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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, 1997.
[ ] 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. [X]
Aggregate market value of the 2,632,637 shares of Common Stock held by
non-affiliates of the Registrant as of March 13, 1998 was $50,842,802 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).
As of March 13, 1998, Registrant had outstanding 5,770,056 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 1998 Annual Meeting of
Stockholders.
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TABLE OF CONTENTS
<TABLE>
ITEM PAGE
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<S> <C> <C>
PART I
1. and 2. BUSINESS and PROPERTIES..................................... 3
3. LEGAL PROCEEDINGS.............................................. 15
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS............. 15
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
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.................... 25
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE............................ 25
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT............. 26
11. EXECUTIVE COMPENSATION......................................... 26
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT..................................................... 26
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS................. 26
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON
FORM 8-K...................................................... 27
</TABLE>
2
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PART I
ITEMS 1 and 2. BUSINESS and PROPERTIES
"The Company" or "Prima" is used in this report to refer to Prima Energy
Corporation and its consolidated subsidiaries. Items 1 and 2 contain
"forward-looking statements" and are made pursuant to the "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995. These
statements include, without limitation, statements relating to the drilling
and completion of wells, well operations, utilization rates of oilfield
service equipment, reserve estimates (including estimates for future net
revenues associated with such reserves and the present value of such future
net reserves), business strategies and other plans and objectives of Prima
management for future operations and activities and other such matters. The
words "believes," "plans," "intends," "strategy," 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 15.
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 1993, Prima effected a two for one stock split of its common stock.
The Board of Directors of Prima approved a three for two stock split of
its common stock, to stockholders 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 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-Julesburg Basin in northeastern Colorado, the Wind River Basin in
central Wyoming, the Powder River Basin in northeastern Wyoming, and in the
Texas Panhandle. Prima also has leased undeveloped acreage in the Green
River Basin located in southwest Wyoming. The Wattenberg Field Area
("Wattenberg Area") in the Denver- Julesburg Basin is the Company's principal
area of operation. Prima's business activities include oil and gas lease
acquisition, exploration, development, production, marketing and operations.
3
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At December 31, 1997, the Company operated 372 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 1997, the
average price received for the Company's natural gas production was $2.39 per
Mcf, as compared to $2.11 per Mcf in 1996. The price Prima receives for its
natural gas production is higher than the Rocky Mountain spot price because
the Wattenberg Area production is rich gas (approximately 1,250 Btu) which
commands a premium price, and because of its proximity to a major
metropolitan market. Additionally, approximately 5% of Prima's production is
sold pursuant to a $5.90 per MMBtu contract price which raises Prima's
average gas price by approximately $0.19 per Mcf. The price received for the
Company's crude oil production was $19.90 per barrel in 1997, as compared to
$20.84 in 1996. During 1997, the Company produced 5,344,000 Mcf of natural
gas and 255,000 barrels of oil compared to 4,646,000 Mcf and 233,000 barrels
in 1996. The Company drilled 50 gross (36.48 net) wells in 1997 compared to
39 gross (23.04 net) wells in 1996.
The Company's net proved reserves as of December 31, 1997, as estimated
by the consulting engineering firm of Reed W. Ferrill & Associates, Inc.,
consisted of over 63 Bcf of natural gas and 3,358,000 barrels of oil having
an estimated pretax discounted present value, using prices in effect at year
end, of approximately $76 million. 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 and approximately 76% are attributable to natural gas
reserves.
A summary of the Company's key statistics by area of activity at
December 31, 1997 is as follows:
<TABLE>
Percent of Daily Net Production Percent of
Proved ---------------------------------- Oil and Gas
Reserves Oil (bbls) Gas (Mcf) Revenue
-------------- -------------- --------------- ---------------
1997 1996 1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Wattenberg Area................. 77% 90% 680 622 10,265 9,217 75% 77%
Bonny Field..................... 4 5 0 0 763 696 9 10
Wind River Basin................ 8 4 9 12 3,004 2,549 13 12
Powder River Basin.............. 11 1 10 3 590 232 3 1
</TABLE>
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 to create additional
opportunities. For the foreseeable future, the Company intends to emphasize:
- - Further exploitation of the Company's inventory of potential drillsites 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, 1997, the Company owned interests in
221,000 gross, 149,000 net, undeveloped acres in its areas of interest.
4
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- - Prospect generation - The Company utilizes 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.
1997 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 15,439 gross, 11,799
net, developed acres, with an additional 9,551 gross, 7,912 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 1997 production from Prima's
Wattenberg Area properties accounted for approximately 75% of total oil and
gas revenues, with natural gas production averaging 10,265 Mcf per day and
oil production averaging 680 barrels per day net to Prima's interest.
During the second quarter of 1997, the Company commenced a twenty well
(19.7 net) drilling program in the Wattenberg Area. At December 31, 1997,
all twenty of the wells had been drilled. Seventeen of the wells were
completed and on production by December 31, and the remaining three wells
were placed on production in January 1998. Additionally, during 1997 the
Company successfully recompleted 10 wells (9.1 net).
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, 1997 the Company
owned or controlled nearly 250 potential drillsites 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 improve 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, 1997 the Company had classified 45
undrilled locations in the Wattenberg Area as proved undeveloped reserves in
its year-end reserve report. Additionally, the Company included in its year
end reserve report 74 wells with pay zones behind pipe as proved developed
non-producing reserves. The Company expects its primary exploitation efforts
will focus on recompleting or restimulating its behind pipe reserves over the
next few years. The Company's reserve report contemplates 32 recompletions
and 10 new wells at Wattenberg during 1998, with an estimated capital
expenditure of $5,072,000.
5
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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
provisions which require that a well be drilled every 90 days, and that the
Federal Aviation Administration approve each drill site. Prima drilled,
completed and turned to production two wells on this lease in the fourth
quarter of 1997, in which the Company owns a 100% working interest. The
wells targeted the "D" and "J" sands in this area at approximately 8,000
feet. One well was deepened to the Dakota Formation at approximately 8,350
feet but was not productive from that zone. The two wells are both productive
from the "J" Formation. The Company intends to continue to evaluate and
develop this leasehold by drilling two wells which have been included in the
reserve report as proved undeveloped locations. These wells will be drilled
during late spring and early summer of 1998 at an expected capital
expenditure of $560,000. The ongoing development of DIA will be reviewed
following these two wells.
BONNY FIELD
Prima owns non-operated working interests ranging from 15.5% to 33.3% in
approximately 120 producing wells in the Bonny Field located in Yuma County
in eastern Colorado. The wells produce from the Niobrara Formation at a
depth of about 1,800 feet. Prima's leasehold position in the Bonny Field is
4,371 gross, 720 net, developed acres, with an additional 11,882 gross, 1,923
net, undeveloped acres. During 1997 the working interest owners drilled 9
development wells (2.29 net to Prima), which have all been completed and are
producing. For the year ended December 31, 1997, the Bonny Field accounted
for approximately 9% of Prima's oil and gas revenues with production
averaging approximately 763 Mcf of natural gas per day net to Prima's
interest.
The natural gas contract for the Bonny Field, for both existing and new
wells, provides for a $5.90 per MMBtu price, no market-out, 95% take or-pay,
and continued purchases beyond expiration of the primary term in May 2002.
The contract has been fully litigated as to these terms and conditions.
Approximately 4% of Prima's year end reserves on a BOE basis were
attributable to the Bonny Field. Prima intends to participate in the ongoing
development of this field.
