who accounted
for 28% 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 two gathering
agreements, one in the Denver Basin and one in the Wind River Basin, to get its
gas from the wellhead into interstate pipelines for sale, but has not contracted
on a firm basis for interstate pipeline transportation. As such, we have no
liability to pay reservation (demand) charges for pipeline capacity, or
assurance that our gas can flow every day, although no significant curtailment
of production occurred in 1999. 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. Prima had no open natural gas trading positions at year end. In 1999,
total revenues from the sale of Prima's natural gas production were $15,042,000,
or 50% of consolidated revenues, and trading revenues amounted to $2,318,000, or
8% 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 1999,
one purchaser, Ultramar Diamond Shamrock ("UDS"), accounted for approximately
80% of Prima's crude oil sales, $4,462,000, which represented 15% of
consolidated revenues. Prima is not affiliated with UDS, and believes that it
can sell its crude to other purchasers should we lose UDS as a customer.
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. Hedging activity is
reviewed by Prima's Chief Executive Officer before commitment to a hedge, and
significant positions are reviewed by the Board of Directors. At year end 1999,
the Company did not have any open positions or hedges for future production and
trading activity. During 1999, Prima hedged 1,310,000 MMBtu of natural gas, and
81,000 barrels of crude oil, representing 15% of its natural gas and 25% of its
crude oil production.
14
<PAGE> 15
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 1999, 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, 1999,
29% 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. Revenues recorded by AOS in 1999 were $3,792,000, or 13%
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 five drilling
rigs, pipeline trenching equipment and a back hoe. We intend to engage in both
drilling and gathering activities in the Powder River Basin. Our services are
offered to both Prima and third parties in the area. During the year, AES
acquired the assets of two small well servicing companies in the area. During
1999, 18% 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 revenues were $1,182,000 in 1999, and represented 4% of the Company's
consolidated revenues.
MANAGEMENT AND OPERATOR SERVICES
The Company provides management and operator services for approximately
372 wells which the Company operates pursuant to industry standard operating
agreements with other working interest owners in the wells. The Company also
served, through December 31, 1998, as managing venturer and operator of Bonny
Gathering Company, a joint venture formed to construct and operate a natural gas
gathering and pipeline facility in the Bonny Field in eastern Colorado. As
mentioned earlier in this document, the gathering system was sold in January
1999. Prima agreed to provide transitional operating and management services
through March 31, 1999. Revenues attributable to management and operator
services provided to third parties were $619,000 for the year ended December 31,
1999, including $66,000 from management of the Bonny Gathering system, which was
2% of consolidated revenues.
PHYSICAL PROPERTIES
The Company leases its Denver office space at an annual rate of
approximately $135,000 per year. Such offices consist of 11,717 square feet and
the lease continues until November 30, 2000. The Company owns office furniture
and equipment with a net book value at December 31, 1999 of $184,000.
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 at this location was $1,990,000 at December 31, 1999.
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 and buildings at December 31, 1999, was $208,000. The service
15
<PAGE> 16
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 $2,170,000 at
December 31, 1999.
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, 1999.
EMPLOYEES AND OFFICES
As of December 31, 1999, the Company had 116 full-time employees,
including 24 in its Denver office and 92 field employees. Action Oilfield
Services employed 50 people, Action Energy Services employed 30 people, and 12
were employed in Prima's field production and pumping activities. 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 1801 Broadway, Suite 500, 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, 1999, 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.
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, 1999.
16
<PAGE> 17
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 1999, average oil and natural gas prices realized by the Company were 37%
and 5% higher than those received in 1998. 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.
17
<PAGE> 18
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
46% of the Company's proved reserves at December 31, 1999, were located in the
Wattenberg Area of the Denver Basin, where wells are characterized by relatively
rapid decline rates. Additionally, approximately 52% of the Company's total
proved reserves at December 31, 1999, 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 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 1999, the Company's hedge agreements covered approximately 25%
and 15% of the Company's daily average oil and natural gas 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.
18
<PAGE> 19
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 tier of the Nasdaq Stock 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, 1999 and 1998. 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.
<TABLE>
<CAPTION>
Year Ended December 31, 1999 HIGH LOW
-------- --------
<S> <C> <C>
Quarter Ended March 31, 1999 ......................................... $ 10.417 $ 8.375
Quarter Ended June 30, 1999 .......................................... 15.167 8.667
Quarter Ended September 30, 1999 ..................................... 17.083 13.750
Quarter Ended December 31, 1999 ...................................... 18.500 13.833
Year Ended December 31, 1998
Quarter Ended March 31, 1998 ......................................... $ 13.333 $ 11.333
Quarter Ended June 30, 1998 .......................................... 13.000 11.167
Quarter Ended September 30, 1998 ..................................... 13.000 9.000
Quarter Ended December 31, 1998 ...................................... 12.333 8.167
</TABLE>
On March 10, 2000, the closing sale price for the Company's common
stock was $22.25 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 March 10, 2000 totaled 1,138.
(C) DIVIDENDS. Holders of common stock are entitled to receive such
dividends as may be declared by Prima's Board of Directors. No dividends were
declared or paid in 1999, 1998 or 1997. Future dividends, if any, will be
evaluated based among other things, on operating results and financial condition
of the Company at the time.
19
<PAGE> 20
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.
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- -------- --------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues:
Oil and gas sales ..................... $ 20,644 $ 16,612 $ 17,840 $ 14,657 $ 11,502
Oilfield services ..................... 4,974 4,148 3,214 2,269 1,487
Trading revenues ...................... 2,318 3,956 15,999 10,001 4,604
Interest and dividend income .......... 1,334 469 546 411 154
Management and operator fees .......... 619 1,044 1,035 1,003 1,084
Other ................................. (48) 3,863 216 280 217
-------- -------- -------- -------- --------
29,841 30,092 38,850 28,621 19,048
-------- -------- -------- -------- --------
Expenses:
Depreciation, depletion
and amortization:
Oil and gas properties ............. 4,650 6,260 4,935 4,210 4,058
Property and equipment ............. 817 616 497 334 314
Lease operating expense ............... 2,012 2,041 1,720 1,511 1,432
Ad valorem and production taxes ....... 1,765 1,272 1,355 981 736
Cost of oilfield services ............. 3,377 2,701 2,368 1,759 1,170
Cost of trading ....................... 2,827 3,936 15,323 9,060 3,613
General and administrative ............ 2,331 2,141 1,915 1,812 1,863
-------- -------- -------- -------- --------
17,779 18,967 28,113 19,667 13,186
-------- -------- -------- -------- --------
Income before income taxes ............. 12,062 11,125 10,737 8,954 5,862
Provision for income taxes ............. 3,035 3,060 2,635 2,285 1,370
-------- -------- -------- -------- --------
Net Income ............................. $ 9,027 $ 8,065 $ 8,102 $ 6,669 $ 4,492
======== ======== ======== ======== ========
Basic Net Income per Share ............. $ 1.05 $ 0.93 $ 0.94 $ 0.77 $ 0.51
======== ======== ======== ======== ========
Diluted Net Income per Share ........... $ 1.03 $ 0.91 $ 0.91 $ 0.76 $ 0.51
======== ======== ======== ======== ========
Cash Dividends per Share ............... $ 0.00 $ 0.00 $ 0.00 $ 0.11 $ 0.00
======== ======== ======== ======== ========
Balance Sheet Data (at end of period):
Total assets ........................... $ 72,665 $ 66,866 $ 57,921 $ 48,006 $ 38,565
Net property and equipment ............. 44,467 55,607 43,181 32,325 29,118
Long-term debt ......................... 0 120 240 0 0
Stockholders' equity ................... 58,908 51,308 43,214 35,273 29,916
Working capital ........................ 21,408 5,467 7,952 7,863 4,292
</TABLE>
20
<PAGE> 21
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 17.
