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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] Annual Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 1998.
[ ] 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 2,706,188 shares of Common Stock held by
non-affiliates of the Registrant as of March 11, 1999 was $40,254,547 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).
As of March 11, 1999, Registrant had outstanding 5,677,424 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 1999 Annual
Meeting of Stockholders.
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
1. and 2. BUSINESS and PROPERTIES.................................... 3
3. LEGAL PROCEEDINGS.............................................. 15
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............................................ 18
6. SELECTED FINANCIAL DATA........................................ 19
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS............................ 20
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
2
PART I
ITEMS 1 and 2. BUSINESS and PROPERTIES
"The Company" or "Prima" is used in this report to refer to Prima
Energy Corporation and its consolidated subsidiaries. Items 1 and 2 contain
"forward-looking statements" 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, Year 2000 compliance and other plans and
objectives of Prima management for future operations and activities and other
such matters. The words "believes," "plans," "intends," "strategy," 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 16.
GENERAL
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 marketing
and trading.
Prima's oil and gas exploration 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., a wholly owned subsidiary of Prima Oil & Gas
Company, is involved in various aspects of the oilfield service business.
In 1997, Prima effected a three for two stock split of its common
stock. All share and per share amounts included in this Form 10-K have been
restated to show the retroactive effects of the stock splits.
OIL AND GAS OPERATIONS
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 also has leased
undeveloped acreage in the Green River Basin located in southwest Wyoming.
The Wattenberg Field Area ("Wattenberg Area") in the Denver Basin and the
Powder River Basin are the Company's principal areas of operation. Prima's
business activities include oil and gas lease acquisition, exploration,
development, production, marketing and operations.
At December 31, 1998, the Company operated 375 producing wells. It
is an objective of the Company to operate, when possible, the oil and gas
properties in which it has economic interests. The Company believes, with the
responsibility and authority as operator, it is in a better position to
control costs, safety, and timeliness of work, as well as other critical
factors affecting the economics of a well.
The Company's natural gas production is marketed pursuant to a
number of gas sales agreements which vary with respect to their specific
provisions, including price, gross volumes and length of contract. During
1998, the average price received for the Company's natural gas production was
$2.00 per Mcf, as compared to $2.39 per Mcf in 1997. The year to year price
decrease was a result of lower natural gas spot prices which were
attributable to a warm winter in the first quarter of 1998, as well as a warm
November and
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December, causing low space heating requirements. Natural gas liquids prices
were also low in 1998, causing the premium to index prices Prima has
historically received for high Btu gas (1,250 Btu) in Wattenberg and the
Powder River Basin to narrow. The Company was, however, aided by its long
term fixed price contract for its Bonny Field natural gas production which
provides for a $5.90 per MMBtu price, and raised Prima's average gas price by
$0.19 per Mcf in 1998. On January 21, 1999, the Company sold all of its
interest in the Bonny Field for $26 million (see 1998 Activity--Bonny Field
on page 6 for more information). The price received for the Company's crude
oil production was $12.71 per barrel in 1998, a decrease of 36% compared to
$19.90 in 1997 due to depressed oil prices experienced in 1998. During 1998,
the Company produced 6,476,000 Mcf of natural gas and 286,000 barrels of oil
compared to 5,344,000 Mcf and 255,000 barrels in 1997. The Company drilled 38
gross (14.94 net) wells in 1998 compared to 50 gross (36.44 net) wells in
1997.
The Company's net proved reserves as of December 31, 1998, as
estimated by the consulting engineering firms of Reed W. Ferrill &
Associates, Inc. (Denver Basin), McCartney Engineering, LLC (Powder River
Basin), and Ryder Scott Company (Wind River Basin), consisted of over 71 Bcf
of natural gas and 2,826,000 barrels of oil having an estimated pretax
discounted present value, using prices in effect at year end, of
approximately $65 million. The year end prices used in the 1998 reserve
report were $2.13 per Mcf and $10.31 per barrel compared to $2.40 per Mcf and
$17.08 per barrel used in the 1997 reserve report. Approximately 74% of
Prima's year end estimated reserves on a barrel of oil equivalent ("BOE")
basis, converted on the basis of six Mcf of natural gas to one barrel of oil,
are proved developed reserves. The 1998 reserves are approximately 81%
attributable to natural gas, and 19% to crude oil.
A summary of the Company's key statistics by area of activity at
December 31, 1998 and for the year then ended is as follows:
Percent of Average Daily Net Production Percent of
Proved ------------------------------------- Oil and Gas
Reserves Oil (bbls) Gas (Mcf) Revenue
-------------- ---------------- ------------------- ---------------
1998 1997 1998 1997 1998 1997 1998 1997
------ ------ ------ ------ -------- ---------- ------ ------
Wattenberg Area
(including DIA).. 64% 77% 692 680 10,310 10,265 62% 75%
Bonny Field ........ 6 4 0 0 864 763 11 9
Wind River Basin ... 9 8 16 9 4,307 3,004 17 13
Powder River Basin . 21 11 76 10 2,261 590 10 3
The Company plans to continue to identify, develop and exploit
opportunities in all of its areas of oil and gas operations over the next few
years. The Company intends to build upon past success utilizing the reserve,
production and cash flow from core properties as well as the funds received
from the sale of its Bonny Field assets, to create additional opportunities.
For the foreseeable future, the Company intends to emphasize:
- - Exploitation of the Company's inventory of potential drill sites and
recompletion opportunities based upon its technical evaluation and
activity in the areas where the Company is active.
- - Acquisition of both developed and undeveloped properties. 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. At December 31, 1998, the Company owned interests
in 219,000 gross, 160,000 net, undeveloped acres in its areas of
interest. Effective January 21, 1999, the Company placed $26 million
of proceeds from the sale of its Bonny Field assets in a like-kind-
exchange escrow account with a qualified intermediary. Although the
Company intends to close on qualifying properties pursuant to Internal
Revenue Service requirements, there is no assurance it will be
successful in doing so. If the Company is unable to close on
qualifying properties, the proceeds will be taxable and Prima will
attempt to invest the after tax proceeds of approximately $20 million
in opportunities that meet its criteria.
4
- - Exploration and prospect generation utilizing its own personnel and
outside consultants to develop oil and natural gas prospects for
drilling either solely by the Company or with partners on lease
acreage acquired in Prima's core areas. The Company also acquires
interests in exploratory or development projects through acquisition
or farm-ins from third parties.
1998 ACTIVITY
DENVER BASIN
WATTENBERG AREA
The Wattenberg Area is located approximately 30 miles northeast of
Denver, Colorado and encompasses an area in excess of 1,000 square miles.
Prima's leasehold position in the Wattenberg Area is 16,316 gross, 12,317
net, developed acres, with an additional 9,358 gross, 7,914 net, undeveloped
acres. See "Developed and Undeveloped Acreage" below. The Company's drilling
and production activities have been centered in a portion of the field where
the primary productive reservoirs are the Codell and Niobrara formations with
occasional production from the J-Sand, Parkman and Sussex formations. The
Codell and Niobrara reservoirs blanket large areas of the field and have
moderate porosity and low permeability. These two formations, therefore,
require stimulation to establish economic production. Recoverable reserves in
any individual well bore are controlled by reservoir quality, reservoir
thickness, the gas-to-oil ratio, and fracture stimulation techniques. The
Company has developed an extensive database of well information and
production history. The 1998 production from Prima's Wattenberg Area
properties accounted for approximately 62% of total oil and gas revenues,
with natural gas production averaging 10,310 Mcf per day and oil production
averaging 692 barrels per day net to Prima's interest.
During 1998, the Company refractured 37 wells (35.4 net). The 37
refracs resulted in initial average production increases of 775%, with
average initial daily production rates of 180 Mcf of natural gas and 10
barrels of crude oil per day per well. The Company estimates the average
finding and development costs to develop these incremental reserves were
approximately $5.00 per BOE. The 1998 program primarily targeted wells that
were eligible for Section 29 tax credits of approximately $.65 per Mcf
attributable to production through the year 2002. The Company elected not to
drill any new wells in Wattenberg during 1998, due at least in part to the
low product price environment.
The Company intends to continue its development and exploitation
activities in the Wattenberg Area, with the timing of the activities largely
dependent on natural gas and oil prices. At December 31, 1998 the Company
owned or controlled approximately 225 potential drill sites in the Wattenberg
Area. A substantial number of these locations are in areas where the Company
believes historical results of older producing wells have either been
uneconomic or marginally economic. The Company's strategy includes drilling
and completing selected wells in these areas over the next few years
utilizing advanced drilling and completion techniques, improved marketing,
and cost controls in an attempt to enhance the wells' economics and prove up
additional acreage. There is no assurance that any of these locations will
ultimately be drilled or that any wells drilled will ultimately prove to be
commercially productive. At December 31, 1998 the Company had classified 16
undrilled locations in the Wattenberg Area as proved undeveloped reserves in
its year end reserve report, which was down from 45 the prior year. This
decrease was solely attributable to the utilization of the lower prices in
effect at year end 1998, resulting in these locations no longer meeting the
Company's economic criteria. Additionally, the Company included in its year
end reserve report 112 wells with pay zones behind pipe as proved developed
non-producing reserves. The Company expects its primary exploitation efforts
will focus on restimulating its behind pipe reserves over the next few years.
The Company's reserve report contemplates 67 well restimulations or
recompletions and 6 new wells at Wattenberg during 1999, with an estimated
capital expenditure of $5.7 million.
5
DENVER INTERNATIONAL AIRPORT (DIA)
In the second quarter of 1997, Prima acquired a 12,760 gross and
net acre oil and gas lease from the City and County of Denver covering a
portion of its Denver International Airport property. The property is located
approximately 20 miles northeast of downtown Denver. The lease contains a
provision which requires that a well be drilled every 90 days to ultimately
hold all the acreage, that each well hold a 640 acre leasehold interest and
that the Federal Aviation Administration approve each drill site. During
1998, Prima drilled, completed and placed on production three wells at DIA in
which the Company owns 100% working interest. The three productive wells
targeted the "J" sands in the area at approximately 8,100 feet, which is
typically developed on 160 acres per well. A re-entry of an older well was
attempted in 1998, but was plugged and abandoned when caving problems
threatened to stick the drill string. One well was deepened to the Dakota
formation at approximately 8,350 feet in 1998, but was not productive from
that zone. DIA represents approximately 5% of Prima's year end reserves on a
BOE basis. The Company currently operates five gross and net wells in this
area which hold 3,200 acres. During 1999, Prima intends to continue to
evaluate, develop and earn additional acreage by drilling three wells which
have been included in the 1998 reserve report as proved undeveloped
locations. These wells are anticipated to be drilled during late spring and
summer of 1999 at an anticipated total capital expenditure of $934,000. The
ongoing development of DIA will be reviewed following these three wells.
BONNY FIELD
In 1998, Prima's ownership in the Bonny Field located in Yuma
County in eastern Colorado consisted of non-operated working interests
ranging from 15.5% to 33.3% in 135 producing wells. The Company and its
partners participated in the drilling of 21 new wells (4.6 net) in this field
in 1998 with 19 (4.3 net) completed as producers and two (0.31 net) abandoned
as dry holes. The wells produce from the Niobrara Formation at a depth of
approximately 1,800 feet. Prima's leasehold position in the Bonny Field at
year end was 4,771 gross, 787 net, developed acres, with an additional 11,482
gross, 1,857 net, undeveloped acres. For the year ended December 31, 1998,
the Bonny Field accounted for approximately 11% of Prima's oil and gas
revenues with production averaging approximately 864 Mcf of natural gas per
day net to Prima's interest. The natural gas from this field continued to be
sold at a $5.90 per MMBtu price in 1998 pursuant to a long term gas sales
contract that provides for a 95% take-or-pay, and purchases beyond expiration
of the primary term in May 2002. Approximately 6% of Prima's year end
reserves on a BOE basis were attributable to the Bonny Field.