Prima also owns a 15.5% interest in and serves as managing venturer and
operator of the gathering and compression entity for the field, Bonny
Gathering Company. Prima and other non-managing owners participated in a
renovation and upgrade of this gathering system beginning the third quarter
of 1997, scheduled for completion the second quarter of 1998. Gathering,
compression and dehydration facilities are being replaced with new specially
designed equipment in order to enhance deliverability of natural gas, improve
run times and facilitate ongoing development of the field. The renovation
and upgrade will cost approximately $600,000 to Prima's interest.
WIND RIVER BASIN
Prima owns between a 4.5% and 50% working interest in 22 wells located
in the Cave Gulch Area of the Wind River Basin in central Wyoming. The
Company operates two of the 22 wells. The Company has been active in this
area since 1987 and 1988 when it participated in the drilling and completion
of two gas wells in the Frontier Formation at depths of approximately 2,700
feet. These two wells are currently not being produced due to high line
pressure on the interstate pipeline in the area of the wells.
6
<PAGE>
In 1994, Prima contributed approximately 27 net acres to the formation
of a 440 acre federal unit, the Cave Gulch Unit ("Unit"), in which Prima owns
a 6% non-operated working interest. 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. Prima has participated for its 6%
interest in 12 wells drilled within the Unit from July 1994 (inception of
drilling within the Unit) through December 31, 1997, including one well
drilled during 1997.
During 1997, Prima participated in the drilling of five wells directly
north of the Unit (North Cave Gulch) in which the Company has non-operated
working interests ranging from 6% to 18%. These wells also targeted the Fort
Union and Lance formations. At year end, two of the wells were producing and
three were being completed. As of March 13, 1998, one additional well had
been completed and was producing, and the remaining two were still in various
stages of completion.
In the fourth quarter of 1997, Prima began drilling its operated
Northwest Cave Gulch #25-43 well approximately one mile west of the Unit.
Prima has a 24% working interest in this well which targeted the Lance
Formation sands at depths ranging from approximately 5,500 to 8,500 feet.
The well reached total depth in January 1998, and completion was in progress
as of March 13, 1998.
During 1997, Prima also participated for its 4.5% non-operated working
interest share of a well located one half mile north of the Unit, and
scheduled to test the Lakota, Dakota, Muddy and Frontier formations to a
depth of approximately 19,000 feet. This well was drilling at year end.
During February 1998, a strong pressure kick was experienced upon drilling
two feet into the Muddy Formation at a depth of 18,175 feet. The kick
necessitated extreme well control measures to avoid a more serious problem
and the possible loss of the wellbore and/or rig. Beginning February 19,
1998, the gas flow was diverted into an emergency sales line at rates that
have varied between 25 and 45 million cubic feet of gas per day on a 31/64
inch dual choke with a flowing tubing pressure in excess of 10,800 pounds per
square inch. Current plans by the operator are to continue to produce the
well and monitor its behavior before deciding whether to continue drilling or
rig down and produce the well from the Muddy and Frontier formations.
Development drilling in the Cave Gulch Area was delayed in 1996 and part
of 1997 pending issuance of an Environmental Impact Study for which the
Record of Decision was issued in August 1997. Drilling in the area has
progressed steadily since completion of the Study. Also in 1997, two major
interstate pipelines completed projects to move additional gas from the
immediate area. Additional capacity is estimated to be approximately 140,000
Mcf per day. Due to additional gas production from the area, however,
pipeline capacity may be constrained from time to time in this area.
Prima's leasehold position in the Wind River Basin is approximately 640
gross, 67 net, developed acres, with an additional 27,584 gross, 17,826 net,
undeveloped acres at December 31, 1997. Average daily production from this
area net to Prima's share in 1997 was approximately 3,004 Mcf and 9 barrels
per day. The oil and natural gas revenues approximated 13% of Prima's total
oil and gas sales for the year. This area represents about 8% 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.
POWDER RIVER BASIN
Prima currently operates 7 wells (6.27 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. The Company
is producing from the Turner Formation at a depth of approximately 10,000
feet in four of its wells, and the Muddy Formation at a depth of
approximately 9,500 in the three remaining wells. Prima's initial well
operations began in this basin in 1994.
7
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During the fourth quarter of 1997 and the first quarter of 1998, Prima
drilled four Muddy Formation wells in which the Company owns from 66.67% to
100% working interests. Three of the four wells were completed and turned to
production by January 1998. These wells are included in the 7 operated well
count in the preceding paragraph. The three wells were producing
approximately 2,200 Mcf of natural gas and 80 barrels per day net to Prima's
interest at March 13, 1998. The fourth well encountered gas shows while
drilling, but the reservoir quality was not sufficient to deem an economic
completion. Consequently, the well was plugged and abandoned. Prima acquired
its right to drill these wells in a farmout agreement, whereby after drilling
the wells Prima earned additional lease acreage and drilling locations. The
three completed and producing wells provide the Company with offset
development locations which the Company intends to drill in 1998. Prima
believes at this time that it has a minimum of three and a maximum of eight
development locations to be drilled in 1998. The amount of locations
actually drilled will depend on results of each offsetting well.
Prima's leasehold position in the Powder River Basin at December 31,
1997, was 459 gross, 391 net, developed acres, with an additional 60,380
gross, 55,585 net, undeveloped acres. Oil and gas sales from the area
approximated 3% of Prima's total oil and gas sales for the year ended
December 31, 1997, averaging 590 Mcf of natural gas and 10 barrels of oil per
day. The Powder River Basin Area contributed 11% of Prima's reserves on a
BOE basis in 1997. The Company has identified several additional leads and
prospects in this basin on which future drilling is anticipated.
OTHER ACTIVITY
During 1997, Prima drilled or re-entered five wells on its Texas
Panhandle acreage. Two of the wells were capable of marginal production, and
three were dry holes. Prima owns a 100% working interest and operates these
wells which tested the Brown Dolomite Formation at a depth of approximately
3,000 feet, and the Red Cave Formation at a depth of approximately 2,800
feet. Prima currently holds 1,444 gross, 1,288 net, developed acres, and
26,954 gross, 25,187 net, undeveloped acres in this area. The Company plans
no additional expenditures, and is considering selling its wells and leases
in this area.
Prima has 66,028 gross, 26,499 net, undeveloped lease acres in the
Greater Green River Basin located in west central Wyoming. The Company has
supported, through acreage options, the drilling of two 14,000 exploratory
test wells in an area where Prima owns about 59,000 gross, 21,800 net, acres.
Prima will not own an interest in the initial exploratory wells. The
initial well commenced operations in September 1997, and the decision was
made by the operator to run casing and attempt completion. The second
exploratory well reached total depth during February 1998 and the operator
elected to run casing. The Company believes the operator will attempt a
completion on these wells in the near future. The results of these two
exploratory wells will be key in evaluating the play and determining Prima's
future activity in this area.
In January 1998, Prima committed to a 6.25% non-operated working
interest in a well to be drilled in Kern County, California. The well is on
a seismically defined structure, and is scheduled to spud in the second
quarter of 1998. This is a high risk well with large reserve potential.
PRODUCTION
The Company's net natural gas production averaged 14,641 Mcf per day for
the year ended December 31, 1997 compared to 12,694 Mcf per day for the year
ended December 31, 1996 and 11,755 Mcf per day during the year ended December
31, 1995. Net oil production averaged 699 barrels per day for the year ended
December 31, 1997 compared to 637 barrels per day during the year ended
December 31, 1996 and 729 barrels per day during the year ended December 31,
1995. The table below summarizes information with respect to the Company's
producing oil and gas properties for each of these periods.