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, 1999. 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 $12,006,000 for the year ended December
31, 1999, compared to $16,789,000 for the year ended December 31, 1998 and
$14,685,000 for the year ended December 31, 1997. Net working capital at
December 31, 1999 was $21,408,000 as compared to $5,467,000 at December 31,
1998. Current assets were $27,941,000 at December 31, 1999 compared to
$10,673,000 at December 31, 1998. Current liabilities were $6,533,000 at
December 31, 1999 compared to $5,206,000 at December 31, 1998. The Company had
proceeds from the sales of oil and gas properties and other equipment and sales
of securities of $27,871,000 in 1999.
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. 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 invested $18,617,000 in additions to oil and gas properties
during the year ended December 31, 1999, compared to $18,147,000 during the year
ended December 31, 1998 and $15,250,000 during the year ended December 31, 1997.
During 1999, $13,416,000 was paid for the Company's share of development well
costs and recompletions, $1,731,000 for exploratory costs, $3,347,000 for
acquisitions of unproved properties and $123,000 for purchases of proved
properties. Other uses of funds in 1999 included $2,673,000 for purchases of
oilfield service equipment, facilities and office equipment, $2,454,000 for
treasury stock purchases and $497,000 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 $75,466,000 at
December 31, 1999 as compared to $51,426,000 at December 31, 1998 and
$58,149,000 at December 31, 1997. Estimated future net cash flows from proved
oil and natural gas reserves increased to $190,008,000 at December 31, 1999
compared to $115,801,000 at December 31, 1998 and $136,391,000 at December 31,
1997. Oil reserve volumes at December 31, 1999 increased 16% and natural gas
reserve volumes increased 74% compared to December 31, 1998. On a barrel of oil
equivalent basis, 1999 reserves increased 63% to 23,953,000 BOE. The weighted
average natural gas price received at December 31, 1999 on Company production
was $1.90 per Mcf, a decrease of $0.23 per Mcf compared to December 31, 1998.
The year end weighted average oil price was $24.68 per barrel, an increase of
$14.37 per barrel compared to December 31, 1998.
21
<PAGE> 22
At December 31, 1999, the Company estimates that capital expenditures
of $36,107,000 will be required to develop the Company's proved undeveloped and
proved developed non-producing reserves over the next several years.
Approximately $71,443,000, net of future development costs, of the estimated
future net cash flows of the Company's proved oil and gas reserves at December
31, 1999 were proved undeveloped reserves.
The Board of Directors of Prima approved a three for two stock split of
its common stock 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 5,645,341 to 8,467,744 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 split.
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 is required to
adopt SFAS 133 on January 1, 2001. Although the Company has not completed the
process of evaluating the impact that will result from adopting SFAS 133,
management does not believe it would have a material impact on financial
position or results of operations.
RESULTS OF OPERATIONS
1999 VS 1998
For the year ended December 31, 1999, the Company earned net income of
$9,027,000, or $1.03 per diluted share, on revenues of $29,841,000, compared to
net income of $8,065,000, or $0.91 per diluted share, on revenues of $30,092,000
for the year ended December 31, 1998. Operating expenses were $17,779,000 for
1999 compared to $18,967,000 for 1998. Revenues decreased $251,000 or 1%,
expenses decreased $1,188,000 or 6% and net income increased $962,000 or 12% in
1999. During 1998, the
22
<PAGE> 23
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 $0.28. Exclusive of this transaction, net income for 1998 would have
been $5,565,000 and earnings per diluted share would have been $0.63.
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 both 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 a BOE basis, the Company's production for 1999
increased 149,000 BOE or 11%, or 202,000 BOE and 15% after giving effect to the
Bonny sale. 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. The purpose of these hedges is to provide market price
protection in the volatile environment of oil and natural gas spot pricing.
Hedging losses of $180,000 are 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. 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.
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 $4,650,000 or
$3.07 per BOE on 1,515,000 equivalent barrels produced in 1999, compared to
$6,260,000 or $4.58 per BOE on 1,366,000 equivalent barrels 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 $2.49 per BOE for 1999 compared to 20% and
$2.43 for 1998.
Oilfield service revenues of $4,974,000 and $4,148,000 for the years
ended December 31, 1999 and 1998, respectively, represent the revenues earned by
Action Oilfield Services, Inc. and Action Energy Services, wholly owned
subsidiaries. These revenues include well servicing fees from drilling rigs,
completion rigs, swab rigs, trucking, water hauling, rental equipment and other
related activities. Revenues increased $826,000, or 20% for 1999. 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%. 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, 1999 and 1998, 26% and 21%, 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.
23
<PAGE> 24
Trading revenues and cost of trading represented the marketing of third
party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary.
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%. 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
at December 31, 1999 or March 10, 2000.
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%.
Management and operator fees in 1999 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 a working interest
owner in each of the operated wells. 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. During 1998, the
Company also served as managing venturer of a joint venture which owned gas
gathering and pipeline facilities in the Bonny Field in Yuma County, Colorado.
In January 1999, the Company sold its interest in the Bonny Field assets and no
longer served as managing venturer and operator. Management and operator fees
attributable to the Bonny Field system were $406,000 for 1998.
General and administrative expense ("G&A") totaled $2,331,000 for the
year ended December 31, 1999 compared to $2,141,000 for the year ended December
31, 1998, an increase of $190,000 or 9%. 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. Effective
tax rates are affected by amounts of permanent differences between financial and
taxable income, consisting primarily of statutory depletion deductions, Section
29 tax credits and compensation expense recognized from the exercise of
non-qualified stock options.
1998 VS 1997
For the year ended December 31, 1998, the Company earned net income of
$8,065,000, or $0.91 per diluted share, on revenues of $30,092,000, compared to
net income of $8,102,000, or $0.91 per diluted share, on revenues of $38,850,000
for the year ended December 31, 1997. 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 $0.28. The
proceeds from this transaction are reported in other income on the consolidated
statement of income. Operating expenses were $18,967,000 for 1998 compared to
$28,113,000 for 1997. Revenues decreased $8,758,000 or 23%, expenses decreased
$9,146,000 or 33% and net income decreased $37,000 or less than 1% in 1998.