Prima also owned a 15.5% interest in and served as managing
venturer and operator of the gathering and compression entity for the field,
Bonny Gathering Company. During 1998, Prima and the other non- managing
owners completed a renovation and upgrade of this gathering system.
Gathering, compression and dehydration facilities were replaced with new
specially designed equipment in order to enhance deliverability, improve run
times and facilitate ongoing development of the field. The renovation and
upgrade cost approximately $715,000 to Prima's interest.
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. Prima placed the proceeds from this sale in a like-kind exchange
escrow account with a qualified intermediary with the intent of identifying
and closing on certain qualifying properties pursuant to like-kind exchange
provisions of Section 1031 of the Internal Revenue Code. Pursuant to these
tax provisions, Prima must identify qualifying properties within 45 days and
close within 180 days of the closing of the Bonny Field transaction. On March
5, 1999, the Company filed a listing of qualifying properties, which included
oil and gas properties and other real estate properties, with the qualified
intermediary. There is no assurance that the Company will be able to close on
these qualifying properties pursuant to these requirements. In the event the
Company is unable to close on qualifying properties pursuant to these
requirements, the proceeds will be taxable. In that event, the Company
intends to invest the after tax proceeds of approximately $20 million in
opportunities that meet its criteria.
6
POWDER RIVER BASIN
CONVENTIONAL
Prima currently operates 10 wells (9.24 net) in the Powder River
Basin, an extensive basin which covers the Northeast quadrant of the State of
Wyoming. The wells are all located in Campbell County, Wyoming. During 1998,
Prima drilled three Muddy Formation wells in which the Company owns 100%
working interests. The Company now operates six Muddy Formation wells that
reached combined production rates of over 5,700 Mcf and 220 barrels per day
in 1998 and were producing 4,523 Mcf and 108 barrels per day at March 6,
1999. The Company also operates four Turner Formation wells, which produce
from a depth of approximately 10,000 feet.
These wells provide the Company with offset development locations
which the Company intends to develop in the future. The timing of this
development and number of wells drilled will depend upon crude oil and
natural gas prices, drilling commitments due to contractual obligations,
lease expirations, and results of each offsetting well. The Company included
four locations in its 1998 reserve report as proved undeveloped locations
requiring an anticipated capital expenditure of $3,320,000 to drill and
complete.
The Company has identified several additional leads and prospects
in conventional plays in this basin on which future drilling activity is
being evaluated. Oil and gas sales from the area have grown significantly in
1998 and were approximately 19% of Prima's total oil and gas sales for
December 1998. The oil and natural gas revenues from this area represented
approximately 10% of Prima's total oil and gas sales for 1998, and 21% of
year end reserves on a BOE basis. Prima's leasehold position in the Powder
River Basin at December 31, 1998 was 944 gross, 809 net, developed acres,
with an additional 139,738 gross, 133,789 net, undeveloped acres.
COAL SEAM
The Company estimates that approximately 100,000 gross and net
acres of its Powder River Basin undeveloped acreage is prospective in a
burgeoning shallow gas coal seam play. The Wyodak coal seam located at
depths of 250 to 1,500 feet in the basin is starting to be developed by
several producers. According to the Wyoming Oil & Gas Commission, there were
517 coalbed methane wells producing 80.6 MMcf per day as of November 13,
1998. During 1998, Prima drilled three coal seam wells to begin evaluating
its acreage. Prima is encouraged by the results from these wells. Individual
wells in this play are expected to cost approximately $75,000. Reserves per
well can vary considerably but various industry publications typically
estimate average reserves per well at approximately 350 MMcf of natural gas.
The Company cautions that its results may vary considerably depending on the
location of its acreage, results of drilling, thickness of coal, completion
and production methods, and other factors.
Pipeline capacity out of the Powder River Basin is currently
constrained. Two significant pipeline entities have publicly announced plans
to build 24 inch pipelines out of this area by the fall or early winter of
1999. The pipelines are planned to have a capacity of 400,000 to 450,000 Mcf
per day each, for a total of 800,000 to 900,000 Mcf per day. The Bureau of
Land Management has placed a moratorium on new well permits on Federal land,
pending completion of an Environmental Impact Study ("EIS") covering a
significant area of the prospective play. The EIS addresses key issues
including, but not limited to, water disposal from the coal seams and air
quality as a result of compression requirements. The EIS is anticipated to be
completed by the summer of 1999. Depending on the eventual expanse of the
play, additional EIS studies may need to occur. Exploration and development
of fee land was also slowed in 1998 due to litigation involving the ownership
of natural gas within the coal seams underlying fee lands. Pursuant to
federal legislation enacted in November 1998, Prima believes it has a valid
leasehold interest in its fee acreage, which represents approximately 12% of
its total coalbed methane acreage. Approximately 78% of Prima's prospective
acreage in this play is Federal acreage and 10% is state acreage which is not
subject to this dispute.
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The Company intends to monitor this play closely, continuing to
evaluate its acreage and formulate drilling plans, pending completion of the
pipeline projects and the EIS. This play is anticipated to become a
significant area of operations for Prima in the future.
WIND RIVER BASIN
Prima entered the Wind River Basin in 1987 when it participated in
the drilling and completion of two gas wells in the Frontier formation at
depths of approximately 2,700 feet. The Company currently owns between 6.0%
and 24% working interests in 19 gross (1.6 net) producing wells in this basin
located in central Wyoming. Prima operates one producing well in this basin,
and has non-operated working interests in the remainder of the wells.
Production to Prima's interest in this basin is currently located in the Cave
Gulch Unit, and surrounding area, near Waltman, Wyoming. In 1994, Prima
contributed approximately 27 net acres to the formation of the Cave Gulch
Unit ("Unit"), a 440 acre federal unit. Prima owns a 6% non-operated working
interest in 13 wells within the Unit. The Unit was formed to target a thick
section of lenticular sandstones in the Fort Union and Lance formations of
Tertiary and Upper Cretaceous age. More recent drilling activity in the area,
beginning in 1997, has targeted the Frontier, Muddy and Lakota formations at
depths of approximately 17,000 to 19,000 feet.
During the first quarter of 1998, Prima completed the NW Cave Gulch
25-43 in the lower Lance Formation. The Company operates this well in which
it owns a 24% working interest. The well was producing at rates of 3,200 Mcf
and 20 barrels per day when a bridge plug was set and additional uphole pay
completed. The well was producing at rates of approximately 2,100 Mcf and 30
barrels per day from the newly completed zones at year end 1998. Eventually,
the Company intends to remove the bridge plug and commingle the production.
In the fourth quarter of 1998, Prima also participated for a 6% non-operated
working interest in the Cave Gulch Unit #17, a well drilled to a depth of
4,575 feet to test Fort Union sand stringers. The well was producing
approximately 4,750 Mcf per day in January of 1999, and the Company believes
the well sets up 3 to 5 offsetting drillsites. Also in the fourth quarter of
1998, Prima participated for its 15% non-operated share of a Lance Formation
well, the East Cave Gulch #2-29, which was drilled, completed and pending
first sales as of February 1999. The Company also participated for a 6%
interest in the Cave Gulch Unit #12 which was recently drilled and is
currently undergoing completion operations.
During 1998, Prima also participated for its 4.5% non-operated
working interest share of a well located one half mile north of the Unit, the
Cave Gulch Federal #1-29 LAK. The well was scheduled to test the Frontier,
Muddy and Lakota formations to a depth of approximately 19,000 feet. This
well experienced a strong pressure kick in February of 1998 upon drilling two
feet into the Muddy Formation at a depth of 18,175 feet, which necessitated
an immediate connection to an emergency sales line. The well produced between
25 and 45 million cubic feet of gas per day at initial flowing tubing
pressures of 10,800 pounds per square inch and then declining to 8,800 pounds
per square inch when the well blew out on August 13, 1998. Shortly
thereafter, the operator diverted an offsetting well that had recently spud,
the Cave Gulch Federal #4- 19 LAK, to intercept the #1-29 LAK wellbore and
kill the blow out. The #1-29 LAK bridged off naturally, but a cement plug was
still set when the #4-19 LAK intercepted the well bore. A rig was on location
as of March 11, 1999 in an attempt to salvage the #1-29 LAK. If the well
cannot be salvaged, current plans are to drill a replacement well. Prima
owned an 11.2% interest in the Cave Gulch #4-19 LAK at the time it was taken
over and diverted as a kill well for the #1-29 LAK. Insurance purchased by
the operator prior to drilling the #1-29 LAK, and participated in by Prima,
allows for coverage of well control costs and a replacement well. The Company
has been informed that the blowout insurance will cover equipment damages,
relief well, and salvage of the #1-29 LAK if necessary, up to a combined $25
million. If the salvage operations on the #1-29 LAK are not successful and a
replacement well is necessary, the total costs would probably exceed the
insurance proceeds.
The Company has a 1.25% working interest and a .94% overriding
royalty interest in the Cave Gulch Federal 3-29 Deep in the Muddy Formation
and a 1.16% working interest and a .96% overriding royalty interest in the
Frontier and Lakota formations. The 3-29 Deep was originally drilled in 1998
as a Madison, Tensleep test but was not commercially productive in these
formations. Prima did not participate in the
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drilling and testing of these formations. When the #1-29 LAK blew out in the
Muddy Formation, the Wyoming Oil and Gas Conservation Commission allowed the
3-29 Deep to be completed in the Muddy Formation for safety reasons and in
order to prevent waste. Ultimately, a voluntary production unit was formed
for production from the 3-29 Deep. The Unit as formed will allow a set amount
of gas production from each of the Muddy, Frontier and Lakota formations. The
well will be tested in the Lakota and Frontier formations once the agreed
upon amount of gas has been produced from the Muddy Formation.
The Company has been AFE'd for a 7% working interest in the 28-1
Federal, a 19,000 foot Muddy Formation test. This well is located 1/2 mile
east of the #1-29 LAK. The location was being prepared for drilling as of
March 11, 1999. Net costs to Prima to drill and complete this well are
estimated to be $750,000.
Prima's leasehold position in the Wind River Basin is approximately
840 gross, 108 net, developed acres, with an additional 32,501 gross, 22,661
net, undeveloped acres at December 31, 1998. Average daily production from
this area net to Prima's share in 1998 was approximately 4,307 Mcf and 16
barrels per day. The oil and natural gas revenues approximated 17% of Prima's
total oil and gas sales for the year. This area represents about 9% of
Prima's year end reserves on a BOE basis. After considering geological,
engineering and marketing risks, Prima intends to continue its participation
in development of this area on a well-by-well basis as it steps out from
existing production.
OTHER ACTIVITY
Prima owns 71,041 gross, 28,388 net, undeveloped lease acres in the
Greater Green River Basin located in west central Wyoming. During 1997 and
1998, the Company supported, through acreage options, the drilling of two
14,000 exploratory test wells in an area where Prima owns 59,000 gross,
21,800, net acres. Prima did not own an interest in the initial exploratory
wells. At year end, operations on these two wells had been suspended. Prima
intends to monitor activity in this area but has no plans to drill wells in
this area during 1999.
In 1998, Prima participated in an 18,500 foot exploration project
located in Kern County, California. Prima paid approximately $450,000 for its
6.25% working interest share in the project including a prospect fee, acreage
costs and the estimated dry hole costs on the initial exploratory well.
During the drilling of the initial exploratory well, the other working
interest owners elected to sidetrack the well at a considerable additional
cost. Prima elected to go "non-consent" (not to participate) in this change
of operations pursuant to its interpretation of the exploration and operating
agreements. A dispute has arisen over Prima's right to make this election.
According to published reports, the well blew out and ignited in late
November 1998. Similar reports indicate the well continues to blow out
uncontrolled. A relief well is underway and will be used to attempt to kill
the well, which is reported to be totally lost. Prima is currently seeking to
resolve its ownership interest in this project.
PRODUCTION
The Company's net natural gas production averaged 17,742 Mcf per
day for the year ended December 31, 1998 compared to 14,641 Mcf per day for
the year ended December 31, 1997 and 12,694 Mcf per day during the year ended
December 31, 1996. Net oil production averaged 784 barrels per day for the
year ended December 31, 1998 compared to 699 barrels per day during the year
ended December 31, 1997 and 637 barrels per day during the year ended
December 31, 1996. The following table summarizes information with respect to
the Company's producing oil and gas properties for each of these periods.