8
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<TABLE>
Year Ended December 31,
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1997 1996 1995
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<S> <C> <C> <C>
Quantities Sold:
Natural gas (Mcf).......................... 5,344,000 4,646,000 4,298,000
Oil (barrels).............................. 255,000 233,000 266,000
Average Sales Price:
Natural gas (per Mcf)...................... $ 2.39 $ 2.11 $ 1.61
Oil (per barrel)........................... $ 19.90 $ 20.84 $ 17.19
Average production (lifting)
costs per equivalent barrel (1)............ $ 2.68 $ 2.47 $ 2.21
</TABLE>
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(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, except as provided by contract. The quantities and
values are based on prices in effect at year end (averaging $17.08 per barrel
of oil and $2.40 per Mcf of natural gas at December 31, 1997 compared to
$24.69 per barrel of oil and $3.76 per Mcf of natural gas at December 31,
1996). 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 13 of the Notes to Consolidated Financial Statements.
<TABLE>
December 31,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Estimated proved natural gas reserves (Mcf).. 63,490,000 52,112,000 47,711,000
Estimated proved oil reserves (barrels)...... 3,358,000 3,037,000 2,734,000
Present value of estimated future net cash
flows (before future income tax expense)... $75,540,000 $91,446,000 $47,785,000
Standardized measure of discounted
future net cash flows...................... $58,149,000 $68,965,000 $39,180,000
</TABLE>
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above table represents estimates
only. Oil and gas reserve engineering must be recognized as a subjective
process of estimating underground accumulations of oil and natural gas that
cannot be measured in an exact way. The accuracy of any reserve estimate is
a function of the quality of available data and engineering, and geological
interpretation and judgment. Results of drilling, testing and production
after the date of the estimate may justify revisions. Accordingly, reserve
estimates are often materially different from the quantities of oil and
natural gas that are ultimately produced. There has been no major discovery
or other favorable event that is believed to have caused a significant upward
change in estimated proved reserves subsequent to December 31, 1997. Oil and
natural gas prices declined during the first quarter of 1998. Oil and
natural gas prices have historically been volatile and are expected to
continue to be so in the future.
9
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Changes in product prices affect the present value of estimated future net
cash flows and the standardized measure of discounted future net cash flows.
Although oil and natural gas prices have declined from those experienced at
year end, the Company does not believe these price declines would result in
an impairment to the book value of its oil and gas properties.
Since January 1, 1997, 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, 1997.
<TABLE>
Productive Wells
---------------------------------------
Oil Gas
---------------- -----------------
Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Operated:
Colorado...................... 8 7.1 354 286.7
Texas......................... 0 0.0 3 2.5
Wyoming....................... 0 0.0 7 6.3
Non-operated:
Colorado...................... 1 0.2 147 28.7
Oklahoma...................... 2 0.2 0 0.0
Utah.......................... 0 0.0 2 0.4
Wyoming....................... 0 0.0 15 1.0
-- --- --- -----
Total (3).................. 11 7.5 528 325.6
-- --- --- -----
-- --- --- -----
</TABLE>
Additionally, the Company has a royalty interest in 127 of the gross
wells reported above in which it owns a working interest. Also, the Company
has royalty interests in an additional 59 gross wells which are not included
in the above table.
- ------------------
(1) A gross well is a well in which a working interest is held. The number of
gross wells is the total number of wells in which a working interest is
owned.
(2) A net well is deemed to exist when the sum of fractional ownership
interests in gross wells equals one. The number of net wells is the sum of
the fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
(3) Wells are classified as oil wells or gas wells according to their
predominate production stream. The totals include 190 dual or triple
completions. Multiple completions are counted as one well.
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DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 1997, the Company held leased acreage as set forth below:
<TABLE>
Developed Acreage (1) Undeveloped Acreage (2)
----------------------- -----------------------
Location Gross (3) Net (4) Gross (3) Net (4)
-------- --------- ------- --------- -------
<S> <C> <C> <C> <C>
Colorado............... 20,568 12,934 35,341 23,110
Nevada................. 0 0 2,240 210
Oklahoma............... 1,875 58 0 0
Texas.................. 1,445 1,288 26,954 25,187
Utah................... 320 66 1,857 598
Wyoming................ 1,100 458 154,474 100,390
------ ------ ------- -------
Total.................. 25,308 14,804 220,866 149,495
------ ------ ------- -------
------ ------ ------- -------
</TABLE>
- ----------------
(1) Developed acres are acres spaced or assigned to productive wells.
(2) Undeveloped acreage are those lease acres on which wells have not been
drilled or completed to a point that would permit the production of
commercial quantities of oil or natural gas, regardless of whether such
acreage contains proved reserves.
(3) A gross acre is an acre in which a working interest is owned. The number
of gross acres is the total number of acres in which a working interest is
owned.
(4) A net acre is deemed to exist when the sum of the fractional ownership
working interests in gross acres equals one. The number of net acres is
the sum of the fractional working interests owned in gross acres expressed
as whole numbers and fractions thereof.
Many of the leases summarized in the table above as undeveloped acreage
will expire at the end of their respective primary terms unless production has
been obtained from the acreage subject to the lease prior to that date, in which
event the lease will remain in effect until the cessation of production. The
following table sets forth the expiration dates of the gross and net acres
subject to leases summarized in the table of undeveloped acreage.
<TABLE>
Acres Expiring
----------------------
Twelve Months Ending: Gross Net
------- ------
<S> <C> <C>
December 31, 1998........................... 26,606 21,413
December 31, 1999........................... 17,808 12,942
December 31, 2000........................... 8,567 6,270
December 31, 2001........................... 4,290 4,290
December 31, 2002........................... 3,675 2,931
December 31, 2003 and later................. 119,260 75,970
</TABLE>
11
<PAGE>
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities for
the years ended December 31, 1997, 1996 and 1995 is set forth below:
<TABLE>
1997 1996 1995
-------------- -------------- --------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Development:
Productive........... 46 33.74 34 20.03 45 15.38
Dry.................. 0 0.00 0 0.00 0 0.00
---- ----- ----- ----- ----- -----
46 33.74 34 20.03 45 15.38
Exploratory:
Productive........... 0 0.00 0 0.00 0 0.00
Dry.................. 4 2.70 2 1.00 4 0.78
---- ----- ----- ----- ----- -----
4 2.70 2 1.00 4 0.78
Total
Productive........... 46 33.74 34 20.03 45 15.38
Dry.................. 4 2.70 2 1.00 4 0.78
---- ----- ----- ----- ----- -----
50 36.44 36 21.03 49 16.16
---- ----- ----- ----- ----- -----
---- ----- ----- ----- ----- -----
</TABLE>
Since December 31, 1997, the Company has participated in the drilling of
ten additional wells. One exploratory well (1.0 net) in the Powder River Basin
was plugged and abandoned in January 1998. One exploratory well (.045 net) at
Cave Gulch commenced production in February 1998. Four development wells (0.8
net) at the Bonny Field also commenced production in February 1998. Four
development wells at Cave Gulch were in various stages of completion as of March
13,1998.
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 in order 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 $17,840,000 or 46% of consolidated revenues, for the year ended
December 31, 1997. During 1997, two purchasers, Duke Energy Field Services,
Inc. and Total Petroleum, accounted for 20%, and 11%, respectively, of the
Company's total consolidated revenues. These two purchasers are not
affiliated with Prima. Although the loss of either of these two customers
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
either or both of these purchasers.
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,
1997, 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).
At December 31, 1997, none of the Company's remaining production, except
those reserves dedicated to a gas sales agreement with a cogeneration
facility discussed below, had been sold under a fixed price contract or under
a contract that required the Company to deliver any specified amount of
production.