Oil and gas sales for the year ended December 31, 1998 were $16,612,000
compared to $17,840,000 for the year ended December 31, 1997, a decrease of
$1,228,000 or 7%. This decrease was due to lower product prices, which more than
offset increased production. The Company's net natural gas production was 6.5
Bcf for 1998 compared to 5.3 Bcf in 1997, an increase of 1.2 Bcf or 23%. Its net
oil production was 286,000 barrels compared to 255,000 barrels for the same
periods, an increase of 31,000 barrels or 12%. On a BOE basis, the Company's
production for 1998 increased 220,000 BOE or 19%. The average price received per
Mcf of natural gas sold was $2.00 for the year ended December 31, 1998 compared
to $2.39 per Mcf for the year ended December 31, 1997, a decrease of $.39 per
Mcf or 16%.
24
<PAGE> 25
Approximately 4.9% and 5.2% of the natural gas production for the years ended
December 31, 1998 and 1997, respectively, 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 and $2.20 per Mcf for the
year ended December 31, 1997. The average price received per barrel of oil sold
was $12.71 for 1998 compared to $19.90 for 1997, a decrease of $7.19 per barrel
or 36%. During the year ended December 31, 1998, the Company hedged
approximately 44% of its natural gas production. Hedging losses of $112,000 are
included in oil and gas revenues for the year, which decreased the average price
received per Mcf of natural gas by $0.02. No oil was hedged during this period.
During the year ended December 31, 1997, the Company hedged approximately 29% of
its oil production and 37% of its natural gas production. Hedging gains of
$140,000 are included in oil and gas revenues for the year, which increased the
average price received per barrel of oil by $0.50 and had no material effect on
the price received per Mcf of natural gas.
The Company's depletion of oil and gas properties was $6,260,000 or
$4.58 per BOE on 1,366,000 equivalent barrels produced in 1998, compared to
$4,935,000 or $4.31 per BOE on 1,146,000 equivalent barrels produced in 1997.
Depreciation of other fixed assets was $616,000 and $497,000 for 1998 and 1997,
respectively. Depreciation expense increased $119,000, or 24%, due primarily to
acquisitions of oilfield service equipment in 1998.
LOE was $2,041,000 for the year ended December 31, 1998 compared to
$1,720,000 for the year ended December 31, 1997. Ad valorem and production taxes
were $1,272,000 and $1,355,000 for the same periods. Total lifting costs (LOE
plus ad valorem and production taxes) were 20% of oil and gas revenues and $2.43
per equivalent barrel of production for 1998 compared to 17% and $2.68 for 1997.
Oilfield service revenues were $4,148,000 for the year ended December
31, 1998 compared to $3,214,000 for the year ended December 31, 1997. Revenues
increased $934,000, or 29% for 1998. Costs of oilfield services were $2,701,000
for the year ended December 31, 1998 compared to $2,368,000 for the year ended
December 31, 1997, an increase of $333,000 or 14%. Utilization levels in the
Wattenberg Area, where the service company is active, increased above 1997
levels. The Company also purchased additional equipment which contributed to the
increase in revenues. For the years ended December 31, 1998 and 1997, 21% and
22%, respectively, of the gross fees billed by Action were for Company owned
wells.
Trading revenues were $3,956,000 for 1998 compared to $15,999,000 for
1997, a decrease of $12,043,000 or 75%. The Company marketed 1,823,000 MMBtus of
third party gas in 1998 compared to 7,105,000 MMBtus in 1997, a decrease of
5,282,000 MMBtus or 74%. Costs of trading were $3,936,000 for 1998 compared to
$15,323,000 for 1997, a decrease of $11,387,000 or 74%. These decreases are
attributable to the termination of the gas supply contract to a co-generation
facility and to certain other buy-for-resale contracts which terminated in the
fall of 1997 and were not renewed.
Management and operator fees for the years ended December 31, 1998 and
1997 were $1,044,000 and $1,035,000, respectively, an increase of $9,000 or 1%.
G&A totaled $2,141,000 for the year ended December 31, 1998 compared to
$1,915,000 for the year ended December 31, 1997. G&A costs increased by $226,000
or 12%. The Company's G&A expense has increased due to expansion of the
Company's area of operations. During 1998, the company capitalized geological
and geophysical costs of $180,000 compared to $120,000 in 1997. Additionally,
the Company capitalized G&A costs of $380,000 in 1998 related primarily to its
expansion in the Powder River Basin.
The provision for income taxes was $3,060,000 for the year ended
December 31, 1998 compared to $2,635,000 for the year ended December 31, 1997.
The effective tax rate was 27.5% in 1998 compared to 24.5% in 1997.
25
<PAGE> 26
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 deceases 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.
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 5 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. During
1999, the Company sold 322,000 barrels of oil. A hypothetical decrease of $1.74
per barrel (10% of the average price received during the year) would decrease
the Company's production revenues by $560,000 during 2000, assuming that oil
production remains at 1999 levels. The Company sold 7.2 Bcf of natural gas in
1999. A hypothetical decrease of $.21 per Mcf (10% of the average price received
during the year) would decrease the Company's production revenues by $1,512,000
for 2000, assuming that natural gas production remains at 1999 levels.
26
<PAGE> 27
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 18, 2000 and is hereby
incorporated by reference.
27
<PAGE> 28
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
<S> <C>
Independent Auditors' Report ...................................... 29
Consolidated Balance Sheets at December 31, 1999 and 1998 ......... 30
Consolidated Statements of Income for the years ended
December 31, 1999, 1998 and 1997 ............................. 32
Consolidated Statements of Comprehensive Income for the years ended
December 31, 1999, 1998 and 1997 ............................. 33
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1999, 1998 and 1997 ............................. 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1999, 1998 and 1997 ............................. 35
Notes to Consolidated Financial Statements for the years ended
December 31, 1999, 1998 and 1997 ............................. 36
</TABLE>
(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.
<TABLE>
<CAPTION>
EXHIBIT NO. DOCUMENT
<S> <C>
2 Purchase and Sale Agreement dated January 7, 1999 (incorporated
by reference as Exhibit 2.1 to Form 8-K filed February 5, 1999)
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP
27 Financial Data Schedules
</TABLE>
(b) REPORTS ON FORM 8-K
The Company filed a Report on Form 8-K dated November 15, 1999,
reporting the Company's earnings for the third quarter of 1999 and an update of
the Company's operations for the same period. The Company filed a Report on Form
8-K dated January 27, 2000, reporting the declaration of a three for two stock
split of the Company's common stock. Record date for the stock split was
February 10, 2000 and the distribution date was February 24, 2000. The Company
filed a Report on Form 8-K dated February 24, 2000, reporting year end 1999 oil
and natural gas reserve information, the Company's estimated year 2000 budget,
and a summary of 1999 capital expenditures.
28
<PAGE> 29
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, 1999 and
1998, 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, 1999. 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, 1999 and 1998, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1999 in conformity with accounting principles generally accepted in the
United States of America.