9
Year Ended December 31,
--------------------------------------------------
1998 1997 1996
------------- ------------ ------------
Quantities Sold:
Natural gas (Mcf) .............................. 6,476,000 5,344,000 4,646,000
Oil (barrels) .................................. 286,000 255,000 233,000
Average Sales Price:
Natural gas (per Mcf) .......................... $ 2.00 $ 2.39 $ 2.11
Oil (per barrel) ............................... $ 12.71 $ 19.90 $ 20.84
Average production (lifting)
costs per equivalent barrel (1) ................ $ 2.43 $ 2.68 $ 2.47
- -------------------
(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).
RESERVES
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 $10.31 per barrel of oil and $2.13 per Mcf of
natural gas at December 31, 1998 compared to $17.08 per barrel of oil and
$2.40 per Mcf of natural gas at December 31, 1997). The future net cash flows
were discounted by ten percent per year as of the end of each of the last
three fiscal periods. The ten percent discount factor is specified by the
Securities and Exchange Commission and is not necessarily the most
appropriate discount rate. Present value, no matter what rate is used, is
materially affected by assumptions as to timing of future production, which
may prove to be inaccurate. For further information concerning the reserves
and the discounted future net cash flows from these reserves, see Note 12 of
the Notes to Consolidated Financial Statements.
December 31,
---------------------------------------------
1998 1997 1996
------------- ------------ ------------
Estimated proved natural gas reserves (Mcf) ...... 71,207,000 63,490,000 52,112,000
Estimated proved oil reserves (barrels) .......... 2,826,000 3,358,000 3,037,000
Present value of estimated future net cash
flows (before future income tax expense) ....... $65,318,000 $75,540,000 $91,446,000
Standardized measure of discounted
future net cash flows .......................... $51,426,000 $58,149,000 $68,965,000
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, 1998.
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 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.
10
Since January 1, 1998, 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.
PRODUCTIVE WELLS
The following table summarizes total gross and net productive wells
for the Company at December 31, 1998.
Productive Wells
-----------------------------------------
Oil Gas
----------------- -----------------------
Gross(1) Net(2) Gross(1)(3) Net(2)(3)
-------- ------- ----------- ----------
Operated:
Colorado ......... 8 7.1 356 287.4
Wyoming .......... 0 0.0 11 9.4
Non-operated:
Colorado ......... 1 0.2 166 32.6
Oklahoma ......... 3 0.2 2 0.1
Wyoming .......... 0 0.0 19 1.5
--- --- ----- -----
Total (3) ....... 12 7.5 554 331.0
--- --- ----- -----
--- --- ----- -----
Additionally, the Company has a royalty interest in 141 of the
gross wells reported above in which it owns a working interest. Also, the
Company has royalty interests in an additional 60 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) Included in these totals are 135 gross, 23.4 net, non-operated wells
located at the Bonny Field, Yuma County, Colorado, which were sold by
the Company in January 1999.
(4) 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.
11
DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 1998, the Company held leased acreage as set forth
below:
Developed Acreage (1) Undeveloped Acreage (2)
-------------------------- --------------------------------
Location Gross (3)(5) Net (4)(5) Gross (3)(5) Net (4)(5)
-------- ------------ ------------- ------------ ------------
Colorado ...... 21,887 13,904 32,480 21,411
Montana ....... 0 0 25,514 25,514
Oklahoma ...... 1,495 57 0 0
Texas ......... 0 0 9,165 8,368
Utah .......... 320 66 1,857 598
Wyoming ....... 1,783 917 218,892 160,450
------- ------- ------- -------
Total ......... 25,485 14,944 287,908 216,341
------- ------- ------- -------
------- ------- ------- -------
- --------------------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acreage are those lease acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil or natural gas, regardless of whether
such acreage contains proved reserves.
(3) A gross acre is an acre in which a working interest is owned. The
number of gross acres is the total number of acres in which a working
interest is owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres
is the sum of the fractional working interests owned in gross acres
expressed as whole numbers and fractions thereof.
(5) Included in these totals are 4,771 gross, 787 net, developed acreage
and 11,482 gross, 1,857 net, undeveloped acreage located at the Bonny
Field, which the Company sold in January 1999.
Many of the leases summarized in the table above as undeveloped
acreage will expire at the end of their respective primary terms unless
production has been obtained from the acreage subject to the lease prior to
that date, in which event the lease will remain in effect until the cessation
of production. The following table sets forth the expiration dates of the
gross and net acres subject to leases summarized in the table of undeveloped
acreage.
Acres Expiring
--------------------
Gross Net
--------- ---------
Twelve Months Ending:
December 31, 1999 ............... 18,912 14,049
December 31, 2000 ............... 10,545 8,437
December 31, 2001 ............... 7,738 6,718
December 31, 2002 ............... 3,025 2,611
December 31, 2003 ............... 9,652 6,775
December 31, 2004 and later ..... 198,001 152,872
12
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling
activities for the years ended December 31, 1998, 1997 and 1996 is set forth
below:
1998 1997 1996
------------------ --------------- ----------------
Gross Net Gross Net Gross Net
-------- -------- ------- ------ ------- ------
Development:
Productive ............ 30 10.52 46 33.74 34 20.03
Dry ................... 2 0.31 0 0.00 0 0.00
-------- -------- ------- ------ ------- ------
32 10.83 46 33.74 34 20.03
-------- -------- ------- ------ ------- ------
-------- -------- ------- ------ ------- ------
Exploratory:
Productive ............ 4 3.05 0 0.00 0 0.00
Dry ................... 2 1.06 4 2.70 2 1.00
-------- -------- ------- ------ ------- ------
6 4.11 4 2.70 2 1.00
-------- -------- ------- ------ ------- ------
-------- -------- ------- ------ ------- ------
Total
Productive ............ 34 13.57 46 33.74 34 20.03
Dry ................... 4 1.37 4 2.70 2 1.00
-------- -------- ------- ------ ------- ------
38 14.94 50 36.44 36 21.03
-------- -------- ------- ------ ------- ------
-------- -------- ------- ------ ------- ------
Since December 31, 1998, the Company has participated in the
drilling of two additional wells, both non-operated wells in the Cave Gulch
area of the Wind River Basin. One of the wells began producing in February
1999 and the other was waiting on completion as of February 28, 1999.
OIL AND GAS 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.
Total revenues from the sales of natural gas and oil produced by
the Company were $16,612,000 or 55% of consolidated revenues, for the year
ended December 31, 1998. During 1998, one purchaser, Duke Energy Field
Services, Inc., accounted for 19% of the Company's total consolidated
revenues. This purchaser is not affiliated with Prima. Although the loss of
this customer could have a material adverse effect on the Company, the
Company believes it would be able to locate alternate customers in the event
of the loss of this purchaser.
The Company has entered into a number of gas sales agreements with
respect to the sale of gas from its producing wells. These contracts vary
with respect to their specific provisions, including price, quantity and
length of contract. The Company's oil production is sold under contracts at
prices which are based upon posted prices. For the year ended December 31,
1998, all of the Company's production from the Bonny Field, which accounted
for approximately 5% of the Company's total natural gas production, was
committed to a gas sales contract that had a fixed price ($5.90 per MMBtu).
On January 21, 1999, the Company closed on the sale of its Bonny properties.
See discussion under 1998 Activity--Bonny Field, located on page 6. At
December 31, 1998, none of the Company's remaining production had been sold
under a fixed price contract or under a contract that required the Company to
deliver any specified amount of production.
In December 1997, Prima agreed to terminate its long-term,
fixed-price with annual escalation contract to supply natural gas to Colorado
Power Partnership (CPP), effective October 31, 1998, for $3,850,000, and
other consideration. The payment and closing was scheduled for, and completed
in January 1998. Prima's participating supply partner, KN Gas Marketing,
Inc., also terminated its obligation to supply CPP. Initial sales to CPP
began in the fall of 1990 and the contract was to expire in the year 2005. As
part
13
of the termination agreement, Prima agreed to supply gas to CPP from January
1, through March 31, 1998 at $2.72 per MMBtu and from April 1, through
October 31, 1998 at a spot related index price. Thereafter, Prima agreed to
supply CPP 2,000 MMBtu per day from November 1, 1998 through March 31, 1999
for $2.315 per MMBtu. Prima's substantial dedication of gas reserves in the
Wattenberg Area in northeast Colorado for the long-term contract was released
effective October 31, 1998.
To hedge its natural gas and crude oil production and purchases for
resale, 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 oil and natural gas spot pricing. As a result of its trading
activities, the Company may also from time to time have open purchase or sale
commitments without corresponding contracts to offset these commitments,
which could result in losses to the Company. The Company attempts to control
its exposure to these risks by monitoring its positions as it deems
appropriate. 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. With the exception of the sale to CPP
through March 31, 1999 discussed above, the Company had no open trading
positions to purchase or deliver natural gas at December 31, 1998.
The Company hedged a portion of its expected natural gas production
in its key area of production, the Rocky Mountain Region, by entering into a
one year commodity swap agreement covering 200,000 MMBtu per month beginning
March 1, 1998 and ending February 28, 1999 at a fixed price of $1.855 per
MMBtu. At December 31, 1998, the Company had an unrealized loss of $42,000 on
the remaining open months of January, and February 1999. As of this writing,
the hedge has expired and the Company realized a $70,000 gain. The Company
also hedged 100,000 MMBtu per month from April 1, 1998 through October 31,
1998 at a price of $1.5675 using a seven month commodity swap. This swap was
entered into to protect the Company should prices decrease in months other
than winter. This off season swap resulted in a hedging loss of $107,000.
During the year ended December 31, 1998, revenues from trading
activities were $3,956,000 representing 13% of the Company's consolidated
revenues. Trading revenues decreased 75% over 1997 trading revenues of
$15,999,000. The decreased trading revenues were attributable to the
previously announced 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.
OILFIELD SERVICES
The Company's oilfield service business is conducted under the name
of Action Oilfield Services, Inc. ("AOS"), a wholly owned subsidiary. At
December 31, 1998, AOS owned seven completion rigs, two swab rigs, ten
tractor trailer rigs used for water hauling, and oilfield rental equipment
including pumps, tanks, work strings, and blow-out preventors. AOS's
historical activities have concentrated in the Wattenberg Area. AOS provides
services on wells owned and operated by Prima and for third parties. During
1998, 21% of AOS's revenues were from activities performed on wells owned by
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. Although drilling activity in the
Wattenberg Area slowed significantly in 1998, an increased level of well
re-works and recompletions resulted in strong utilization of equipment.
Revenues recorded by AOS from third parties during the year ended December
31, 1998 were $4,148,000 or 14% of consolidated revenues. This was a $934,000
or 29% increase over 1997 levels. On March 5, 1999, Action Energy Services
("AES") , a newly formed subsidiary of Prima Oil & Gas Company, purchased the
assets of Star Drilling Company located in Sheridan, Wyoming for $460,000.
This acquisition included two drilling rigs, three water trucks and other
ancillary service equipment. AES intends to offer drilling, completion and
construction services to Prima and others in the Gillette, Wyoming area.
14
MANAGEMENT AND OPERATOR SERVICES
The Company provides management and operator services for
approximately 375 wells which the Company operates pursuant to industry
standard operating agreements with other working interest owners in the
wells. The Company also served as managing venturer and operator of Bonny
Gathering Company in 1998, 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 has agreed to provide transitional operating and
management services through March 31, 1999, at which time it will no longer
operate and manage the Bonny Field system. Revenues attributable to
management and operator services provided to third parties were $1,044,000
for the year ended December 31, 1998, including $405,600 attributable to
Bonny Gathering Company, which was 3% of consolidated revenues.