12
<PAGE>
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. Prima supplied 70%, and KN Gas
Marketing, Inc. 30%, of CPP's gas requirements for approximately 1,750,000
MMBtu per year. KN Gas Marketing, Inc, has no right or obligation to supply
CPP after December 31, 1997. Initial sales to CPP began in the fall of 1990
and the contract was to expire in the year 2005. From January 1, 1998,
through October 31, 1998, Prima has agreed to supply 100% of CPP's gas
requirements. Prima will receive $2.72 per MMBtu from January 1, 1998
through March 31, 1998, and a spot related index price from April 1, 1998
through October 31, 1998. After that time, CPP and Prima have agreed to
negotiate in good faith a new supply contract through the year 2005, but
neither party has an obligation to supply or purchase from the other.
Prima's substantial dedication of gas reserves in the Wattenberg Area in
northeast Colorado for the long-term contract will be 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 CPP
contract discussed above, the Company had no open trading positions to
purchase or deliver natural gas at December 31, 1997. During 1997, 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 150,000 MMBtu per month, beginning April 1,
at a fixed price of $1.575 per MMBtu. At December 31, 1997, the Company had
an unrealized loss of $155,000 on the remaining open months of January,
February and March 1998.
Subsequent to year end, the Company entered into two additional natural
gas swap agreements to hedge a portion of its expected natural gas
production. The first hedge agreement is for a term of seven months
beginning April 1, 1998 for 100,000 MMBtu per month at a fixed price of
$1.5675 per MMBtu. The second hedge agreement is for a term of twelve months
beginning March 1, 1998 for 200,000 MMBtu per month at a fixed price of
$1.855 per MMBtu.
During the year ended December 31, 1997, revenues from trading
activities, which included the cost of gas purchased or sold for trading
purposes, were $15,999,000 representing 41% of the Company's consolidated
revenues. Trading revenues increased 60% over 1996 trading revenues of
$10,001,000. The increased trading revenues 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. During
1997, sales to KN Gas Marketing, Inc. accounted for 21%, and Colorado Power
Partnership 10% of the Company's total consolidated revenues. As previously
mentioned, the Colorado Power Partnership contract has been terminated with
monetary consideration paid to Prima. The sales to KN Gas Marketing, Inc.
were for a term of one year which expired and were not renewed.
13
<PAGE>
OILFIELD SERVICES
The Company's oilfield service business is conducted under the name of
Action Oilfield Services, Inc. ("Action"), a wholly owned subsidiary. Action
owns seven completion rigs, a swab rig, and various trucking, water hauling
and oilfield rental equipment including pumps, tanks, workstrings and
blow-out preventors. Action's activities are currently concentrated in the
Wattenberg Area. Action provides these services on wells owned and operated
by Prima and for third parties. During 1997, 22% of Action's revenues were
from activities performed on wells owned by Prima. The Company's share of
fees paid to Action 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 has stabilized
at levels lower than those experienced in 1993 and 1994, an increased level
of well re-works and recompletions has resulted in strong utilization of
equipment. Action purchased the assets of Centennial Well Service in June
1997, which added two more working completion rigs to its fleet, bringing the
total to six. Centennial brought experienced employees with a good work
reputation, which further augmented Action's capacity utilization in the
Wattenberg Area. Late in the year, Action refurbished its stacked rig, and
put it into service in January 1998, bringing the rig count to seven.
Revenues recorded by Action from third parties during the year ended December
31, 1997 were $3,214,000 or 8% of consolidated revenues.
MANAGEMENT AND OPERATOR SERVICES
The Company provides management and operator services for approximately
372 wells which the Company operates pursuant to industry standard operating
agreements with other working interest owners in the wells. The Company also
serves as managing venturer and operator of Bonny Gathering Company, a joint
venture formed to construct and operate a natural gas gathering and pipeline
facility in the Bonny Field in eastern Colorado. Revenues attributable to
management and operator services provided to third parties were $1,035,000
for the year ended December 31, 1997, 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, 1997 was $186,000.
The service company and field operations own related equipment, including
completion rigs, a swab rig, water trucks, a dozer, a grader, rental
equipment and various oil field vehicles with a net book value of $1,727,000
at December 31, 1997.
The Company owns a 15.5% interest in Bonny Gathering Company, a joint
venture which owns a gas gathering and pipeline system located in Yuma
County, Colorado. The book value of this partnership interest was $227,000
at December 31, 1997. The facility consists 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 is
$257,000 at December 31, 1997.
The Company leases its Denver office space at an annual rate of $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, 1997 of $198,000.
14
<PAGE>
EMPLOYEES AND OFFICES
As of December 31, 1997, the Company had 76 full-time employees,
including 19 in its Denver office and 57 field employees. Action Oilfield
Services employed 42 of the field employees and 15 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, 1997, Prima is not a
party to any legal proceedings which it believes would have a material impact
on the Company.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of the Company's security holders
during the fourth quarter of the fiscal year ended December 31, 1997.
-------------
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. 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.
15
<PAGE>
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 cancelled 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, inclement weather conditions and financial instability of well
operators and working interest owners. Furthermore, the availability of a
ready market for the Company's oil and natural gas depends on numerous
factors beyond its control, including demand for and supply of oil and
natural gas, general economic conditions, proximity of natural gas reserves
to pipelines, 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 77% of the Company's proved reserves at December 31, 1997, were
located in the Wattenberg Area of the Denver-Julesburg Basin, where wells are
characterized by relatively rapid decline rates. Additionally, approximately
26% of the Company's total proved reserves at December 31, 1997, were
undeveloped. Recovery of such reserves will require significant capital
expenditures and successful drilling 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 1997, the Company's hedge agreements
covered approximately 29% and 37% 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
16
<PAGE>
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
<PAGE>
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, 1997 and 1996. These prices have been restated to reflect
the effect of the three for two split of Prima's common stock on March 4,
1997.
<TABLE>
Year Ended December 31, 1997 HIGH LOW
---------------------------- ------- -------
<S> <C> <C>
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
Year Ended December 31, 1996
----------------------------
Quarter Ended March 31, 1996................ $ 9.333 $ 7.500
Quarter Ended June 30, 1996................. 10.833 7.667
Quarter Ended September 30, 1996............ 11.667 9.750
Quarter Ended December 31, 1996............. 18.500 11.167
</TABLE>
On March 13, 1998 the closing sale price for the Company's common stock
was $19.1875 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 13, 1998 was 1,198.
(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 (restated) 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
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
<PAGE>
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected consolidated
financial data. This data should be read in conjunction with Management's
Discussion and Analysis of Financial Condition and Results of Operations and
the Consolidated Financial Statements and notes thereto.
<TABLE>
Year Ended December 31,
--------------------------------------------------------
1997 1996 1995 1994 1993
-------- -------- -------- -------- --------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues:
Oil and gas sales..................... $ 17,840 $ 14,657 $ 11,502 $ 11,558 $ 11,107
Trading revenues...................... 15,999 10,001 4,604 3,790 2,143
Oilfield services..................... 3,214 2,269 1,487 2,102 1,744
Management and operator fees.......... 1,035 1,003 1,084 1,014 1,063
Interest and dividend income.......... 546 411 154 143 196
Other................................. 216 280 217 1,477 211
-------- -------- -------- -------- --------
38,850 28,621 19,048 20,084 16,464
-------- -------- -------- -------- --------
Expenses:
Depreciation, depletion
and amortization..................... 5,432 4,544 4,372 4,313 3,869
Lease operating expense............... 1,720 1,511 1,432 1,512 1,336
Ad valorem and production taxes....... 1,355 981 736 863 999
Cost of trading....................... 15,323 9,060 3,613 3,334 1,849
Cost of oilfield services............. 2,368 1,759 1,170 1,334 1,112
General and administrative............ 1,915 1,812 1,863 1,925 1,958
-------- -------- -------- -------- --------
28,113 19,667 13,186 13,281 11,123
-------- -------- -------- -------- --------
Income before income taxes............. 10,737 8,954 5,862 6,803 5,341
Provision for income taxes............. 2,635 2,285 1,370 1,572 1,090
-------- -------- -------- -------- --------
Net Income............................. $ 8,102 $ 6,669 $ 4,492 $ 5,231 $ 4,251
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Basic Net Income per Share (1)......... $ 1.40 $ 1.15 $ 0.77 $ 0.90 $ 0.73
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Diluted Net Income per Share (1)....... $ 1.37 $ 1.14 $ 0.77 $ 0.90 $ 0.73
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Cash Dividends per Share............... $ 0.00 $ 0.17 $ 0.00 $ 0.00 $ 0.00
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
Balance Sheet Data
(at end of period):
Total assets........................... $ 57,921 $ 48,006 $ 38,565 $ 35,716 $ 29,477
Net property and equipment............. 43,181 32,325 29,118 28,177 21,428
Long-term debt......................... 240 0 0 1,000 1,300
Stockholders' equity................... 43,214 35,273 29,916 25,353 20,270
Working capital........................ 7,531 7,863 4,292 848 2,003
</TABLE>
(1) Per share data has been restated to give effect to the adoption of
SFAS 128 in the fourth quarter of 1997. See "Earnings per Share"
subheading of Note 1 of the Notes to Consolidated Financial Statements
for discussion of SFAS 128.