DELOITTE & TOUCHE LLP
March 10, 2000
Denver, Colorado
29
<PAGE> 30
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
ASSETS
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents .................... $ 18,883,000 $ 2,522,000
Available for sale securities, at market ..... 1,949,000 2,391,000
Receivables (net of allowance for doubtful
accounts: 1999, $45,000; 1998, $47,000) ...... 5,284,000 4,696,000
Tubular goods inventory ...................... 837,000 612,000
Other current assets ......................... 988,000 452,000
------------ ------------
Total current assets ................... 27,941,000 10,673,000
------------ ------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ............ 77,700,000 86,081,000
Less accumulated depreciation,
depletion and amortization ................ (37,785,000) (33,135,000)
------------ ------------
Oil and gas properties - net ........... 39,915,000 52,946,000
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ................... 6,814,000 4,353,000
Furniture and equipment ...................... 659,000 815,000
Field office, shop and land .................. 481,000 439,000
------------ ------------
7,954,000 5,607,000
Less accumulated depreciation ................ (3,402,000) (2,946,000)
------------ ------------
Property and equipment - net ........... 4,552,000 2,661,000
------------ ------------
OTHER ASSETS ................................. 257,000 586,000
------------ ------------
$ 72,665,000 $ 66,866,000
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE> 31
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 1999 AND 1998
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
1999 1998
------------ ------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable ....................................... $ 2,085,000 $ 2,122,000
Amounts payable to oil and gas property owners ......... 1,499,000 973,000
Ad valorem and production taxes payable ................ 1,210,000 1,552,000
Income taxes payable ................................... 1,051,000 0
Accrued and other liabilities .......................... 384,000 439,000
Current portion of note payable ........................ 304,000 120,000
------------ ------------
Total current liabilities ........................ 6,533,000 5,206,000
NOTE PAYABLE ........................................... 0 120,000
AD VALOREM TAXES, non-current .......................... 1,516,000 1,088,000
DEFERRED INCOME TAXES .................................. 5,708,000 9,144,000
------------ ------------
Total liabilities ................................ 13,757,000 15,558,000
------------ ------------
COMMITMENTS AND CONTINGENCIES (Note 8)
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; 12,000,000
shares authorized; 8,893,366 and
8,754,616 shares issued ............................. 133,000 131,000
Additional paid-in capital ............................. 5,693,000 4,373,000
Retained earnings ...................................... 56,577,000 47,550,000
Accumulated other comprehensive income (loss) .......... (244,000) 51,000
Treasury stock, 322,305 and 95,680 shares at cost ...... (3,251,000) (797,000)
------------ ------------
Stockholders' equity - net ....................... 58,908,000 51,308,000
------------ ------------
$ 72,665,000 $ 66,866,000
============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE> 32
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
REVENUES
Oil and gas sales ........................... $ 20,644,000 $ 16,612,000 $ 17,840,000
Oilfield services ........................... 4,974,000 4,148,000 3,214,000
Trading revenues ............................ 2,318,000 3,956,000 15,999,000
Interest and dividend income ................ 1,334,000 469,000 546,000
Management and operator fees ................ 619,000 1,044,000 1,035,000
Other ....................................... (48,000) 3,863,000 216,000
------------ ------------ ------------
29,841,000 30,092,000 38,850,000
------------ ------------ ------------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ...... 4,650,000 6,260,000 4,935,000
Depreciation of property and equipment ... 817,000 616,000 497,000
Lease operating expense ..................... 2,012,000 2,041,000 1,720,000
Ad valorem and production taxes ............. 1,765,000 1,272,000 1,355,000
Cost of oilfield services ................... 3,377,000 2,701,000 2,368,000
Cost of trading ............................. 2,827,000 3,936,000 15,323,000
General and administrative .................. 2,331,000 2,141,000 1,915,000
------------ ------------ ------------
17,779,000 18,967,000 28,113,000
------------ ------------ ------------
INCOME BEFORE INCOME TAXES .................. 12,062,000 11,125,000 10,737,000
PROVISION FOR INCOME TAXES .................. 3,035,000 3,060,000 2,635,000
------------ ------------ ------------
NET INCOME .................................. $ 9,027,000 $ 8,065,000 $ 8,102,000
============ ============ ============
BASIC NET INCOME PER SHARE .................. $ 1.05 $ 0.93 $ 0.94
============ ============ ============
DILUTED NET INCOME PER SHARE ................ $ 1.03 $ 0.91 $ 0.91
============ ============ ============
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE> 33
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Net income ................................................... $ 9,027,000 $ 8,065,000 $ 8,102,000
----------- ----------- -----------
Other comprehensive income:
Unrealized gain (loss) on available-for-sale securities ...... (551,000) 12,000 117,000
Deferred income tax benefit (expense) related to
unrealized gain on available-for-sale securities ............ 175,000 (3,000) (47,000)
Reclassification adjustment for (gains) losses
included in net income ..................................... 81,000 (2,000) 10,000
----------- ----------- -----------
(295,000) 7,000 80,000
----------- ----------- -----------
COMPREHENSIVE INCOME ......................................... $ 8,732,000 $ 8,072,000 $ 8,182,000
=========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
33
<PAGE> 34
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Treasury
Stock Capital Earnings Income (Loss) Stock Total
----------- ----------- ----------- ------------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
BALANCES, January 1, 1997 ......... $ 131,000 $ 4,178,000 $31,383,000 $ (36,000) $ (383,000) $35,273,000
Net income ........................ 8,102,000 8,102,000
Exercise of stock options ......... 0 111,000 111,000
Tax benefit from exercise of non-
qualified stock options ........ 52,000 52,000
Other comprehensive income ........ 80,000 80,000
Treasury stock purchased .......... (404,000) (404,000)
----------- ----------- ----------- ----------- ----------- -----------
BALANCES, December 31, 1997 ....... 131,000 4,341,000 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 ....... 131,000 4,373,000 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 ....... $ 133,000 $ 5,693,000 $56,577,000 $ (244,000) $(3,251,000) $58,908,000
=========== =========== =========== =========== =========== ===========
</TABLE>
See accompanying notes to consolidated financial statements.
34
<PAGE> 35
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income .................................................................... $ 9,027,000 $ 8,065,000 $ 8,102,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization ................................... 5,467,000 6,876,000 5,432,000
Deferred income taxes ...................................................... 2,281,000 2,238,000 2,028,000
Current taxes from sale of oil and gas properties .......................... (5,704,000) 0 0
Other ...................................................................... 551,000 (104,000) (116,000)
Changes in operating assets and liabilities:
Receivables .............................................................. (588,000) 985,000 240,000
Inventory ................................................................ (225,000) 270,000 (571,000)
Other current assets ..................................................... (374,000) (265,000) 32,000
Accounts payable and payables to owners .................................. 489,000 (1,375,000) (911,000)
Production taxes payable ................................................. 86,000 81,000 481,000
Income taxes payable............................................ 1,051,000 0 (23,000)
Accrued and other liabilities ............................................ (55,000) 18,000 (9,000)
------------ ------------ ------------
Net cash provided by operating activities ............................. 12,006,000 16,789,000 14,685,000
------------ ------------ ------------
INVESTING ACTIVITIES
Proceeds from sales of property ............................................... 27,483,000 130,000 292,000
Additions to oil and gas properties ........................................... (18,617,000) (18,147,000) (14,893,000)
Purchases of other property ................................................... (2,673,000) (1,275,000) (931,000)
Purchases of securities ....................................................... (497,000) (540,000) (358,000)
Proceeds from sales of securities ............................................. 388,000 28,000 113,000
------------ ------------ ------------
Net cash provided by (used in)
investing activities ............................................... 6,084,000 (19,804,000) (15,777,000)
------------ ------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ...................................................... (2,454,000) (10,000) (404,000)
Proceeds from exercise of stock options ....................................... 845,000 23,000 111,000
Repayment of long-term debt ................................................... (120,000) (120,000) 0
------------ ------------ ------------
Net cash used in financing activities ................................. (1,729,000) (107,000) (293,000)
------------ ------------ ------------
Increase (decrease) in cash and cash equivalents .............................. 16,361,000 (3,122,000) (1,385,000)
Cash and cash equivalents, beginning of year .................................. 2,522,000 5,644,000 7,029,000
------------ ------------ ------------
CASH AND CASH EQUIVALENTS, end of year ........................................ $ 18,883,000 $ 2,522,000 $ 5,644,000
============ ============ ============
</TABLE>
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets for $460,000 in March
1999 and $600,000 in June 1997. A summary of the transactions are as follows:
<TABLE>
<S> <C> <C>
Fair value of assets acquired ................................................. $460,000 $600,000
Cash paid ..................................................................... 276,000 240,000
-------- --------
Note payable issued to seller ............................................ $184,000 $360,000
======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
35
<PAGE> 36
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
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, 1999.