PHYSICAL PROPERTIES
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, 1998 was $234,000. The
service company and field operations own related equipment, including
completion rigs, swab rigs, tractor trailer rigs used for water hauling,
oilfield rental equipment and various oil field vehicles with a net book
value of $2,194,000 at December 31, 1998.
During 1998, the Company owned a 15.5% interest in Bonny Gathering
Company, a joint venture which owned and operated a gas gathering and
pipeline system located in Yuma County, Colorado. The assets were sold in
January 1999. The book value of this joint venture interest was $329,000 at
December 31, 1998. The facility consisted of over 80 miles of gas gathering
lines, 26 miles of main trunk line, an office and shop building, and related
compression and dehydration facilities.
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, 1998.
The Company leases its Denver office space at an annual rate of
approximately $130,000 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, 1998 of
$233,000.
EMPLOYEES AND OFFICES
As of December 31, 1998, the Company had 88 full-time employees,
including 25 in its Denver office and 63 field employees. Action Oilfield
Services employed 47 of the field employees and 16 were employed in Prima's
field production, pumping and gas gathering activities. The Company believes
its relations with its employees are good. 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, 1998, Prima was not
a party to any legal proceedings which it believed would have a material
impact on the Company.
15
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, 1998.
-----------------------------
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 1998, lower oil and natural gas prices
adversely impacted revenues, earnings and cash flows. 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
16
numerous factors beyond its control, including demand for and supply of oil
and natural gas, general economic conditions, proximity of natural gas
reserves to pipelines, availability and terms for pipeline space, weather
conditions and government regulation.
NEED TO REPLACE RESERVES. As is customary in the oil and gas
exploration and production industry, the Company's future success depends
upon its ability to continue to find, develop or acquire additional oil and
gas reserves that are economically recoverable. Unless the Company replaces
the reserves that it produces through successful development, exploration or
acquisition, the Company's proved reserves will decline. Further,
approximately 64% of the Company's proved reserves at December 31, 1998, were
located in the Wattenberg Area of the Denver Basin, where wells are
characterized by relatively rapid decline rates. Additionally, approximately
26% of the Company's total proved reserves at December 31, 1998, 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 1998, the Company's hedge agreements
covered approximately 0% and 44% 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.
17
YEAR 2000 ISSUE. The failure to correct a material Year 2000
problem could result in an interruption in, or failure of, certain normal
business activities or operations. Such failures could materially and
adversely affect the Company's results of operations, liquidity and financial
condition. The Company has not yet determined the potential adverse effect
that Year 2000 risks may have on its financial condition, liquidity or
results of operations. The Company's program is expected to significantly
reduce the Company's level of uncertainty about Year 2000 issues and, in
particular, about Year 2000 compliance and readiness of its third party
vendors and associates. The Company believes that, with the modification of
its business systems and completion of its assessment program as scheduled,
the possibility of significant interruptions of normal operations should be
reduced. The cost of Year 2000 compliance has not been specifically tracked
but is not anticipated to be material to the Company's financial position or
results of operations in any given year.
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, 1998 and 1997. These prices have been restated to reflect
the effect of the three for two split of Prima's common stock on March 4,
1997.
Year Ended December 31, 1998 HIGH LOW
---------------------------- ----------- -----------
Quarter Ended March 31, 1998 ................... $ 20.000 $ 17.000
Quarter Ended June 30, 1998 .................... 19.500 16.750
Quarter Ended September 30, 1998 ............... 19.500 13.500
Quarter Ended December 31, 1998 ................ 18.500 12.250
Year Ended December 31, 1997
----------------------------
Quarter Ended March 31, 1997 ................... $ 18.000 $ 13.000
Quarter Ended June 30, 1997 .................... 17.625 13.000
Quarter Ended September 30, 1997 ............... 24.750 15.625
Quarter Ended December 31, 1997 ................ 25.500 17.000
On March 11, 1999 the closing sale price for the Company's common
stock was $15.00 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. The number of
holders of record of Prima's common stock at March 11, 1999 was 1,166.
(c) DIVIDENDS. Holders of common stock are entitled to receive such
dividends as may be declared by Prima's Board of Directors. The Board
declared a special dividend of $0.17 per common share payable to stockholders
of record as of the close of business August 26, 1996. The dividend was paid
August 30, 1996. No dividends were declared or paid in 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.
18
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected consolidated
financial data. This data should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and
the Consolidated Financial Statements and notes thereto.
Year Ended December 31,
--------------------------------------------------------
1998 1997 1996 1995 1994
-------- -------- -------- -------- ---------
(in thousands, except per share data)
Income Statement Data:
Revenues:
Oil and gas sales ................... $16,612 $17,840 $14,657 $11,502 $11,558
Trading revenues .................... 3,956 15,999 10,001 4,604 3,790
Oilfield services ................... 4,148 3,214 2,269 1,487 2,102
Management and operator fees ........ 1,044 1,035 1,003 1,084 1,014
Interest and dividend income ........ 469 546 411 154 143
Other ............................... 3,863 216 280 217 1,477
-------- -------- -------- -------- ---------
30,092 38,850 28,621 19,048 20,084
-------- -------- -------- -------- ---------
Expenses:
Depreciation, depletion
and amortization ................... 6,876 5,432 4,544 4,372 4,313
Lease operating expense ............. 2,041 1,720 1,511 1,432 1,512
Ad valorem and production taxes ..... 1,272 1,355 981 736 863
Cost of trading ..................... 3,936 15,323 9,060 3,613 3,334
Cost of oilfield services ........... 2,701 2,368 1,759 1,170 1,334
General and administrative .......... 2,141 1,915 1,812 1,863 1,925
-------- -------- -------- -------- ---------
18,967 28,113 19,667 13,186 13,281
-------- -------- -------- -------- ---------
Income before income taxes ........... 11,125 10,737 8,954 5,862 6,803
Provision for income taxes ........... 3,060 2,635 2,285 1,370 1,572
-------- -------- -------- -------- ---------
Net Income ........................... $ 8,065 $ 8,102 $ 6,669 $ 4,492 $ 5,231
-------- -------- -------- -------- ---------
-------- -------- -------- -------- ---------
Basic Net Income per Share ........... $ 1.40 $ 1.40 $ 1.15 $ 0.77 $ 0.90
-------- -------- -------- -------- ---------
-------- -------- -------- -------- ---------
Diluted Net Income per Share ......... $ 1.37 $ 1.37 $ 1.14 $ 0.77 $ 0.90
-------- -------- -------- -------- ---------
-------- -------- -------- -------- ---------
Cash Dividends per Share ............. $ 0.00 $ 0.00 $ 0.17 $ 0.00 $ 0.00
-------- -------- -------- -------- ---------
-------- -------- -------- -------- ---------
Balance Sheet Data (at end of period):
Total assets ......................... $66,866 $57,921 $48,006 $38,565 $35,716
Net property and equipment ........... 55,607 43,181 32,325 29,118 28,177
Long-term debt ....................... 120 240 0 0 1,000
Stockholders' equity ................. 51,308 43,214 35,273 29,916 25,353
Working capital ...................... 5,467 7,952 7,863 4,292 848
19
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" 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 16.
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, 1998. 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 $16,789,000 for the year ended
December 31, 1998, compared to $14,685,000 for the year ended December 31,
1997 and $12,156,000 for the year ended December 31, 1996. Net working
capital at December 31, 1998 was $5,467,000 as compared to $7,952,000 at
December 31, 1997. Current assets were $10,673,000 at December 31, 1998
compared to $14,256,000 at December 31, 1997. Current liabilities were
$5,206,000 at December 31, 1998 compared to $6,304,000 at December 31, 1997.
The Company had proceeds from the sales of oil and gas properties and other
equipment and sales of securities of $158,000 in 1998.
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. Prima placed the proceeds from this sale in a like-kind exchange
escrow account with a qualified intermediary with the intent of identifying
and closing on certain qualifying properties pursuant to like-kind exchange
provisions of Section 1031 of the Internal Revenue Code. These qualifying
properties include oil and gas properties and other real estate properties.
In the event the Company is unable to close on qualifying properties pursuant
to these requirements, the proceeds will be taxable. In that event, the
Company intends to invest the after tax proceeds of approximately $20 million
in opportunities that meet its criteria.
The Company invested $18,147,000 in additions to oil and gas
properties during the year ended December 31, 1998, compared to $15,250,000
during the year ended December 31, 1997 and $7,942,000 during the year ended
December 31, 1996. During 1998, $11,502,000 was paid for the Company's share
of development well costs and recompletions, $1,082,000 for exploratory
costs, $5,169,000 for acquisitions of unproved properties and $394,000 for
purchases of proved properties. Other uses of funds in 1998 included
$1,275,000 for purchases of oilfield service equipment and facilities and
office equipment, $540,000 for purchases of marketable securities and $10,000
for treasury stock purchases.
The standardized measure of discounted future net cash flows of the
Company's proved oil and natural gas reserves decreased to $51,426,000 at
December 31, 1998 as compared to $58,149,000 at December 31, 1997 and
$68,965,000 at December 31, 1996. Estimated future net cash flows from proved
oil and natural gas reserves decreased to $115,801,000 at December 31, 1998
compared to $136,391,000 at December 31, 1997 and $176,437,000 at December
31, 1996. Oil reserve volumes at December 31, 1998 decreased 16% and natural
gas reserve volumes increased 12% compared to December 31, 1997. On a barrel
of oil equivalent basis, 1998 reserves increased 5% to 14,694,000 BOE. The
weighted average natural
20
gas price received at December 31, 1998 on Company production was $2.13 per
Mcf, a decrease of $0.27 per Mcf compared to December 31, 1997. The year end
weighted average oil price was $10.31 per barrel, a decrease of $6.77 per
barrel compared to December 31, 1997.
At December 31, 1998, the Company estimates that capital
expenditures of $20,341,000 will be required to develop the Company's proved
undeveloped and proved developed non-producing reserves over the next several
years. Approximately $12,304,000, net of future development costs, of the
estimated future net cash flows of the Company's proved oil and gas reserves
at December 31, 1998 were proved undeveloped reserves.
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
20, 1997, distributed March 4, 1997. As a result, the number of shares of
common stock outstanding increased from 3,860,396 to 5,790,556 on the
distribution date. All share and per share amounts included in this report on
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. During 1998, lower oil and
natural gas prices adversely impacted revenues, earnings and cash flows. 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.
YEAR 2000 ISSUE
The Year 2000 Issue is the result of computer applications being
written using two digits rather than four to define the applicable year. As
the year 2000 approaches, such applications may be unable to accurately
process certain date-based information. The Company believes it has
identified the significant internal computer applications that will require
modification to ensure Year 2000 compliance. Internal and external resources
are being used to make the required modifications and test compliance.
Modification and compliance is proceeding as scheduled and the Company
expects that the modifications should be completed by June 30, 1999. At that
time, the Company's internal computer applications are expected to be Year
2000 compliant.
An assessment of the readiness of third parties with whom the
Company does business, such as customers and vendors, is ongoing. Third
parties with whom the Company has material relationships have been contacted
regarding their Year 2000 issues and responses are being monitored to
determine the potential effect on Prima. The Company's operations would be
impacted by various third parties abilities to be Year 2000 compliant.
The failure to correct a material Year 2000 problem could result in
an interruption in, or failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. The Company has not
yet determined the potential adverse effect that Year 2000 risks may have on
its financial condition, liquidity or results of operations. The Company's
program is expected to significantly reduce the Company's level of
uncertainty about Year 2000 issues and, in particular, about Year 2000
compliance and readiness of its third party
21
vendors and associates. The Company believes that, with the modification of
its business systems and completion of its assessment program as scheduled,
the possibility of significant interruptions of normal operations should be
reduced. The cost of Year 2000 compliance has not been specifically tracked
but is not anticipated to be material to the Company's financial position or
results of operations in any given year.
To mitigate Year 2000 compliance issues at year end, the Company
will back up all internal computer data to ensure the ability to restore that
information. The Company will have hard copies of all important internal
computer information and hard copies of the detail of any assets held by
third parties such as banks and investment brokers. If the Company is unable
to produce its wells or transport or sell its production due to Year 2000
compliance issues, wells will be shut-in until normal operations can be
resumed.