19
<PAGE>
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 "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 15.
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, 1997. 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 $14,589,000 for the year ended
December 31, 1997, compared to $12,157,000 for the year ended December 31,
1996 and $8,906,000 for the year ended December 31, 1995. Net working
capital at December 31, 1997 was $7,531,000 as compared to $7,863,000 at
December 31, 1996. Current assets were $13,835,000 at December 31, 1997
compared to $15,011,000 at December 31, 1996. Current liabilities were
$6,304,000 at December 31, 1997 compared to $7,148,000 at December 31, 1996.
The Company had proceeds from the sales of oil and gas properties and other
equipment and sales of securities of $405,000 in 1997.
The Company has external borrowing capacity of $8,000,000 through an
unsecured line of credit with a commercial bank, all of which is available to
be drawn.
The Company invested $15,250,000 in additions to oil and gas properties
during the year ended December 31, 1997, compared to $7,942,000 during the
year ended December 31, 1996 and $5,182,000 during the year ended December
31, 1995. During 1997, $12,565,000 was paid for the Company's share of
development well costs and recompletions, $1,228,000 for exploratory costs,
$1,427,000 for acquisitions of unproved properties and $30,000 for purchases
of proved properties. Other uses of funds in 1997 included $1,291,000 for
purchases of oilfield service equipment and facilities and office equipment,
$358,000 for purchases of marketable securities and $404,000 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 $58,149,000 at
December 31, 1997 as compared to $68,965,000 at December 31, 1996 and
$39,180,000 at December 31, 1995. Estimated future net cash flows from
proved oil and natural gas reserves decreased to $136,391,000 at December 31,
1997 compared to $176,437,000 at December 31, 1996 and $85,028,000 at
December 31, 1995. Oil reserve volumes at December 31, 1997 increased 11%
and natural gas reserve volumes increased 22% compared to December 31, 1996.
The weighted average natural gas price received at December 31, 1997 on
Company production was $2.40 per Mcf, a decrease of $1.37 per Mcf compared to
December 31, 1996. The year end weighted average oil price was $17.08 per
barrel, a decrease of $7.63 per barrel compared to December 31, 1996.
20
<PAGE>
At December 31, 1997, the Company estimates that capital expenditures
of $22,095,000 will be required to develop the Company's proved undeveloped
and proved developed non-producing reserves over the next several years.
Approximately $13,166,000, net of future development costs, of the estimated
future net cash flows of the Company's proved oil and gas reserves at
December 31, 1997 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. 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 data-based information. The Company has identified all significant
programs 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 should be
completed by December 31, 1998. The cost of Year 2000 compliance has not
been and is not anticipated to be material to the Company's financial
position or results of operations in any given year. In addition, an
assessment of the readiness of external companies with whom the Company does
business, such as customers and vendors, is ongoing.
NEW ACCOUNTING PRONOUNCEMENTS
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income"
("SFAS 130"). SFAS 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and
losses) in a full set of general purpose financial statements. SFAS 130
requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. Reclassification is required for financial statements from
earlier periods provided for comparative purposes. Prima is required to adopt
SFAS 130 in January 1998. Prima has not completed the process of evaluating
the impact that will result from adopting SFAS 130 or the manner that will be
used to disclose the required information in its financial statements.
21
<PAGE>
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 supersedes FASB
Statement No. 14, "Financial Reporting for Segments of a Business
Enterprise." SFAS 131 establishes standards for the way that public business
enterprises report information about operating segments in annual financial
statements and requires that those enterprises report selected information
about operating segments in interim financial reports issued to shareholders.
It also establishes standards for 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 reportable operating segments. Operating segments are components of an
enterprise about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. Generally, financial
information is required to be reported on the basis that it is used
internally for evaluating segment performance and deciding how to allocate
resources to segments. The Company is required to adopt SFAS 131 in 1998 and
comparative information for earlier years is required to be restated. The
Company has not completed the process of evaluating the impact that will
result from adopting SFAS 131 or the manner that will be used to disclose the
required information in its financial statements.
RESULTS OF OPERATIONS
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 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.
22
<PAGE>
Depreciation, depletion and amortization ("DD&A") rates are affected by
production levels and changes in reserve estimates. Total 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 increased $163,000, or
49%, due primarily to acquisitions of oilfield service equipment in 1997.
Lease operating expenses ("LOE") were $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 ( LOE plus ad valorem and production
taxes) 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 and cost of trading represented the marketing of third
party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary.
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%. Trading
activities fluctuate with natural gas markets and the Company's ability to
develop markets that meet the Company's trading criteria. 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 of $3,214,000 and $2,269,000 for the years
ended December 31, 1997 and 1996, respectively, represent the revenues earned
by Action Oilfield Services, Inc., a wholly owned subsidiary. These revenues
include well servicing fees from seven completion rigs, a swab rig, trucking,
water hauling, dozer and roustabout work, rental equipment and other related
activities. 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. 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, 1997 and
1996 were $1,035,000 and $1,003,000, respectively, an increase of $32,000 or
3%. Management and operator fees are earned pursuant to the Company's roles
as operator for approximately 372 oil and gas wells located primarily in the
Wattenberg Area of Weld County, Colorado and as managing venturer of a joint
venture which owns 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.
23
<PAGE>
General and administrative expense ("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.
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.
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.
1996 VS 1995
For the year ended December 31, 1996, the Company earned net income of
$6,669,000, or $1.14 per diluted share, on revenues of $28,621,000, compared
to net income of $4,492,000, or $0.77 per diluted share, on revenues of
$19,048,000 for the year ended December 31, 1995. Operating expenses were
$19,667,000 for the 1996 year compared to $13,186,000 for 1995. Revenues
increased $9,573,000 or 50%, expenses increased $6,481,000 or 49% and net
income increased $2,177,000 or 49% in 1996.
Oil and gas sales for the year ended December 31, 1996 were $14,657,000
compared to $11,502,000 for the year ended December 31, 1995, an increase of
$3,155,000 or 27%. This increase was due primarily to increased product
prices for both oil and natural gas. The Company's net natural gas
production was 4.65 Bcf for 1996 compared to 4.30 Bcf in 1995, an increase of
.35 Bcf or 8%. Its net oil production was 233,000 barrels compared to
266,000 barrels for the same periods, a decrease of 33,000 barrels or 12%.
On a BOE basis, the Company's production for 1996 increased 24,000 BOE or 2%.