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 $4,725,000, $810,000 and $787,000 for
the years ended December 31, 1999, 1998 and 1997, respectively. Cash paid for
interest in 1999 and 1998 was $37,000 and $20,000, respectively. No amount was
paid for interest in 1997.
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.
36
<PAGE> 37
INVENTORY
Inventory consists of various tubular goods intended to be used in the
Company's oil and gas operations and are stated at the lower of cost or market
value using the specific identification method.
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 of 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 have been 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 10 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.
37
<PAGE> 38
RISK MANAGEMENT
The Company periodically uses both commodity futures contracts and
price 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 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 price 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. At December 31,
1999, the Company had no transactions that did not correspond to anticipated
physical transactions. For the years ended December 31, 1999, 1998 and 1997,
gains or losses for these transactions were not significant to the Company's
results of operations.
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, 1999, 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.
38
<PAGE> 39
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
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 is required to
adopt SFAS 133 on January 1, 2001. Although the Company has not completed the
process of evaluating the impact that will result from adopting SFAS 133,
management does not believe it would have a material impact on financial
position or results of operations.
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 9, 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).
The following table reconciles the numerator and denominator used in
the calculation of basic and diluted net income per share.
<TABLE>
<CAPTION>
Income Shares Per Share
(Numerator) (Denominator) Amount
------------ ------------- ------------
<S> <C> <C> <C>
Year Ended December 31, 1999:
Basic Net Income per Share ............................................. $ 9,027,000 8,569,464 $ 1.05
============
Effect of Stock Options ................................................ 189,957
------------ ------------
Diluted Net Income per Share ........................................... $ 9,027,000 8,759,421 $ 1.03
============ ============ ============
Year Ended December 31, 1998:
Basic Net Income per Share ............................................. $ 8,065,000 8,659,047 $ 0.93
============
Effect of Stock Options ................................................ 189,004
------------ ------------
Diluted Net Income per Share ........................................... $ 8,065,000 8,848,051 $ 0.91
============ ============ ============
Year Ended December 31, 1997:
Basic Net Income per Share ............................................. $ 8,102,000 8,656,634 $ 0.94
============
Effect of Stock Options ................................................ 209,043
------------ ------------
Diluted Net Income per Share ........................................... $ 8,102,000 8,865,677 $ 0.91
============ ============ ============
</TABLE>
In January 2000, the Company purchased 103,050 shares of its common
stock for the treasury for $1,773,000. The Board of Directors of Prima approved
a three for two stock split of the Company's common stock to shareholders of
record on February 10, 2000, distributed February 24, 2000. As a result, the
number of shares of common stock outstanding increased from 5,645,341 to
8,467,744 on the distribution date. All
39
<PAGE> 40
share and per share amounts included in these financial statements have been
restated to show the retroactive effects of the stock split. During 1997, the
shareholders of Prima approved an increase in the number of authorized shares of
common stock from 8,000,000 to 12,000,000 shares.
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.
At December 31, 1999, there are no outstanding hedges. Natural gas
hedge contracts were not recorded on the balance sheet at December 31, 1998. The
fair value of the Company's liability under these contracts was estimated to be
$42,000. The estimated fair value of the natural gas hedge contracts is
determined by multiplying the difference between year end natural gas prices and
the hedge contract price by the quantities under contract.
The fair market value of the Company's debt at December 31, 1999 is
approximately equal to its carrying value since the Company could have obtained
the debt for the same terms at December 31, 1999.
3. AVAILABLE FOR SALE SECURITIES
The Company's available for sale securities are comprised of marketable
equity securities. For the years ended December 31, 1999 and 1998, the Company
sold securities with a market value of $388,000 and $28,000 which resulted in
realized gains and (losses) of ($81,000) and $2,000, respectively. The net
unrealized gain or loss on securities at December 31, 1999 and 1998 is included
in accumulated other comprehensive income, net of deferred income taxes of
($145,000) and $30,000, respectively. The change in net unrealized gain or loss
on securities for the years ended December 31, 1999 and 1998 was determined as
follows:
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
Net unrealized gain, beginning of year ............................ $ 81,000 $ 71,000
Net unrealized gain (loss), end of year ........................... (389,000) 81,000
----------- -----------
Net change in unrealized gain or loss ............................. $ (470,000) $ 10,000
=========== ===========
The components of fair value as of December 31, 1999 and 1998 are as follows:
1999 1998
----------- -----------
Cost (including reinvested distributions) ......................... $ 2,338,000 $ 2,310,000
Gross unrealized gains ............................................ 0 160,000
Gross unrealized losses ........................................... (389,000) (79,000)
----------- -----------
Fair value ........................................................ $ 1,949,000 $ 2,391,000
=========== ===========
4. NOTES PAYABLE AND LINE OF CREDIT
The Company's notes payable consists of the following:
1999 1998
----------- -----------
Total .......................................................... $ 304,000 $ 240,000
Less current portion ........................................... 304,000 120,000
----------- -----------
Long term ...................................................... $ 0 $ 120,000
=========== ===========
</TABLE>
40
<PAGE> 41
The Company has two notes payable at December 31, 1999. The first note
is dated June 10, 1997 and is due on June 10, 2000. Payments of principal and
accrued interest (8% per annum) are to be made in three equal annual
installments on the anniversary date of the note. The note financed the purchase
of oilfield service equipment by Action Oilfield Services, Inc., a wholly owned
subsidiary. The note balance was $120,000 at December 31, 1999. The note is
collateralized by oilfield service equipment. The second note is for $184,000.
It is dated March 10, 1999 and is due in one annual installment of principal and
accrued interest (8% per annum) on March 10, 2000. The note financed the
purchase of oilfield service equipment by Action Energy Services, a newly formed
wholly owned subsidiary. The note is collateralized by oilfield service
equipment.