NEW ACCOUNTING PRONOUNCEMENTS
The Company adopted Statement of Financial Accounting Standards
No. 130 "Reporting Comprehensive Income" ("SFAS 130") effective January 1,
1998. SFAS 130 requires that changes in equity during a reporting period,
except transactions with owners in their capacity as owners (for example, the
issuance of common stock and dividends paid on common stock) and transactions
reported as direct adjustments to capital deficit or retained earnings, be
reported as a component of comprehensive income. Comprehensive income is
required to be reported in a financial statement that is displayed with the
same prominence as other financial statements. Statements of comprehensive
income for the years ended December 31, 1998, 1997 and 1996 are included in
the accompanying financial statements.
The Company adopted Statement of Financial Accounting Standards No.
131, "Disclosures about Segments of an Enterprise and Related Information"
("SFAS 131") effective January 1, 1998. SFAS 131 establishes standards for
reporting selected information about operating segments and related
disclosures about products and services, geographic areas, and major
customers. SFAS 131 requires that a public business enterprise report
financial and descriptive information about its operating segments which are
regularly evaluated by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. SFAS 131 also requires that
the financial information be reported on the basis that it used internally
for evaluating segment performance. The Company's adoption of SFAS 131 in
1998 had no impact on its consolidated financial position, results of
operations or cash flows.
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, 2000. The Company has not completed
the process of evaluating the impact that will result from adopting SFAS 133.
22
RESULTS OF OPERATIONS
1998 VS 1997
For the year ended December 31, 1998, the Company earned net income
of $8,065,000, or $1.37 per diluted share, on revenues of $30,092,000,
compared to net income of $8,102,000, or $1.37 per diluted share, on revenues
of $38,850,000 for the year ended December 31, 1997. 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 6.48 Bcf for 1998 compared to 5.34 Bcf in 1997, an increase of
1.14 Bcf or 21%. 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%. 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. 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 $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.
Depreciation, depletion and amortization ("DD&A") rates are
affected by production levels and changes in reserve estimates. Total DD&A
expense was $6,876,000 in 1998 compared to $5,432,000 for 1997, an increase
of $1,444,000 or 27%. 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. Included in DD&A expense for 1998 and 1997 is $616,000 and
$497,000, respectively, attributable to depreciation of service equipment,
furniture and equipment and buildings. Depreciation expense on these assets
increased $119,000, or 24%, due primarily to acquisitions of oilfield service
equipment in 1998.
Lease operating expenses ("LOE") were $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.
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 $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%.
Trading activities fluctuate with natural gas markets and the Company's
ability to develop markets that meet the Company's trading criteria. These
decreases are attributable to the previously announced
23
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.
Oilfield service revenues of $4,148,000 and $3,214,000 for the
years ended December 31, 1998 and 1997, respectively, represent the revenues
earned by Action Oilfield Services, Inc., a wholly owned subsidiary. These
revenues include well servicing fees from seven completion rigs, two swab
rigs, trucking, water hauling, rental equipment and other related activities.
Revenues increased $934,000, or 29% for 1998. Cost 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. The Company's share of fees paid to Action on
owned wells and the costs associated with providing the services are
eliminated in consolidation.
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%. Management and operator fees are earned pursuant to the Company's
roles as operator for approximately 375 oil and gas wells located primarily
in the Wattenberg Area of Weld County, Colorado and as managing venturer of a
joint venture which owned gas gathering and pipeline facilities in the Bonny
Field in Yuma 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. In January
1999, the Company sold its interest in the Bonny Field assets and will no
longer serve as managing venturer and operator. Management and operator fees
attributable to the Bonny Field system were $406,000 for each of 1998 and
1997.
General and administrative expense ("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.
Effective tax rates are affected by amounts of permanent differences between
financial and taxable income, consisting primarily of statutory depletion
deductions and Section 29 tax credits.
1997 VS 1996
For the year ended December 31, 1997, the Company earned net income
of $8,102,000, or $1.37 per diluted share, on revenues of $38,850,000,
compared to net income of $6,669,000, or $1.14 per diluted share, on revenues
of $28,621,000 for the year ended December 31, 1996. Operating expenses were
$28,113,000 for 1997 compared to $19,667,000 for 1996. Revenues increased
$10,229,000 or 36%, expenses increased $8,446,000 or 43% and net income
increased $1,433,000 or 21% in 1997.
Oil and gas sales for the year ended December 31, 1997 were
$17,840,000 compared to $14,657,000 for the year ended December 31, 1996, an
increase of $3,183,000 or 22%. This increase was due primarily to increased
production of both oil and natural gas and to increased natural gas prices.
The Company's net natural gas production was 5.34 Bcf for 1997 compared to
4.65 Bcf in 1996, an increase of .69 Bcf or 15%. Its net oil production was
255,000 barrels compared to 233,000 barrels for the same periods, an increase
of 22,000 barrels or 9%. On a BOE basis, the Company's production for 1997
increased 139,000 BOE or 14%. The average price received per Mcf of natural
gas sold was $2.39 for the year ended
24
December 31, 1997 compared to $2.11 per Mcf for the year ended December 31,
1996, an increase of $.28 per Mcf or 13%. Approximately 5.2% and 5.5% of the
natural gas production for the years ended December 31, 1997 and 1996,
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 $2.20 per Mcf for
the year ended December 31, 1997 and $1.89 per Mcf for the year ended
December 31, 1996. The average price received per barrel of oil sold was
$19.90 for 1997 compared to $20.84 for 1996, a decrease of $0.94 per barrel
or 5%. During the year ended December 31, 1997, the Company hedged
approximately 29% of its oil production and 37% of its natural gas
production. The purpose of these hedges is to provide market price protection
in the volatile environment of oil and natural gas spot pricing. Hedging
gains of $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. During the year
ended December 31, 1996, the Company hedged approximately 25% of its oil
production. Hedging losses of $116,000 reduced the price received per barrel
of oil by $0.50. No natural gas production was hedged in 1996.
DD&A expense was $5,432,000 in 1997 compared to $4,544,000 for
1996, an increase of $888,000 or 20%. The Company's depletion of oil and gas
properties was $4,935,000 or $4.31 per BOE on 1,146,000 equivalent barrels
produced in 1997, compared to $4,210,000 or $4.18 per BOE on 1,007,000
equivalent barrels produced in 1996. Included in DD&A expense for 1997 and
1996 is $497,000 and $334,000, respectively, attributable to depreciation of
service equipment, furniture and equipment and buildings. Depreciation
expense on these assets increased $163,000, or 49%, due primarily to
acquisitions of oilfield service equipment in 1997.
LOE was $1,720,000 for the year ended December 31, 1997 compared to
$1,511,000 for the year ended December 31, 1996. Ad valorem and production
taxes were $1,355,000 and $981,000 for the same periods. Total lifting costs
were 17% of oil and gas revenues and $2.68 per equivalent barrel of
production for 1997 compared to 17% and $2.47 for 1996. The increased rate
for 1997 was due to workover expenses and additional production taxes
resulting from higher product prices.
Trading revenues were $15,999,000 for 1997 compared to $10,001,000
for 1996, an increase of $5,998,000 or 60%. The Company marketed 7,105,000
MMBtu's of third party gas in 1997 compared to 5,252,000 MMBtu's in 1996, an
increase of 1,853,000 MMBtu's or 35%. Costs of trading were $15,323,000 for
1997 compared to $9,060,000 for 1996, an increase of $6,263,000 or 69%. The
increased trading revenues and costs for 1997 were attributable to purchasing
larger volumes of natural gas at fixed or indexed prices, for resale at
slightly higher fixed or indexed prices, realizing a known margin.
Oilfield service revenues were $3,214,000 for the year ended
December 31, 1997 compared to $2,269,000 for the year ended December 31,
1996. Revenues increased $945,000, or 42% for 1997. Cost of oilfield services
were $2,368,000 for the year ended December 31, 1997 compared to $1,759,000
for the year ended December 31, 1996, an increase of $609,000 or 35%.
Utilization levels in the Wattenberg Area, where the service company is
active, increased above 1996 levels. The Company also purchased additional
equipment which contributed to the increase in revenues. For both the years
ended December 31, 1997 and 1996, 22% of the gross fees billed by Action were
for Company owned wells.
Management and operator fees for the years ended December 31, 1997
and 1996 were $1,035,000 and $1,003,000, respectively, an increase of $32,000
or 3%. G&A totaled $1,915,000 for the year ended December 31, 1997 compared
to $1,812,000 for the year ended December 31, 1996. G&A costs increased by
$103,000 or 6%. The Company's G&A expense has increased due to expansion of
the Company's area of operations. During 1997, the Company capitalized
$120,000 of geological and geophysical costs while no geological and
geophysical costs were capitalized in 1996.
The provision for income taxes was $2,635,000 for the year ended
December 31, 1997 compared to $2,285,000 for the year ended December 31,
1996. The effective tax rate was 24.5% in 1997 compared to 25.5% in 1996.
25
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. The Company had no derivative commodity instruments in
place as of March 11, 1999. During 1998, the Company sold 286,000 barrels of
oil. A hypothetical decrease of $1.03 per barrel (10% of year end 1998
prices) would decrease the Company's production revenues by $295,000 during
1999, assuming that oil production remains at 1998 levels. The Company sold
6.48 Bcf of natural gas in 1998. A hypothetical decrease of $.21 per Mcf (10%
of year end 1998 prices) would decrease the Company's production revenues by
$1,361,000 for 1999, assuming that natural gas production remains at 1998
levels.
26
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 19, 1999 and is hereby incorporated by reference.
27
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM
8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
Independent Auditors' Report ........................................................ 29
Consolidated Balance Sheets at December 31, 1998 and 1997 ........................... 30
Consolidated Statements of Income for the years ended
December 31, 1998, 1997 and 1996 ............................................... 32
Consolidated Statements of Comprehensive Income for the years ended
December 31, 1998, 1997 and 1996 ............................................... 33
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1998, 1997 and 1996 ............................................... 34
Consolidated Statements of Cash Flows for the years ended
December 31, 1998, 1997 and 1996 ............................................... 35
Notes to Consolidated Financial Statements for the years ended
December 31, 1998, 1997 and 1996 ............................................... 36
(a) (2) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are
not applicable or the information required therein is included elsewhere in
the financial statements or notes thereto.
(a) (3) EXHIBITS
The following Exhibits are filed herewith pursuant to Rule 601 of
the Regulation S-K or are incorporated by reference to previous filings.
EXHIBIT NO. DOCUMENT
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
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Company's fiscal
quarter ended December 31, 1998. A Form 8-K dated January 21, 1999, announced
the sale of oil and gas properties and related assets for $26 million. See
Note 10 of the Notes to Consolidated Financial Statements for additional
discussion of this transaction.
28
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, 1998
and 1997, 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, 1998. These financial statements are the
responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of the Company and
its subsidiaries at December 31, 1998 and 1997, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1998 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
March 19, 1999
Denver, Colorado
29
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
ASSETS
1998 1997
-------------- ---------------
CURRENT ASSETS
Cash and cash equivalents ........................ $ 2,522,000 $ 5,644,000
Available for sale securities, at market ......... 2,391,000 1,866,000
Receivables (net of allowance for doubtful
accounts: 1998, $47,000; 1997, $49,000) ....... 4,696,000 5,681,000
Tubular goods inventory .......................... 612,000 882,000
Other current assets ............................. 452,000 183,000
-------------- ---------------
Total current assets ....................... 10,673,000 14,256,000
-------------- ---------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ................ 86,081,000 67,945,000
Less accumulated depreciation,
depletion and amortization .................... (33,135,000) (26,875,000)
-------------- ---------------
Oil and gas properties - net ............... 52,946,000 41,070,000
-------------- ---------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ....................... 4,353,000 3,504,000
Furniture and equipment .......................... 815,000 711,000
Field office, shop and land ...................... 439,000 356,000
-------------- ---------------
5,607,000 4,571,000
Less accumulated depreciation .................... (2,946,000) (2,460,000)
-------------- ---------------
Property and equipment - net ............... 2,661,000 2,111,000
-------------- ---------------
OTHER ASSETS ..................................... 586,000 484,000
-------------- ---------------
$66,866,000 $ 57,921,000
-------------- ---------------
-------------- ---------------
See accompanying notes to consolidated financial
statements.