The average price received per Mcf of natural gas sold was $2.11 for the
year ended December 31, 1996 compared to $1.61 per Mcf for the year ended
December 31, 1995, an increase of $.50 per Mcf or 31%. Approximately 5.5%
and 4.3% of the natural gas production for the years ended December 31, 1996
and 1995, 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 $1.89
per Mcf for the year ended December 31, 1996 and $1.43 per Mcf for the year
ended December 31, 1995. The average price received per barrel of oil sold
was $20.84 for 1996 compared to $17.19 for 1995, an increase of $3.66 per
barrel or 21%. 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. During the year ended December 31, 1995, the Company hedged
approximately 11% of its oil production and 34% of its natural gas
production. Hedging gains of $80,000 are included in oil and gas revenues
for the year, which increased the average price received per barrel of oil by
$0.09 and the average price received per Mcf of natural gas by $0.01.
DD&A expense was $4,544,000 in 1996 compared to $4,372,000 for 1995, an
increase of $172,000 or 4%. The Company's depletion of oil and gas
properties was $4,210,000 or $4.18 per BOE on 1,007,000 equivalent barrels
produced in 1996, compared to $4,058,000 or $4.13 per BOE on 983,000
equivalent barrels produced in 1995. Included in DD&A expense for 1996 and
1995 is $334,000 and $314,000, respectively, attributable to depreciation of
service equipment, furniture and equipment and buildings.
LOE was $1,511,000 for the year ended December 31, 1996 compared to
$1,432,000 for the year ended December 31, 1995. Ad valorem and production
taxes were $981,000 and $736,000 for the same periods. Total lifting costs
were 17% of oil and gas revenues and $2.47 per equivalent barrel of
production for 1996 compared to 19% and $2.21 for 1995.
24
<PAGE>
Trading revenues were $10,001,000 for 1996 compared to $4,604,000 for
1995, an increase of $5,397,000 or 117%. The Company marketed 5,252,000
MMBtu's of third party gas in 1996 compared to 2,295,000 MMBtu's in 1995.
Costs of trading were $9,060,000 for 1996 compared to $3,613,000 for 1995, an
increase of $5,447,000 or 151%.
Oilfield service revenues were $2,269,000 for the year ended December
31, 1996 compared to $1,487,000 for the year ended December 31, 1995. Fees
increased by $782,000 or 53%. Cost of oilfield services were $1,759,000 for
the year ended December 31, 1996 compared to $1,170,000 for the year ended
December 31, 1995. Costs increased by $589,000 or 50%. Activity in the
Wattenberg Area where the service company is active had declined
significantly in 1995 due to low natural gas prices. In 1996, Wattenberg
Area activity improved due to higher oil and natural gas prices, application
of new drilling technologies, and an increased level of well reworks and
recompletions. For the years ended December 31, 1996 and 1995, 22% and 25%
of the gross fees billed by Action were for Company owned wells. The
services performed for the Company increased in 1996 because the Company
drilled more Wattenberg wells than in 1995, but the percentage is lower due
to increased business with third party operators.
Management and operator fees for the years ended December 31, 1996 and
1995 were $1,003,000 and $1,084,000, respectively, a decrease of $81,000 or
8%. Fees decreased in 1996 due to reduced third party ownership in operated
wells.
G&A totaled $1,812,000 for the year ended December 31, 1996 compared to
$1,863,000 for the year ended December 31, 1995, a decrease of $51,000 or 3%.
The Company's G&A expense was relatively consistent from 1995 to 1996 because
personnel levels and facility costs had not materially changed.
The provision for income taxes was $2,285,000 for the year ended
December 31, 1996 compared to $1,370,000 for the year ended December 31,
1995. The effective tax rate was 25.5% in 1996 compared to 23.4% in 1995.
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.
25
<PAGE>
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 13, 1998 and is hereby
incorporated by reference.
26
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
PAGE
<S> <C>
Independent Auditors' Report.................................. 28
Consolidated Balance Sheets at December 31, 1997 and 1996..... 29
Consolidated Statements of Income for the years ended
December 31, 1997, 1996 and 1995......................... 31
Consolidated Statements of Stockholders' Equity for the years
ended December 31, 1997, 1996 and 1995................... 32
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1996 and 1995......................... 33
Notes to Consolidated Financial Statements for the years
ended December 31, 1997, 1996 and 1995................... 34
</TABLE>
(a) (2) FINANCIAL STATEMENT SCHEDULES
Financial statement schedules have been omitted because they are not
applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.
(a) (3) EXHIBITS
The following Exhibits are filed herewith pursuant to Rule 601 of the
Regulation S-K or are incorporated by reference to previous filings.
EXHIBIT NO. DOCUMENT
3.1 Certificate of Amendment of the Certificate of
Incorporation - Prima Energy Corporation
(Incorporated by reference as Exhibit 3.1 to
Form 10-Q filed November 14, 1997)
10.1 Extension of Line of Credit Letter Agreement
(Incorporated by reference as Exhibit 10-97.1
to Form 10-Q filed May 13, 1997)
10.2 Agreement to Terminate CPP Natural Gas Supply Contract
21 Subsidiaries of the Registrant
27 Financial Data Schedules
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Registrant's fiscal quarter
ended December 31, 1997. A Form 8-K was filed January 8, 1998, announcing
the agreement to terminate the long term natural gas supply contract with
Colorado Power Partners for $3,850,000. See Note 9 of the Notes to
Consolidated Financial Statements for additional discussion of this agreement.
27
<PAGE>
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, 1997 and
1996, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended
December 31, 1997. 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
subsidiaries at December 31, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1997 in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
March 13, 1998
Denver, Colorado
28
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
ASSETS
<TABLE>
1997 1996
----------- -----------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents......................... $ 5,223,000 $ 6,704,000
Available for sale securities, at market.......... 1,866,000 1,503,000
Receivables (net of allowance for doubtful
accounts: 1997, $49,000; 1996, $45,000)......... 5,681,000 5,921,000
Tubular goods inventory........................... 882,000 311,000
Other current assets.............................. 183,000 572,000
----------- -----------
Total current assets........................ 13,835,000 15,011,000
----------- -----------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method.................. 67,945,000 52,885,000
Less accumulated depreciation,
depletion and amortization...................... (26,875,000) (21,940,000)
----------- -----------
Oil and gas properties - net................ 41,070,000 30,945,000
----------- -----------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment........................ 3,504,000 2,387,000
Furniture and equipment........................... 711,000 652,000
Field office, shop and land....................... 356,000 341,000
----------- -----------
4,571,000 3,380,000
Less accumulated depreciation..................... (2,460,000) (2,000,000)
----------- -----------
Property and equipment - net................ 2,111,000 1,380,000
----------- -----------
OTHER ASSETS
Cash, designated................................... 421,000 325,000
Other.............................................. 484,000 345,000
----------- -----------
Total other assets.......................... 905,000 670,000
----------- -----------
$57,921,000 $48,006,000
----------- -----------
----------- -----------
</TABLE>
See accompanying notes to consolidated financial statements.