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 (8.50% at December 31, 1999), with interest
payable monthly. At December 31, 1999 and 1998, there were no amounts
outstanding under the line of credit.
5. 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 15%, 44% and 37% of its
natural gas production in 1999, 1998 and 1997. The Company hedged approximately
25% and 29% of its oil production in 1999 and 1997. No oil was hedged in 1998.
Net hedging gains and losses of ($180,000), ($112,000) and $140,000 were
recognized in 1999, 1998 and 1997, respectively. The Company had no open
positions at December 31, 1999.
6. INCOME TAXES
The provision for income taxes consists of the following components:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Current:
Federal ........................ $ 5,340,000 $ 679,000 $ 524,000
State .......................... 1,118,000 143,000 83,000
----------- ----------- -----------
6,458,000 822,000 607,000
----------- ----------- -----------
Deferred:
Federal ........................ (4,828,000) 2,440,000 2,277,000
State .......................... (652,000) 321,000 166,000
----------- ----------- -----------
(5,480,000) 2,761,000 2,443,000
----------- ----------- -----------
Tax credits ....................... 2,057,000 (523,000) (415,000)
----------- ----------- -----------
Provision for income taxes ........ $ 3,035,000 $ 3,060,000 $ 2,635,000
=========== =========== ===========
</TABLE>
During 1999, 1998 and 1997, the Company recognized income tax
deductions of $1,247,000, $23,000 and $143,000, respectively, from the exercise
of nonqualified stock options. Stockholders' equity has been credited in the
amount of $477,000, $9,000 and $52,000 for the income tax benefit of these
deductions.
41
<PAGE> 42
The significant components of deferred tax assets and deferred tax
liabilities included in the balance sheet are as follows:
<TABLE>
<CAPTION>
1999 1998
----------- -----------
<S> <C> <C>
Deferred Tax Assets:
Minimum tax credit carryforwards ............................... $ 1,617,000 $ 3,674,000
State income taxes ............................................. 261,000 489,000
Accrued bonuses ................................................ 0 109,000
Other .......................................................... 180,000 32,000
----------- -----------
Total Deferred Tax Assets ...................................... 2,058,000 4,304,000
----------- -----------
Deferred Tax Liabilities:
Intangible drilling costs ...................................... 6,780,000 12,796,000
Deferred revenues .............................................. 0 92,000
Depreciation ................................................... 287,000 180,000
Other .......................................................... 533,000 376,000
----------- -----------
Total Deferred Tax Liabilities ................................. 7,600,000 13,444,000
----------- -----------
$ 5,542,000 $ 9,140,000
=========== ===========
</TABLE>
A reconciliation of income tax computed at the federal statutory tax
rate to the Company's effective tax rate is as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Federal statutory income tax rate ............. 34.0% 34.0% 34.0%
Percentage depletion .......................... (2.2) (1.7) (2.6)
Section 29 credits ............................ (10.5) (7.9) (7.2)
State taxes, net of federal benefits .......... 2.6 2.7 1.6
Other ......................................... 1.3 0.4 (1.3)
------ ------ ------
Effective tax rate ........................ 25.2% 27.5% 24.5%
====== ====== ======
</TABLE>
7. 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,
1999, 1998 and 1997. 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.
42
<PAGE> 43
<TABLE>
<CAPTION>
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Revenues
Oil and gas .................................. $ 20,644,000 $ 16,612,000 $ 17,840,000
Oilfield services ............................ 6,764,000 5,222,000 4,135,000
Marketing and trading ........................ 2,318,000 7,806,000 16,025,000
------------ ------------ ------------
Total ...................................... 29,726,000 29,640,000 38,000,000
Corporate revenues ........................... 1,905,000 1,526,000 1,771,000
Intersegment sales ........................... (1,790,000) (1,074,000) (921,000)
------------ ------------ ------------
Per financial statements .................. $ 29,841,000 $ 30,092,000 $ 38,850,000
============ ============ ============
Operating Earnings
Oil and gas .................................. $ 12,217,000 $ 7,039,000 $ 9,830,000
Oilfield services ............................ 984,000 1,007,000 551,000
Marketing and trading ........................ (511,000) 3,854,000 639,000
------------ ------------ ------------
Total ...................................... 12,690,000 11,900,000 11,020,000
Corporate earnings ........................... (628,000) (775,000) (283,000)
------------ ------------ ------------
Per financial statements ................... $ 12,062,000 $ 11,125,000 $ 10,737,000
============ ============ ============
Identifiable Assets
Oil and gas ................................... $ 39,915,000 $ 52,946,000 $ 41,070,000
Oilfield services ............................. 5,757,000 3,160,000 2,466,000
Marketing and trading ......................... 0 282,000 642,000
------------ ------------ ------------
Total ...................................... 45,672,000 56,388,000 44,178,000
Corporate assets .............................. 26,993,000 10,478,000 13,743,000
------------ ------------ ------------
Per financial statements ................... $ 72,665,000 $ 66,866,000 $ 57,921,000
============ ============ ============
Depreciation, Depletion and Amortization Expense
Oil and gas ................................... $ 4,650,000 $ 6,260,000 $ 4,935,000
Oilfield services ............................. 627,000 447,000 344,000
------------ ------------ ------------
Total ...................................... 5,277,000 6,707,000 5,279,000
Corporate ..................................... 190,000 169,000 153,000
------------ ------------ ------------
Per financial statements ................... $ 5,467,000 $ 6,876,000 $ 5,432,000
============ ============ ============
Capital Expenditures
Oil and gas .................................. $ 18,617,000 $ 18,147,000 $ 15,250,000
Oilfield services ............................ 2,600,000 933,000 986,000
------------ ------------ ------------
Total ...................................... 21,217,000 19,080,000 16,236,000
Corporate .................................... 257,000 342,000 306,000
------------ ------------ ------------
Per financial statements ................... $ 21,474,000 $ 19,422,000 $ 16,542,000
============ ============ ============
</TABLE>
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 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.
43
<PAGE> 44
<TABLE>
<CAPTION>
1999 1998 1997
------ ------ ------
<S> <C> <C> <C>
Oil and Gas:
Duke Energy Field Services, Inc. .......... 28% 19% 20%
Ultramar Diamond Shamrock ................. 15 n/a 11
Marketing and Trading:
Colorado Power Partnership ................ n/a 25 10
KN Gas Marketing, Inc. .................... n/a n/a 21
</TABLE>
8. COMMITMENTS AND CONTINGENCIES
OFFICE LEASE
The Company's lease for office space expires November 30, 2000. Rental
expense, net of sublease rental income, totaled $155,000, $126,000 and $112,000
for the years ended December 31, 1999, 1998 and 1997, respectively. The future
minimum annual rental under the non-cancelable operating lease for the year
ending December 31, 2000 is $124,000.
9. BENEFIT PLANS
EMPLOYEE STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan ("the
Plan"), 900,000 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, 1999, options to acquire 669,750 shares of the Company's
common stock were outstanding under the Plan. The exercise prices, which equaled
the market price of the stock on the date of grant, range from $5.89 to $14.08
per share, with a weighted average price of $8.25 per share. As of December 31,
1999, the weighted average remaining contractual life of the options outstanding
is 6 years, 2 months.