30
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 1998 AND 1997
LIABILITIES AND STOCKHOLDERS' EQUITY
1998 1997
-------------- ---------------
CURRENT LIABILITIES
Accounts payable .................................. $ 2,122,000 $ 3,250,000
Amounts payable to oil and gas property owners .... 973,000 1,220,000
Ad valorem and production taxes payable ........... 1,552,000 1,279,000
Accrued and other liabilities ..................... 439,000 421,000
Current portion of note payable ................... 120,000 120,000
Deferred income taxes ............................. 0 14,000
-------------- ---------------
Total current liabilities ................... 5,206,000 6,304,000
NOTE PAYABLE ...................................... 120,000 240,000
AD VALOREM TAXES, non-current ..................... 1,088,000 1,280,000
DEFERRED INCOME TAXES ............................. 9,144,000 6,883,000
-------------- ---------------
Total liabilities ........................... 15,558,000 14,707,000
-------------- ---------------
COMMITMENTS AND CONTINGENCIES (Note 8)
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value; 2,000,000
sharesauthorized; no shares issued
or outstanding ................................. 0 0
Common stock, $0.015 par value; 12,000,000
shares authorized; 5,835,556 and
5,833,056 shares issued ........................ 87,000 87,000
Additional paid-in capital ........................ 4,417,000 4,385,000
Retained earnings ................................. 47,550,000 39,485,000
Accumulated other comprehensive income ............ 51,000 44,000
Treasury stock, 63,787 and 63,000 shares at cost .. (797,000) (787,000)
-------------- ---------------
Stockholders' equity - net .................. 51,308,000 43,214,000
-------------- ---------------
$ 66,866,000 $ 57,921,000
-------------- ---------------
-------------- ---------------
See accompanying notes to consolidated financial
statements.
31
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
------------- ------------ -------------
REVENUES
Oil and gas sales ................................ $16,612,000 $17,840,000 $14,657,000
Trading revenues ................................. 3,956,000 15,999,000 10,001,000
Oilfield services ................................ 4,148,000 3,214,000 2,269,000
Management and operator fees ..................... 1,044,000 1,035,000 1,003,000
Interest and dividend income ..................... 469,000 546,000 411,000
Other ............................................ 3,863,000 216,000 280,000
------------- ------------ -------------
30,092,000 38,850,000 28,621,000
------------- ------------ -------------
EXPENSES
Depreciation, depletion and amortization ......... 6,876,000 5,432,000 4,544,000
Lease operating expense .......................... 2,041,000 1,720,000 1,511,000
Ad valorem and production taxes .................. 1,272,000 1,355,000 981,000
Cost of trading .................................. 3,936,000 15,323,000 9,060,000
Cost of oilfield services ........................ 2,701,000 2,368,000 1,759,000
General and administrative ....................... 2,141,000 1,915,000 1,812,000
------------- ------------ -------------
18,967,000 28,113,000 19,667,000
------------- ------------ -------------
INCOME BEFORE INCOME TAXES ....................... 11,125,000 10,737,000 8,954,000
PROVISION FOR INCOME TAXES ....................... 3,060,000 2,635,000 2,285,000
------------- ------------ -------------
NET INCOME ....................................... $ 8,065,000 $ 8,102,000 $ 6,669,000
------------- ------------ -------------
------------- ------------ -------------
BASIC NET INCOME PER SHARE ....................... $ 1.40 $ 1.40 $ 1.15
------------- ------------ -------------
------------- ------------ -------------
DILUTED NET INCOME PER SHARE ..................... $ 1.37 $ 1.37 $ 1.14
------------- ------------ -------------
------------- ------------ -------------
See accompanying notes to consolidated financial
statements.
32
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
------------- ------------ -------------
Net income ............................................ $ 8,065,000 $ 8,102,000 $ 6,669,000
------------- ------------ -------------
Other comprehensive income:
Unrealized gain (loss) on available-for-sale securities 12,000 117,000 (4,000)
Deferred income tax expense related to unrealized
gain on available-for-sale securities ................ (3,000) (47,000) (25,000)
Reclassification adjustment for (gains) losses
included in net income .............................. (2,000) 10,000 70,000
------------- ------------ -------------
7,000 80,000 41,000
------------- ------------ -------------
COMPREHENSIVE INCOME .................................. $ 8,072,000 $ 8,182,000 $ 6,710,000
------------- ------------ -------------
------------- ------------ -------------
See accompanying notes to consolidated financial
statements.
33
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
Accumulated
Additional Other
Common Paid-In Retained Comprehensive Treasury
Stock Capital Earnings Income (Loss) Stock Total
-------- ----------- ------------ -------------- ------------ -------------
BALANCES, January 1, 1996 ....... $ 87,000 $4,222,000 $25,684,000 $ (77,000) $ 0 $ 29,916,000
Net income ...................... 6,669,000 6,669,000
Dividends paid .................. (970,000) (970,000)
Other comprehensive income ...... 41,000 41,000
Treasury stock purchased ........ (383,000) (383,000)
-------- ---------- ----------- ---------- ------------ ------------
BALANCES, December 31, 1996 ..... 87,000 4,222,000 31,383,000 (36,000) (383,000) 35,273,000
Net income ...................... 8,102,000 8,102,000
Common stock issued ............. 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 ..... 87,000 4,385,000 39,485,000 44,000 (787,000) 43,214,000
Net income ...................... 8,065,000 8,065,000
Common stock issued ............. 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 ..... $ 87,000 $4,417,000 $47,550,000 $ 51,000 $ (797,000) $ 51,308,000
-------- ---------- ----------- ---------- ------------ ------------
-------- ---------- ----------- ---------- ------------ ------------
See accompanying notes to consolidated
financial statements.
34
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
1998 1997 1996
-------------- -------------- -------------
OPERATING ACTIVITIES
Net income ............................................ $ 8,065,000 $ 8,102,000 $ 6,669,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization ........... 6,876,000 5,432,000 4,544,000
Deferred income taxes .............................. 2,238,000 2,028,000 1,761,000
Other .............................................. (305,000) 179,000 25,000
Changes in operating assets and liabilities:
Receivables ...................................... 985,000 240,000 (2,834,000)
Inventory ........................................ 270,000 (571,000) (94,000)
Other assets ..................................... (256,000) 32,000 (342,000)
Payables ......................................... (1,102,000) (702,000) 2,380,000
Accrued and other liabilities .................... 18,000 (55,000) 47,000
-------------- -------------- -------------
Net cash provided by operating activities ..... 16,789,000 14,685,000 12,156,000
-------------- -------------- -------------
INVESTING ACTIVITIES
Additions to oil and gas properties ................... (18,147,000) (14,893,000) (7,942,000)
Purchases of other property ........................... (1,275,000) (931,000) (640,000)
Purchases of securities ............................... (540,000) (358,000) (744,000)
Proceeds from sales of property ....................... 130,000 292,000 831,000
Proceeds from sales of securities ..................... 28,000 113,000 418,000
-------------- -------------- -------------
Net cash used in investing activities ......... (19,804,000) (15,777,000) (8,077,000)
-------------- -------------- -------------
FINANCING ACTIVITIES
Treasury stock purchased .............................. (10,000) (404,000) (383,000)
Proceeds from issuance of common stock ................ 23,000 111,000 0
Dividends paid ........................................ 0 0 (970,000)
Repayment of long-term debt ........................... (120,000) 0 0
-------------- -------------- -------------
Net cash used in financing activities ......... (107,000) (293,000) (1,353,000)
-------------- -------------- -------------
Increase (decrease) in cash and cash equivalents ...... (3,122,000) (1,385,000) 2,726,000
Cash and cash equivalents, beginning of year .......... 5,644,000 7,029,000 4,303,000
-------------- -------------- -------------
CASH AND CASH EQUIVALENTS, end of year ................ $ 2,522,000 $ 5,644,000 $ 7,029,000
-------------- -------------- -------------
-------------- -------------- -------------
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets for $600,000 in June
1997. A summary of the transaction is as follows:
Fair value of assets acquired........................... $ 600,000
Cash paid............................................... 240,000
------------
Note payable issued to seller........................... $ 360,000
------------
------------
See accompanying notes to consolidated financial
statements.
35
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
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. The Company's interest in an unincorporated joint venture, Bonny
Gathering Company, is accounted for by the equity method. All significant
intercompany transactions have been eliminated. Certain amounts in prior
years have been reclassified to conform with the classifications at December
31, 1998.
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 statements of cash flows.
Supplemental disclosures of cash flow information:
Cash paid for income taxes was $810,000, $787,000 and $693,000 for
the years ended December 31, 1998, 1997 and 1996, respectively. Cash paid for
interest in 1998 was $20,000. No amounts were paid for interest in 1997 or
1996.
AVAILABLE FOR SALE SECURITIES
The Company classifies all 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
INVENTORY
Inventory consists of tubular goods 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 normal sale or abandonment of undeveloped or producing oil
and gas properties unless 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.
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 which are
evaluated for impairment as described above, are evaluated for impairment
whenever events or changes in circumstances indicate that the carrying amount
may not be recoverable. To date, Prima 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 delivered to the purchaser. At
December 31, 1997, the Company had delivered 8,000 MMBtu's into the pipeline
which had not been delivered to the purchaser. This gas is valued at the
lower of cost or market value. Market value for this purpose is deemed to be
the sales price specified in the contract under which the Company intends to
sell the gas. Included in other current assets at December 31, 1997, is
$19,000 representing the cost of gas which had been delivered into the
pipeline but not delivered to the purchaser. There were no amounts over or
under delivered at December 31, 1998.
37
HEDGING TRANSACTIONS
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, 1998, the Company had no transactions that did not
correspond to anticipated physical transactions. For the years ended December
31, 1998, 1997 and 1996, 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, 1998, 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 receives management fees for services performed as the
managing venturer and operator for a gas gathering and pipeline joint
venture. Such fees are included in income. Income from operating wells for
third parties is recognized 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
COMPREHENSIVE INCOME
The Company adopted Statement of Financial Accounting Standards
No. 130 "Reporting Comprehensive Income" ("SFAS 130") effective January 1,
1998. SFAS 130 requires that changes in equity during a reporting period,
except transactions with owners in their capacity as owners (for example, the
issuance of common stock and dividends paid on common stock) and transactions
reported as direct adjustments to capital deficit or retained earnings, be
reported as a component of comprehensive income. Comprehensive income is
required to be reported in a financial statement that is displayed with the
same prominence as other financial statements. Statements of comprehensive
income for the years ended December 31, 1998, 1997 and 1996 are included in
the accompanying financial statements.
SEGMENT REPORTING
The Company adopted Statement of Financial Accounting Standards No.
131, "Disclosures about Segments of an Enterprise and Related Information"
("SFAS 131") effective January 1, 1998. SFAS 131 establishes standards for
reporting selected information about operating segments and related
disclosures about products and services, geographic areas, and major
customers. SFAS 131 requires that a public business enterprise report
financial and descriptive information about its operating segments which are
regularly evaluated by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. SFAS 131 also requires that
the financial information be reported on the basis that it used internally
for evaluating segment performance. The Company's adoption of SFAS 131 in
1998 had no impact on its consolidated financial position, results of
operations or cash flows.
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, 2000. The Company has not completed
the process of evaluating the impact that will result from adopting SFAS 133.
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).
39
The following table reconciles the numerator and denominator used
in the calculation of basic and diluted net income per share.