29
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 1997 AND 1996
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
1997 1996
----------- -----------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable.................................. $ 3,250,000 $ 2,526,000
Amounts payable to oil and gas property owners..... 1,220,000 2,831,000
Ad valorem and production taxes payable............ 1,279,000 1,094,000
Accrued and other liabilities...................... 421,000 476,000
Current portion of notes payable................... 120,000 0
Deferred income taxes.............................. 14,000 221,000
----------- -----------
Total current liabilities................... 6,304,000 7,148,000
NOTES PAYABLE...................................... 240,000 0
AD VALOREM TAXES, non-current...................... 1,280,000 984,000
DEFERRED INCOME TAXES.............................. 6,883,000 4,601,000
----------- -----------
Total liabilities........................... 14,707,000 12,733,000
----------- -----------
COMMITMENTS AND CONTINGENCIES (Note 9)
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued or outstanding.... 0 0
Common stock, $0.015 par value, 12,000,000
shares authorized; 5,833,056 and
5,820,556 shares issued........................ 87,000 87,000
Additional paid-in capital........................ 4,385,000 4,222,000
Retained earnings................................. 39,485,000 31,383,000
Unrealized gain (loss) on available for sale
securities..................................... 44,000 (36,000)
Treasury stock, 63,000 and 30,000 shares at cost.. (787,000) (383,000)
----------- -----------
Stockholders' equity - net.................. 43,214,000 35,273,000
----------- -----------
$57,921,000 $48,006,000
----------- -----------
----------- -----------
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
REVENUES
Oil and gas sales.......................... $17,840,000 $14,657,000 $11,502,000
Trading revenues........................... 15,999,000 10,001,000 4,604,000
Oilfield services.......................... 3,214,000 2,269,000 1,487,000
Management and operator fees............... 1,035,000 1,003,000 1,084,000
Interest and dividend income............... 546,000 411,000 154,000
Other...................................... 216,000 280,000 217,000
----------- ----------- -----------
38,850,000 28,621,000 19,048,000
----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization... 5,432,000 4,544,000 4,372,000
Lease operating expense.................... 1,720,000 1,511,000 1,432,000
Ad valorem and production taxes............ 1,355,000 981,000 736,000
Cost of trading............................ 15,323,000 9,060,000 3,613,000
Cost of oilfield services.................. 2,368,000 1,759,000 1,170,000
General and administrative................. 1,915,000 1,812,000 1,863,000
----------- ----------- -----------
28,113,000 19,667,000 13,186,000
----------- ----------- -----------
INCOME BEFORE INCOME TAXES................. 10,737,000 8,954,000 5,862,000
PROVISION FOR INCOME TAXES................. 2,635,000 2,285,000 1,370,000
----------- ----------- -----------
NET INCOME................................. $ 8,102,000 $ 6,669,000 $ 4,492,000
----------- ----------- -----------
----------- ----------- -----------
BASIC NET INCOME PER SHARE................. $ 1.40 $ 1.15 $ 0.77
----------- ----------- -----------
----------- ----------- -----------
DILUTED NET INCOME PER SHARE .............. $ 1.37 $ 1.14 $ 0.77
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
ADDITIONAL UNREALIZED
COMMON PAID-IN RETAINED GAIN (LOSS) ON TREASURY
STOCK CAPITAL EARNINGS SECURITIES STOCK TOTAL
------ ------- -------- ------------ ------- -----
<S> <C> <C> <C> <C> <C> <C>
BALANCES, January 1, 1995............ $87,000 $4,222,000 $21,192,000 $(148,000) $ 0 $25,353,000
Net income........................... 4,492,000 4,492,000
Change in unrealized gain (loss)
on available for sale securities... 71,000 71,000
------- ---------- ----------- --------- --------- -----------
BALANCES, December 31, 1995.. 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)
Change in unrealized gain (loss)
on available for sale securities... 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
Change in unrealized gain (loss)
on available for sale securities... 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
------- ---------- ----------- --------- --------- -----------
------- ---------- ----------- --------- --------- -----------
</TABLE>
See accompanying notes to consolidated financial statements.
32
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 and 1995
<TABLE>
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income ............................................... $ 8,102,000 $ 6,669,000 $ 4,492,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization.............. 5,432,000 4,544,000 4,372,000
Deferred income taxes................................. 2,028,000 1,761,000 889,000
Other................................................. 83,000 26,000 (34,000)
Changes in operating assets and liabilities:
Receivables......................................... 240,000 (2,834,000) 338,000
Inventory........................................... (571,000) (94,000) 261,000
Other assets........................................ 32,000 (342,000) 24,000
Payables............................................ (702,000) 2,380,000 (1,512,000)
Accrued and other liabilities....................... (55,000) 47,000 76,000
------------ ------------ ------------
Net cash provided by operating activities......... 14,589,000 12,157,000 8,906,000
------------ ------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties....................... (14,893,000) (7,942,000) (5,182,000)
Purchases of other property............................... (931,000) (640,000) (249,000)
Purchases of securities................................... (358,000) (744,000) (181,000)
Proceeds from sales of property........................... 292,000 831,000 125,000
Proceeds from sales of securities......................... 113,000 418,000 0
------------ ------------ ------------
Net cash used by investing activities............. (15,777,000) (8,077,000) (5,487,000)
------------ ------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased.................................. (404,000) (383,000) 0
Proceeds from issuance of common stock.................... 111,000 0 0
Dividends paid............................................ 0 (970,000) 0
Payments on line of credit................................ 0 0 (1,000,000)
------------ ------------ ------------
Net cash used by financing activities............. (293,000) (1,353,000) (1,000,000)
------------ ------------ ------------
Increase (Decrease) in Cash and Cash Equivalents.......... (1,481,000) 2,727,000 2,419,000
Cash and Cash Equivalents, beginning of year.............. 6,704,000 3,977,000 1,558,000
------------ ------------ ------------
Cash and Cash Equivalents, end of year.................... $ 5,223,000 $ 6,704,000 $ 3,977,000
------------ ------------ ------------
------------ ------------ ------------
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
------------
------------
</TABLE>
See accompanying notes to consolidated financial statements.
33
<PAGE>
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
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.
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, 1997.
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 during the period for:
<TABLE>
YEARS ENDED DECEMBER 31,
-----------------------------
1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
Income taxes......... $787,000 $693,000 $ 0
Interest............. 0 0 29,000
</TABLE>
34
<PAGE>
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.
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.
35
<PAGE>
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.
At December 31, 1996, the Company had delivered 13,000 MMBtu's to the
purchaser which had not been delivered into the pipeline. This gas is also
valued at the lower of cost or market value. Included in amounts payable to
oil and gas property owners at December 31, 1996 is $48,000 representing the
cost of gas which had been delivered to the purchaser but not delivered into
the pipeline.
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, 1997, the Company had no transactions that did not correspond
to anticipated physical transactions. For the years ended December 31, 1997,
1996 and 1995, 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, 1997,
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.
36
<PAGE>
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.
COMPREHENSIVE INCOME
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income"
(SFAS 130). SFAS 130 establishes standards for reporting and display of
comprehensive income and its components (revenues, expenses, gains and
losses) in a full set of general purpose financial statements. SFAS 130
requires that all items that are required to be recognized under accounting
standards as components of comprehensive income be reported in a financial
statement that is displayed with the same prominence as other financial
statements. Reclassification is required for financial statements from
earlier periods provided for comparative purposes. Prima is required to
adopt SFAS 130 in January 1998. Prima has not completed the process of
evaluating the impact that will result from adopting SFAS 130 or the manner
that will be used to disclose the required information in its financial
statements.
SEGMENT REPORTING
In June 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 131, "Disclosures about Segments of an
Enterprise and Related Information" ("SFAS 131"). SFAS 131 supersedes FASB
Statement No. 14, "Financial Reporting for Segments of a Business
Enterprise." SFAS 131 establishes standards for the way that public business
enterprises report information about operating segments in annual financial
statements and requires that those enterprises report selected information
about operating segments in interim financial reports issued to shareholders.
It also establishes standards for 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 reportable operating segments. Operating segments are components of an
enterprise about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance. Generally, financial
information is required to be reported on the basis that it is used
internally for evaluating segment performance and deciding how to allocate
resources to segments. The Company is required to adopt SFAS 131 in 1998 and
comparative information for earlier years is required to be restated. The
Company has not completed the process of evaluating the impact that will
result from adopting SFAS 131 or the manner that will be used to disclose the
required information in its financial statements.