A summary of options granted, exercised and outstanding during 1997,
1998 and 1999 is as follows:
<TABLE>
<CAPTION>
Number Weighted Average
of Shares Exercise Prices
------------- ----------------
<S> <C> <C>
Balance at December 31, 1996 .................. 551,250 $ 6.13
Exercised or canceled ......................... (18,750) 5.95
--------
Outstanding at December 31, 1997 .............. 532,500 6.13
Granted during 1998 ........................... 259,500 10.95
Exercised or canceled ......................... (3,750) 6.22
--------
Outstanding at December 31, 1998 .............. 788,250 7.72
Granted during 1999 ........................... 20,250 14.08
Exercised or canceled ......................... (138,750) 6.09
--------
Outstanding at December 31, 1999 .............. 669,750 8.25
========
Exercisable at December 31, 1997 .............. 352,500 6.04
Exercisable at December 31, 1998 .............. 456,000 6.07
Exercisable at December 31, 1999 .............. 414,900 6.72
</TABLE>
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
44
<PAGE> 45
compensation cost has been recognized for the Plan. Had compensation expense for
the Plan been determined based on the fair value at the grant date for the
options awarded in 1995, 1998 and 1999 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:
<TABLE>
<CAPTION>
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
Net income
As reported ...................................... $ 9,027,000 $ 8,065,000 $ 8,102,000
Pro forma ........................................ 8,713,000 7,699,000 8,018,000
Basic net income per share
As reported ...................................... $ 1.05 $ 0.93 $ 0.94
Pro forma ........................................ 1.02 0.89 0.93
Diluted net income per share
As reported ...................................... $ 1.03 $ 0.91 $ 0.91
Pro forma ........................................ 0.99 0.87 0.90
</TABLE>
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:
<TABLE>
<CAPTION>
1999 1998 1995
------ ------ ------
<S> <C> <C> <C>
Expected dividend yield ..................... 0% 0% 0%
Expected price volatility ................... 37% 30% 31%
Risk free interest rate ..................... 6.8% 5.5% 6.6%
Expected life of options (in years) ......... 9 9 9
</TABLE>
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 150,000 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, 15,000 options would be granted each non-employee director. On each
anniversary date of the initial grant, an additional 3,750 options would be
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, 1999, options to acquire
75,000 shares of the company's common stock were outstanding under the plan. The
exercise prices range from $10.00 to $14.75 per share. As of December 31, 1999,
the weighted average remaining contractual life of the options outstanding is 8
years, 11 months.
A summary of options granted, exercised and outstanding during 1998 and
1999 is as follows:
<TABLE>
<CAPTION>
Number Weighted Average
of Shares Exercise Prices
--------- ----------------
<S> <C> <C>
Balance at December 31, 1997 .................. 0 n/a
Granted during 1998 ........................... 60,000 $ 10.00
---------
Outstanding at December 31, 1998 .............. 60,000 10.00
Granted during 1999 ........................... 15,000 14.75
---------
Outstanding at December 31, 1999 .............. 75,000 10.95
=========
Exercisable at December 31, 1998 .............. 0 n/a
Exercisable at December 31, 1999 .............. 12,000 10.00
</TABLE>
45
<PAGE> 46
EMPLOYEE STOCK OWNERSHIP PLAN
The Company has an Employee Stock Ownership Plan ("Plan") and a Trust
to administer the Plan. The Plan 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 year, September 30, and are allocated among the
participants in proportion to their eligible compensation for the Plan year.
Contributions to the plan are payable at a minimum rate of 5% of eligible
salaries. Through the Plan year ended September 30, 1993, the Plan 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 Plan was amended to allow
fully vested employees the option to direct the Plan Trustees to diversify a
portion of their Plan investments by selling a limited percent of Prima common
stock and investing the proceeds, as well as their contributions, in various
investment options. The Plan benefits all full-time employees and includes six
year, 100% vesting provisions. For the years ended December 31, 1999, 1998 and
1997, the Company expensed $224,000, $193,000 and $169,000, respectively, of
contributions payable to the Plan.
10. 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, 1999 and 1998 was
$257,000. During the three years ended December 31, 1999, 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
prospects or 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 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.
46
<PAGE> 47
11. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties .................................... $ 3,347,000 $ 5,169,000 $ 1,427,000
Proved properties ...................................... 123,000 394,000 30,000
Exploration costs ........................................ 1,731,000 1,082,000 1,228,000
Development costs ........................................ 13,416,000 11,502,000 12,565,000
----------- ----------- -----------
Total ................................................. $18,617,000 $18,147,000 $15,250,000
=========== =========== ===========
Amortization per equivalent
barrel of production ................................... $ 3.07 $ 4.58 $ 4.31
=========== =========== ===========
</TABLE>
Results of operations for oil and gas producing activities are as
follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas sales ........................................ $20,644,000 $16,612,000 $17,840,000
----------- ----------- -----------
Expenses
Lease operating expense .................................. 2,012,000 2,041,000 1,720,000
Ad valorem and production taxes .......................... 1,765,000 1,272,000 1,355,000
Depletion of oil and gas properties ...................... 4,650,000 6,260,000 4,935,000
----------- ----------- -----------
8,427,000 9,573,000 8,010,000
----------- ----------- -----------
Income before income taxes ................................. 12,217,000 7,039,000 9,830,000
Income tax expense ......................................... 3,079,000 1,936,000 2,408,000
----------- ----------- -----------
Income from oil and gas producing activities ............... $ 9,138,000 $ 5,103,000 $ 7,422,000
=========== =========== ===========
</TABLE>
The reserve information presented below was prepared by independent
engineers for the years ended December 31, 1999, 1998 and 1997. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting future rates of production and timing of development expenditures.
Oil and gas reserve engineering must be recognized as a subjective process of
estimating underground accumulations of oil and natural gas that cannot be
measured in an exact way. The accuracy of any reserve estimates is a function of
the quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may require revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately produced.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those proved reserves expected to be
recovered through existing wells with existing equipment and operating methods.