Income Shares Per Share
(Numerator) (Denominator) Amount
------------ ------------- ------------
Year Ended December 31, 1998:
Basic Net Income per Share ............. $8,065,000 5,771,843 $ 1.40
-----
-----
Effect of Stock Options ................ 115,161
----------- ---------
Diluted Net Income per Share ........... $8,065,000 5,887,004 $ 1.37
----------- --------- -----
----------- --------- -----
Year Ended December 31, 1997:
Basic Net Income per Share ............. $8,102,000 5,771,089 $ 1.40
-----
-----
Effect of Stock Options ................ 139,362
----------- ---------
Diluted Net Income per Share ........... $8,102,000 5,910,451 $ 1.37
----------- --------- -----
----------- --------- -----
Year Ended December 31, 1996:
Basic Net Income per Share ............. $6,669,000 5,820,594 $ 1.15
-----
-----
Effect of Stock Options ................ 45,536
----------- ---------
Diluted Net Income per Share ........... $6,669,000 5,866,130 $ 1.14
----------- --------- -----
----------- --------- -----
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
20, 1997, distributed March 4, 1997. As a result, the number of shares of
common stock outstanding increased from 3,860,396 to 5,790,556 on the
distribution date. All 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.
Natural gas hedge contracts are not recorded on the balance sheet
at December 31, 1998 and 1997. The fair value of the Company's liability
under these contracts is estimated to be $42,000 and $155,000, respectively.
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, 1998 is
approximately equal to its carrying value since the Company could have
obtained the debt for the same terms at December 31, 1998.
3. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity
securities. For the years ended December 31, 1998 and 1997, the Company sold
securities with a market value of $28,000 and $113,000 which resulted in
realized gains and (losses) of $2,000 and ($10,000), respectively. The net
unrealized gain on securities at December 31, 1998 and 1997 is included in
accumulated other comprehensive income, net of deferred income taxes of
$30,000 and $27,000, respectively. The change in net unrealized gain or loss
on securities for the years ended December 31, 1998 and 1997 was determined
as follows:
40
1998 1997
---------- ---------
Net unrealized gain (loss), beginning of year ........ $ 71,000 $ (56,000)
Net unrealized gain, end of year ...................... 81,000 71,000
--------- ---------
Net change in unrealized gain or loss ................. $ 10,000 $ 127,000
---------- ---------
---------- ---------
The components of fair value as of December 31, 1998 and 1997 are as follows:
1998 1997
----------- ----------
Cost (including reinvested distributions) ............. $ 2,310,000 $1,795,000
Gross unrealized gains ................................ 160,000 111,000
Gross unrealized losses ............................... (79,000) (40,000)
----------- ----------
Fair value ............................................ $ 2,391,000 $1,866,000
----------- ----------
----------- ----------
4. NOTE PAYABLE AND LINE OF CREDIT
The Company's note payable consists of the following:
1998 1997
---------- ---------
Total ................................................. $240,000 $360,000
Less current portion .................................. 120,000 120,000
---------- ---------
Long term ............................................. $120,000 $240,000
---------- ---------
---------- ---------
The note is dated June 10, 1997 and is due on June 10, 2000, with interest at
an annual rate of 8%. Payments of principal and accrued interest on the note
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 is
collateralized by oilfield service equipment with a net book value of
approximately $474,000 at December 31, 1998.
Prima maintains an $8,000,000 unsecured line of credit with a
commercial bank. The line of credit, which matures on May 1, 1999, bears
interest at the bank's prime rate (7.75% at December 31, 1998), with interest
payable monthly. At December 31, 1998 and 1997, there were no amounts
outstanding under the line of credit.
5. HEDGING ACTIVITIES
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 natural gas trading activities that consist of
the purchase and resale of natural gas. 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 44% and 37% of its natural gas production in
1998 and 1997. No natural gas was hedged in 1996. The Company hedged
approximately 29% and 25% of its oil production in 1997 and 1996. No oil was
hedged in 1998.
To hedge its natural gas and crude oil production and purchases for
resale, 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 oil and natural gas spot pricing. As a result of its trading
activities, the Company may also from time to time have open purchase or sale
commitments without corresponding contracts to offset these commitments,
which could result in losses to the Company. The Company attempts to control
its exposure to these risks by monitoring its positions as it deems
appropriate. All hedges or open positions are reviewed by the Chief Executive
Officer before they are committed to, and significant positions are
41
reviewed by the Company's Board of Directors. The Company had no open trading
positions to purchase or deliver natural gas at December 31, 1998. During
1998, the Company had hedged a portion of its expected natural gas production
in its key area of production, the Rocky Mountain Region, by entering into a
one year commodity swap agreement covering 200,000 MMBtu per month beginning
March 1, at a fixed price of $1.855 per MMBtu. At December 31, 1998, the
Company had an unrealized loss of $42,000 on the remaining open months of
January and February 1999.
6. INCOME TAXES
The provision for income taxes consists of the following components:
Year Ended December 31,
---------------------------------------------
1998 1997 1996
----------- ----------- -----------
Current:
Federal ....................................... $ 679,000 $ 524,000 $ 400,000
State ......................................... 143,000 83,000 124,000
----------- ----------- -----------
822,000 607,000 524,000
----------- ----------- -----------
Deferred:
Federal ....................................... 2,440,000 2,277,000 1,741,000
State ......................................... 321,000 166,000 277,000
----------- ----------- -----------
2,761,000 2,443,000 2,018,000
----------- ----------- -----------
Tax credits ...................................... (523,000) (415,000) (257,000)
----------- ----------- -----------
Provision for income taxes ....................... $ 3,060,000 $ 2,635,000 $ 2,285,000
----------- ----------- -----------
----------- ----------- -----------
During 1998 and 1997, the Company recognized income tax deductions
of $23,000 and $143,000, respectively, from the exercise of nonqualified
stock options. Stockholders' equity has been credited in the amount of $9,000
and $52,000 for the income tax benefit of these deductions.
The significant components of deferred tax assets and deferred tax
liabilities included in the balance sheet are as follows:
1998 1997
----------- -----------
Deferred Tax Assets:
Minimum tax credit carryforwards ............ $3,674,000 $3,151,000
State income taxes .......................... 489,000 380,000
Accrued bonuses ............................. 109,000 86,000
Other ....................................... 32,000 32,000
----------- -----------
Total Deferred Tax Assets ................... 4,304,000 3,649,000
----------- -----------
Deferred Tax Liabilities:
Intangible drilling costs ................... 12,796,000 9,963,000
Deferred revenues ........................... 92,000 92,000
Depreciation ................................ 180,000 92,000
Other ....................................... 376,000 399,000
----------- -----------
Total Deferred Tax Liabilities .............. 13,444,000 10,546,000
----------- -----------
$9,140,000 $6,897,000
----------- -----------
----------- -----------
42
A reconciliation of income tax computed at the federal statutory
tax rate to the Company's effective tax rate is as follows:
Year Ended December 31,
-------------------------------
1998 1997 1996
---------- --------- --------
Federal statutory income tax rate .................................... 34.0% 34.0% 34.0%
Percentage depletion ................................................. (1.7) (2.6) (2.7)
Section 29 credits ................................................... (7.9) (7.2) (8.3)
State taxes, net of federal benefits ................................. 2.7 1.6 3.0
Other ................................................................ 0.4 (1.3) (0.5)
---------- --------- --------
Effective tax rate ............................................... 27.5% 24.5% 25.5%
---------- --------- --------
---------- --------- --------
At December 31, 1998, the Company had minimum tax credit
carryforwards of approximately $3,674,000, which may be carried forward
indefinitely.
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) the marketing and trading of third party natural gas and 3)
providing oil field services for wells which it operates and for third
parties. 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, 1998, 1997 and 1996. 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.
1998 1997 1996
------------ ------------ ------------
Revenues
Oil and gas ............................... $17,668,000 $19,075,000 $15,959,000
Marketing and trading ..................... 7,805,000 16,025,000 10,052,000
Oilfield services ......................... 5,222,000 4,135,000 2,894,000
------------ ------------ ------------
Total ................................... 30,695,000 39,235,000 28,905,000
Corporate revenues ........................ 471,000 536,000 340,000
Intersegment sales ........................ (1,074,000) (921,000) (624,000)
------------ ------------ ------------
Per financial statements ............... $30,092,000 $38,850,000 $28,621,000
------------ ------------ ------------
------------ ------------ ------------
Operating Earnings
Oil and gas ............................... $5,944,000 $9,011,000 $7,256,000
Marketing and trading ..................... 3,854,000 639,000 1,058,000
Oilfield services ......................... 857,000 551,000 299,000
------------ ------------ ------------
Total ................................... 10,655,000 10,201,000 8,613,000
Corporate earnings ........................ 470,000 536,000 341,000
------------ ------------ ------------
Per financial statements ................ $11,125,000 $10,737,000 $8,954,000
------------ ------------ ------------
------------ ------------ ------------
43
1998 1997 1996
----------- ----------- -----------
Identifiable Assets
Oil and gas ................................... $58,760,000 $47,256,000 $35,861,000
Marketing and trading ......................... 282,000 642,000 2,011,000
Oilfield services ............................. 3,160,000 2,466,000 1,666,000
----------- ----------- -----------
Total ...................................... 62,202,000 50,364,000 39,538,000
Corporate assets .............................. 4,664,000 7,557,000 8,468,000
----------- ----------- -----------
Per financial statements ................... $66,866,000 $57,921,000 $48,006,000
----------- ----------- -----------
----------- ----------- -----------
Depreciation, Depletion and Amortization Expense
Oil and gas ................................... $6,429,000 $5,088,000 $4,321,000
Oilfield services ............................. 447,000 344,000 223,000
----------- ----------- -----------
Per financial statements ................... $6,876,000 $5,432,000 $4,544,000
----------- ----------- -----------
----------- ----------- -----------
Capital Expenditures
Oil and gas .................................. $18,494,000 $15,556,000 $8,251,000
Oilfield services ............................ 933,000 986,000 331,000
----------- ----------- -----------
Total ...................................... $19,427,000 $16,542,000 $8,582,000
----------- ----------- -----------
----------- ----------- -----------
Total revenue by operating segment includes both sales to
unaffiliated customers, as reported in the Company's consolidated income
statement, and intersegment sales, which are primarily oilfield services
provided to Company owned wells which are eliminated in consolidation.
Oilfield services revenue includes $1,074,000, $921,000 and $624,000 for the
years ended December 31, 1998, 1997 and 1996, respectively, for intersegment
sales. 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.
1998 1997 1996
-------- -------- --------
Oil and Gas:
Duke Energy Field Services, Inc. .................. 19% 20% 19%
Ultramar Diamond Shamrock ......................... n/a 11 15
Marketing and Trading:
Colorado Power Partnership ........................ 25 10 11
KN Gas Marketing, Inc. ............................ n/a 21 21
8. COMMITMENTS AND CONTINGENCIES
NOTE GUARANTEE
Bonny Gathering Company ("Bonny"), an unincorporated joint venture
of which Prima was the managing joint venturer and operator, established a
line of credit with a commercial bank in the amount of $3,500,000 during
1997. The promissory note bore interest at the bank's prime interest rate
less 1/2%, payable monthly on the last day of each calendar month. Funds
could have been advanced on the line of credit through November 30, 1998 and
the note was due November 30, 2001. The note was collateralized by a first
priority mortgage and deed of trust on the assets of Bonny. Prima had
guaranteed its 15.5%
44
proportionate share of the note. At December 31, 1998, Bonny had drawn
$2,165,000 on the note. On January 21, 1999, the note was paid in full.
OFFICE LEASE
During 1995, the Company entered into an agreement to extend its
current operating lease for office space for an additional five years, with a
term through November 30, 2000. Rental expense, net of sublease rental
income, totaled $126,000, $112,000 and $109,000 for the years ended December
31, 1998, 1997 and 1996, respectively. Future minimum annual rentals under
non-cancelable operating leases with remaining terms in excess of one year
are as follows:
Year ending December 31, 1999.................... 132,000
Year ending December 31, 2000.................... 124,000
--------
$ 256,000
--------
--------
9. BENEFIT PLANS
EMPLOYEE STOCK OPTION PLAN
Under the Prima Energy Corporation 1993 Stock Incentive Plan ("the
Plan"), 600,000 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, 1998, options to acquire 525,500 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 $8.83 to $19.25 per share, with a weighted average price of $11.58
per share. As of December 31, 1998, the weighted average remaining
contractual life of the options outstanding is 6 years, 9 months.