47
<PAGE> 48
Proved oil and gas reserves of the Company, all of which are located in
the United States, are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------------------------------
1999 1998 1997
-------------------- -------------------- --------------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
-------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year ............................... 2,826 71,207 3,358 63,490 3,037 52,112
Purchases of oil and
gas reserves in place ......................... 16 318 26 492 27 251
Revisions of previous
estimates ..................................... (83) (2,600) (938) (5,163) (94) (1,843)
Extensions, discoveries and
other additions ............................... 862 68,160 666 18,877 643 18,314
Production ...................................... (322) (7,163) (286) (6,476) (255) (5,344)
Sales of oil and gas reserves
in place ...................................... (31) (5,811) 0 (13) 0 0
-------- -------- -------- -------- -------- --------
End of Year ..................................... 3,268 124,111 2,826 71,207 3,358 63,490
======== ======== ======== ======== ======== ========
Proved developed reserves:
Beginning of year ............................... 2,305 51,538 2,286 48,139 2,087 41,107
End of year ..................................... 2,521 54,079 2,305 51,538 2,286 48,139
</TABLE>
Oil and natural gas prices in effect at each year end used in
calculating reserve estimates are as follows:
<TABLE>
<CAPTION>
1999 1998 1997
------- ------ ------
<S> <C> <C> <C>
Oil (per barrel) .............................................................. $24.68 $10.31 $17.08
Natural gas (per Mcf) ......................................................... 1.90 2.13 2.40
</TABLE>
Standardized measures of discounted future net cash flows relating to
proved oil and gas reserves are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------
1999 1998 1997
------------- ------------- -------------
<S> <C> <C> <C>
Future cash inflows ................ $ 316,417,000 $ 181,082,000 $ 209,689,000
Future production costs ............ (90,302,000) (44,940,000) (51,203,000)
Future development costs ........... (36,107,000) (20,341,000) (22,095,000)
------------- ------------- -------------
Future net cash flows .............. 190,008,000 115,801,000 136,391,000
10% discount factor ................ (81,457,000) (50,483,000) (60,851,000)
Discounted future income taxes ..... (33,085,000) (13,892,000) (17,391,000)
------------- ------------- -------------
Standardized measure of discounted
future net cash flows ........... $ 75,466,000 $ 51,426,000 $ 58,149,000
============= ============= =============
</TABLE>
48
<PAGE> 49
The principal sources of change in the standardized measure of
discounted future net cash flows are as follows:
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
------------ ------------ ------------
<S> <C> <C> <C>
Beginning standardized measure ......................... $ 51,426,000 $ 58,149,000 $ 68,965,000
Sales of oil and gas produced,
net of production costs ............................. (16,867,000) (13,299,000) (14,765,000)
Net changes in prices and production costs ............. 22,566,000 (17,963,000) (29,995,000)
Extensions, discoveries, and improved
recovery, less related costs ........................ 42,530,000 16,262,000 20,922,000
Development costs incurred during the year ............. 6,373,000 4,829,000 5,713,000
Changes in estimated future development costs .......... 2,267,000 4,192,000 (1,402,000)
Revisions of previous quantity
estimates and other ................................. (6,362,000) (10,521,000) (3,658,000)
Purchases of reserves in place ......................... 469,000 464,000 382,000
Sales of reserves in place ............................. (12,886,000) (1,000) 0
Accretion of discount .................................. 5,143,000 5,815,000 6,896,000
Net change in income taxes ............................. (19,193,000) 3,499,000 5,091,000
------------ ------------ ------------
Ending standardized measure ............................ $ 75,466,000 $ 51,426,000 $ 58,149,000
============ ============ ============
</TABLE>
12. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 1999 and 1998.
<TABLE>
<CAPTION>
Three Months Ended
-----------------------------------------------------
3/31/99 6/30/99 9/30/99 12/31/99
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Year Ended December 31, 1999
Revenues ............................................... $ 5,789,000 $ 6,846,000 $ 8,175,000 $ 9,031,000
Gross profit ........................................... 1,816,000 1,979,000 2,831,000 4,102,000
Net income ............................................. 1,515,000 1,776,000 2,389,000 3,347,000
Basic net income per share ............................. 0.18 0.21 0.28 0.39
Diluted net income per share ........................... 0.17 0.20 0.27 0.38
Three Months Ended
-----------------------------------------------------
3/31/98 (1) 6/30/98 9/30/98 12/31/98
----------- ----------- ----------- -----------
Year Ended December 31, 1998
Revenues ............................................... $11,178,000 $ 6,437,000 $ 5,977,000 $ 6,500,000
Gross profit ........................................... 5,895,000 1,747,000 1,499,000 1,515,000
Net income ............................................. 4,139,000 1,469,000 1,250,000 1,207,000
Basic net income per share ............................. 0.48 0.17 0.14 0.14
Diluted net income per share ........................... 0.47 0.17 0.14 0.14
</TABLE>
(1) During the quarter ended March 31, 1998, the Company terminated a gas sales
agreement for $3,850,000, which is included in revenues and gross profit,
and reported net income of $2,500,000 from this non-recurring item.
49
<PAGE> 50
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 16th day of March, 2000.
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
<S> <C> <C>
/s/Richard H. Lewis March 16, 2000
----------------------------------------
Richard H. Lewis Chairman, President, Treasurer,
(Principal Executive and
Financial Officer)
/s/Robert E. Childress March 16, 2000
---------------------------------------
Robert E. Childress Director
/s/Douglas J. Guion March 16, 2000
---------------------------------------
Douglas J. Guion Director
/s/John P. Lockridge March 16, 2000
---------------------------------------
John P. Lockridge Director
/s/George L. Seward March 16, 2000
--------------------------------------
George L. Seward Director
/s/Sandra J. Irlando March 16, 2000
-----------------------------------------
Sandra J. Irlando Vice President of Accounting
and Controller
</TABLE>
50
<PAGE> 51
Exhibit Index
<TABLE>
<CAPTION>
Exhibit
Number Document
- ------ --------
<S> <C>
2 Purchase and Sale Agreement dated January 7, 1999 (incorporated
by reference as Exhibit 2.1 to Form 8-K filed February 5, 1999)
21 Subsidiaries of the Registrant
23 Consent of Deloitte & Touche LLP
27 Financial Data Schedules
</TABLE>
<PAGE> 1
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
Prima Energy Corporation, a Delaware corporation, has one direct wholly owned
subsidiary, Prima Oil & Gas Company, a Colorado corporation.
Prima Oil & Gas Company has three significant wholly owned subsidiaries. These
are as follows:
1. Action Oil Field Services, Inc., a Colorado corporation.
2. Action Energy Services, a Wyoming corporation.
3. Prima Natural Gas Marketing, Inc., a Colorado corporation.
<PAGE> 1
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement
No. 333-41035 on Form S-8 of Prima Energy Corporation of our report dated March
10, 2000 appearing in this Annual Report on Form 10-K of Prima Energy
Corporation for the year ended December 31, 1999.
DELOITTE & TOUCHE LLP
Denver, Colorado
March 20, 2000
<TABLE> <S> <C>
<ARTICLE> 5 <LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K FOR
PRIMA ENERGY CORPORATION FOR THE YEAR ENDED DECEMBER 31, 1999 AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 18,883,000
<SECURITIES> 1,949,000
<RECEIVABLES> 5,329,000
<ALLOWANCES> (45,000)
<INVENTORY> 837,000
<CURRENT-ASSETS> 27,941,000
<PP&E> 85,654,000
<DEPRECIATION> (41,187,000)
<TOTAL-ASSETS> 72,665,000
<CURRENT-LIABILITIES> 6,534,000
<BONDS> 0
0
0
<COMMON> 133,000
<OTHER-SE> 58,775,000
<TOTAL-LIABILITY-AND-EQUITY> 72,665,000
<SALES> 22,962,000
<TOTAL-REVENUES> 29,841,000
<CGS> 12,071,000
<TOTAL-COSTS> 15,448,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 12,062,000
<INCOME-TAX> 3,035,000
<INCOME-CONTINUING> 9,027,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 9,027,000
<EPS-BASIC> 1.05
<EPS-DILUTED> 1.03
</TABLE>