A summary of options granted, exercised and outstanding during
1996, 1997 and 1998 is as follows:
Number Weighted Average
of Shares Exercise Prices
--------- ----------------
Balance, December 31, 1995 ............. 367,500 $9.20
Exercised or canceled .................. 0 n/a
---------
Outstanding at December 31, 1996 ....... 367,500 9.20
Exercised or canceled .................. (12,500) 8.93
---------
Outstanding at December 31, 1997 ....... 355,000 9.20
Granted during 1998 .................... 173,000 16.42
Exercised or canceled .................. (2,500) 9.33
---------
Outstanding at December 31, 1998 ....... 525,500 11.58
---------
---------
Exercisable at December 31, 1996 ....... 171,000 9.00
Exercisable at December 31, 1997 ....... 235,000 9.06
Exercisable at December 31, 1998 ....... 304,000 9.10
The Company has adopted the disclosure-only provisions of Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"). Accordingly, no compensation 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 and 1998 consistent with the provisions of SFAS 123, the Company's
net income and net income per share would have been reduced to the pro forma
amounts indicated below:
45
1998 1997 1996
-------------- -------------- --------------
Net income
As reported ...................... $8,065,000 $8,102,000 $6,669,000
Pro forma ........................ 7,636,000 8,018,000 6,509,000
Basic net income per share
As reported ...................... $1.40 $1.40 $1.15
Pro forma ........................ 1.32 1.39 1.12
Diluted net income per share
As reported ...................... $1.37 $1.37 $1.14
Pro forma ........................ 1.30 1.36 1.11
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:
1998 1995
---- ----
Expected dividend yield ................ 0% 0%
Expected price volatility .............. 30% 31%
Risk free interest rate ................ 5.5% 6.6%
Expected life of options (in years) .... 9 9
NON-EMPLOYEE DIRECTORS' STOCK OPTION PLAN
The Board of Directors adopted the Prima Energy Corporation
Non-Employee Directors' Stock Option Plan effective September 18, 1998,
subject to stockholder approval at the 1999 Annual Meeting of Stockholders.
The plan reserves 100,000 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, 10,000 options would be granted each non-employee
director. On each anniversary date of the initial grant, an additional 2,500
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. As of December
31, 1998, options to purchase 40,000 shares had been granted under the plan.
The option price is $15.00 per share. If the fair market value of the
underlying stock exceeds the exercise price on the date of shareholder
approval, compensation expense would be recognizable by the Company.
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 in various
investment options. The Plan benefits all full-time employees and includes
six year, 100% vesting provisions. For the years ended December 31, 1998,
1997 and 1996, the Company expensed $193,000, $169,000 and $125,000,
respectively, of contributions payable to the Plan.
46
10. SUBSEQUENT EVENTS
The Company sold certain of its oil and gas properties and related
assets on January 21, 1999, for approximately $26,000,000 (subject to certain
closing and post closing adjustments). The assets sold consisted of all of
the Company's interest in 16,253 gross acres and 135 producing wells and
related equipment in the Bonny Field in Yuma County, Colorado. Prima also
sold its 15.5% interest in the Bonny Gathering Company joint venture, which
owned the pipeline, gathering, compression and dehydration facilities at the
Bonny Field.
The sales proceeds have been placed in a like-kind exchange escrow
account with Norwest Bank Colorado, National Association as escrow agent. The
Company intends to identify and close on certain qualifying properties
pursuant to the like-kind exchange provisions of Section 1031 of the Internal
Revenue Code of 1986. Pursuant to these tax provisions, Prima must identify
the qualifying properties within 45 days and close within 180 days of the
closing of the Bonny Field transaction. On March 5, 1999, the Company filed a
listing of qualifying properties with the escrow agent. This list included
oil and gas properties and other real estate properties. There is no
assurance the Company will be able to close on these properties within the
applicable time limit. To the extent the Company does not close on qualifying
properties, the unexpended funds will be disbursed from the escrow account to
Prima and will be subject to federal and state income taxes.
11. TRANSACTIONS WITH RELATED PARTIES
The Company is a 6% limited partner in a real estate limited
partnership which currently owns approximately 22 acres of undeveloped land
in Phoenix, Arizona for investment and capital appreciation. The partnership
owns the 22 acres free and clear. One of the general partners of the
partnership is a company controlled by a brother of the Company's president.
The Company participated on the same basis as the other limited partners.
This transaction was approved by the disinterested members of the Company's
Board of Directors. The carrying value of this investment at December 31,
1998, was $257,000. During the three years ended December 31, 1998, 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.
47
12. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
Year Ended December 31,
--------------------------------------------
1998 1997 1996
------------ ------------- ------------
Acquisition costs:
Unproved properties ....................... $ 5,169,000 $ 1,427,000 $ 873,000
Proved properties ......................... 394,000 30,000 63,000
Exploration costs ........................... 1,082,000 1,228,000 401,000
Development costs ........................... 11,502,000 12,565,000 6,605,000
----------- ----------- -----------
Total .................................... $18,147,000 $15,250,000 $ 7,942,000
----------- ----------- -----------
----------- ----------- -----------
Amortization per equivalent
barrel of production ...................... $ 4.58 $ 4.31 $ 4.18
----------- ----------- -----------
----------- ----------- -----------
Results of operations for oil and gas producing activities are as
follows:
Year Ended December 31,
--------------------------------------------
1998 1997 1996
------------ ------------- ------------
Revenues
Oil and gas sales ......................... $16,612,000 $17,840,000 $14,657,000
----------- ----------- -----------
Expenses
Lease operating expense ................... 2,041,000 1,720,000 1,511,000
Ad valorem and production taxes ........... 1,272,000 1,355,000 981,000
Depreciation, depletion and amortization .. 6,260,000 4,935,000 4,210,000
----------- ----------- -----------
9,573,000 8,010,000 6,702,000
----------- ----------- -----------
Income before income taxes .................. 7,039,000 9,830,000 7,955,000
Income tax expense .......................... 1,936,000 2,408,000 2,029,000
----------- ----------- -----------
Income from oil and gas producing activities $ 5,103,000 $ 7,422,000 $ 5,926,000
----------- ----------- -----------
----------- ----------- -----------
The reserve information presented below was prepared by independent
engineers for the years ended December 31, 1998 and 1997 and by Company
personnel for the year ended December 31, 1996. 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.
48
Proved oil and gas reserves of the Company, all of which are
located in the United States, are as follows:
Year Ended December 31,
------------------------------------------------------------------------
1998 1997 1996
------------------- -------------------- ---------------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- -------- -------- -------- -------- ---------
Proved reserves:
Beginning of year .............. 3,358 63,490 3,037 52,112 2,734 47,711
Purchases of oil and
gas reserves in place ........ 26 492 27 251 14 231
Revisions of previous
estimates .................... (938) (5,163) (94) (1,843) 130 2,444
Extensions, discoveries and
other additions .............. 666 18,877 643 18,314 392 6,372
Production ..................... (286) (6,476) (255) (5,344) (233) (4,646)
Sales of oil and gas reserves
in place ..................... 0 (13) 0 0 0 0
------- -------- -------- -------- -------- ---------
End of Year .................... 2,826 71,207 3,358 63,490 3,037 52,112
------- -------- -------- -------- -------- ---------
------- -------- -------- -------- -------- ---------
Proved developed reserves:
Beginning of year .............. 2,286 48,139 2,087 41,107 1,853 38,076
End of year .................... 2,305 51,538 2,286 48,139 2,087 41,107
Oil and natural gas prices in effect at each year end used in
calculating reserve estimates are as follows:
1998 1997 1996
-------- -------- ---------
Oil (per barrel) ....................... $10.31 $17.08 $24.69
Natural gas (per Mcf) .................. 2.13 2.40 3.76
Standardized measures of discounted future net cash flows relating
to proved oil and gas reserves are as follows:
Year Ended December 31,
------------------------------------------------------
1998 1997 1996
---------------- ---------------- ----------------
Future cash inflows .................... $181,082,000 $209,689,000 $271,196,000
Future production costs ................ (44,940,000) (51,203,000) (77,211,000)
Future development costs ............... (20,341,000) (22,095,000) (17,548,000)
---------------- ---------------- ----------------
Future net cash flows .................. 115,801,000 136,391,000 176,437,000
10% discount factor .................... (50,483,000) (60,851,000) (84,991,000)
Discounted future income taxes ......... (13,892,000) (17,391,000) (22,481,000)
---------------- ---------------- ----------------
Standardized measure of discounted
future net cash flows ............... $ 51,426,000 $ 58,149,000 $ 68,965,000
---------------- ---------------- ----------------
---------------- ---------------- ----------------
49
The principal sources of change in the standardized measure of
discounted future net cash flows are as follows:
Year Ended December 31,
--------------------------------------------------
1998 1997 1996
------------- ------------- --------------
Beginning standardized measure ............................. $58,149,000 $68,965,000 $39,180,000
Sales of oil and gas produced,
net of production costs ................................. (13,299,000) (14,765,000) (12,165,000)
Net changes in prices and production costs ................. (17,963,000) (29,995,000) 37,015,000
Extensions, discoveries, and improved
recovery, less related costs ............................ 16,262,000 20,922,000 11,187,000
Development costs incurred during the year ................. 4,829,000 5,713,000 3,077,000
Changes in estimated future development costs .............. 4,192,000 (1,402,000) (558,000)
Revisions of previous quantity
estimates and other ..................................... (10,521,000) (3,658,000) 806,000
Purchases of reserves in place ............................. 464,000 382,000 381,000
Sales of reserves in place ................................. (1,000) 0 0
Accretion of discount ...................................... 5,815,000 6,896,000 3,918,000
Net change in income taxes ................................. 3,499,000 5,091,000 (13,876,000)
------------- ------------- --------------
Ending standardized measure ................................ $51,426,000 $58,149,000 $68,965,000
------------- ------------- --------------
------------- ------------- --------------
13. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 1998 and 1997.
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 .. 0.72 0.25 0.22 0.21
Diluted net income per share 0.70 0.25 0.21 0.21
Three Months Ended
------------------------------------------------------------
3/31/97 6/30/97 9/30/97 12/31/97
------------ ----------- ----------- -----------
Year Ended December 31, 1997
Revenues .................... $11,913,000 $9,460,000 $8,561,000 $8,916,000
Gross profit ................ 3,565,000 2,559,000 2,033,000 2,034,000
Net income .................. 2,677,000 1,954,000 1,577,000 1,894,000
Basic net income per share .. 0.46 0.34 0.27 0.33
Diluted net income per share 0.45 0.33 0.27 0.32
(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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, Prima Energy Corporation has duly caused
this Annual Report on Form 10-K to be signed on its behalf by the
undersigned, thereunto duly authorized, in Denver, Colorado on the 19th day
of March, 1999.
PRIMA ENERGY CORPORATION
By: /s/ Richard H. Lewis
-----------------------------
Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of
1934, this Annual Report on Form 10-K has been signed below by the following
persons in the capacities indicated and on the dates indicated.
SIGNATURE TITLE DATE
/s/Richard H. Lewis March 19, 1999
----------------------------------------
Richard H. Lewis Chairman, President, Treasurer,
(Principal Executive and
Financial Officer)
/s/Robert E. Childress March 19, 1999
---------------------------------------
Robert E. Childress Director
/s/Douglas J. Guion March 19, 1999
---------------------------------------
Douglas J. Guion Director
/s/John P. Lockridge March 19, 1999
---------------------------------------
John P. Lockridge Director
/s/George L. Seward March 19, 1999
---------------------------------------
George L. Seward Director
/s/Sandra J. Irlando March 19, 1999
---------------------------------------
Sandra J. Irlando Vice President of Accounting
and Controller
51