37
<PAGE>
EARNINGS PER SHARE
During February 1997, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 128, "Earnings per Share"
("SFAS 128"). SFAS 128 establishes standards for computing and presenting
earnings per share ("EPS"), and supersedes APB Opinion No. 15 and its related
interpretations. It replaces the presentation of primary EPS with a
presentation of basic EPS, which excludes dilution, and requires dual
presentation of basic and diluted EPS for all entities with complex capital
structures. Diluted EPS is computed similarly to fully diluted EPS pursuant
to Opinion No. 15. SFAS 128 is effective for periods ending after December
15, 1997, including interim periods, and requires restatement of all prior
period EPS data presented. The Company adopted SFAS 128 effective December
31, 1997, and has restated all prior period EPS data presented to give
retroactive effect to the new accounting standard.
Basic net income per share is computed by dividing net income by the
weighted average common shares outstanding during the period. Diluted net
income per share includes the potential dilution that could occur upon
exercise of the options to acquire common stock described in Note 10,
computed using the treasury stock method. The treasury stock method assumes
that the increase in the number of shares issued is reduced by the number of
shares which could have been repurchased by the Company with the proceeds
from the exercise of the options (which were assumed to have been at the
average market price of the common shares during the reporting period).
The following table reconciles the numerator and denominator used in the
calculation of basic and diluted net income per share.
<TABLE>
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ---------
<S> <C> <C> <C>
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
---------- --------- ------
---------- --------- ------
Year Ended December 31, 1995:
Basic Net Income per Share............ $4,492,000 5,820,594 $ 0.77
Effect of Stock Options............... 0 ------
---------- --------- ------
Diluted Net Income per Share.......... $4,492,000 5,820,594 $ 0.77
---------- --------- ------
---------- --------- ------
</TABLE>
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.
38
<PAGE>
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, 1997 and 1996. The fair value of the Company's liability under
these contracts is estimated to be $155,000 and $23,000, 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, 1997 is
approximately equal to its carrying value since the Company could have
obtained the debt for the same terms at December 31, 1997.
3. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity securities.
For the years ended December 31, 1997 and 1996, the Company sold securities
with a market value of $113,000 and $418,000 which resulted in realized
losses of $10,000 and $70,000, respectively. The net unrealized gain or loss
on securities at December 31, 1997 and 1996 is included as a separate
component of stockholders' equity, net of deferred income taxes of $27,000
and ($20,000), respectively. The change in net unrealized gain or loss on
securities for the years ended December 31, 1997 and 1996 was determined as
follows:
<TABLE>
1997 1996
---------- ----------
<S> <C> <C>
Net unrealized loss, beginning of year....... $ 56,000 $ 122,000
Net unrealized loss, end of year............. 0 (56,000)
Net unrealized gain, end of year............. 71,000 0
---------- ----------
Net change in unrealized gain or loss........ $ 127,000 $ 66,000
---------- ----------
---------- ----------
</TABLE>
The components of fair value as of December 31, 1997 and 1996 are as follows:
<TABLE>
1997 1996
---------- ----------
<S> <C> <C>
Cost (including reinvested distributions).... $1,795,000 $1,559,000
Gross unrealized gains....................... 111,000 5,000
Gross unrealized losses...................... (40,000) (61,000)
---------- ----------
Fair value................................... $1,866,000 $1,503,000
---------- ----------
---------- ----------
</TABLE>
4. NOTE PAYABLE AND LINE OF CREDIT
The note payable as of December 31, 1997, bears interest at an annual
rate of 8% and is due on June 10, 2000. 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 $558,000 at December 31, 1997.
39
<PAGE>
Prima has 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 (8.50% at December 31, 1997), with interest payable
monthly. At December 31, 1997 and 1996, 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 29%, 25% and 11% of its oil production in 1997,
1996 and 1995, respectively, and hedged approximately 37%, 0% and 34% of its
natural gas production in these same years.
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 third
party contract discussed in Note 9, the Company had no open trading positions
to purchase or deliver natural gas at December 31, 1997. During 1997, 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 150,000 MMBtu per month beginning
April 1, at a fixed price of $1.575 per MMBtu. At December 31, 1997, the
Company had an unrealized loss of $155,000 on the remaining open months of
January, February and March 1998.
6. INCOME TAXES
The provision for income taxes consists of the following components:
<TABLE>
Year Ended December 31,
--------------------------------------
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Current:
Federal.......................... $ 524,000 $ 400,000 $ 354,000
State............................ 83,000 124,000 127,000
---------- ---------- ----------
607,000 524,000 481,000
---------- ---------- ----------
Deferred:
Federal.......................... 2,277,000 1,741,000 1,116,000
State............................ 166,000 277,000 127,000
---------- ---------- ----------
2,443,000 2,018,000 1,243,000
---------- ---------- ----------
Tax credits........................ (415,000) (257,000) (354,000)
---------- ---------- ----------
Provision for income taxes......... $2,635,000 $2,285,000 $1,370,000
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
40
<PAGE>
During 1997, the Company recognized income tax deductions of $143,000
from the exercise of nonqualified stock options. Stockholders' equity has
been credited in the amount of $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:
<TABLE>
1997 1996
----------- ----------
<S> <C> <C>
Deferred Tax Assets:
Minimum tax credit carryforwards..... $ 3,151,000 $2,736,000
State income taxes................... 380,000 322,000
Accrued bonuses...................... 86,000 0
Other................................ 32,000 94,000
----------- ----------
Total Deferred Tax Assets............ 3,649,000 3,152,000
----------- ----------
Deferred Tax Liabilities:
Intangible drilling costs............ 9,963,000 7,351,000
Deferred revenues.................... 92,000 82,000
Depreciation......................... 92,000 61,000
Other................................ 399,000 480,000
----------- ----------
Total Deferred Tax Liabilities....... 10,546,000 7,974,000
----------- ----------
$ 6,897,000 $4,822,000
----------- ----------
----------- ----------
</TABLE>
The reconciliation of income tax computed at the federal statutory tax
rate to the Company's effective tax rate is as follows:
<TABLE>
YEAR ENDED DECEMBER 31,
-----------------------
1997 1996 1995
---- ---- -----
<S> <C> <C> <C>
Federal statutory income tax rate....... 34.0% 34.0% 34.0%
Percentage depletion.................... (2.6) (2.7) (3.4)
Section 29 credits...................... (7.2) (8.3) (13.7)
State taxes, net of federal benefit..... 1.6 3.0 2.9
Other................................... (1.3) (0.5) 3.6
---- ---- -----
Effective tax rate................. 24.5% 25.5% 23.4%
---- ---- -----
---- ---- -----
</TABLE>
At December 31, 1997, the Company had minimum tax credit carryforwards
of approximately $3,151,000, which may be carried forward indefinitely.
41
<PAGE>
7. MAJOR CUSTOMERS
The following customers have each accounted for over 10% of the
Company's consolidated revenues and are from the identified industry 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 would be able
to secure additional marketing opportunities.
<TABLE>
1997 1996 1995
---- ---- ----
<S> <C> <C> <C>
Oil and Gas Operations:
Duke Energy Field Services, Inc....... 20% 19% 21%
Total Petroleum....................... 11 15 20
Natural Gas Marketing and Trading:
Colorado Power Partnership............ 10 11 13
KN Gas Marketing, Inc................. 21 21
</TABLE>
8. INDUSTRY SEGMENT INFORMATION
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, 1997, 1996
and 1995 for the Company's two identifiable industry segments.
<TABLE>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas............... $35,100,000 $26,011,000 $17,399,000
Oilfield services......... 4,135,000 2,894,000 1,968,000
Other..................... 536,000 340,000 162,000
----------- ----------- -----------
Total................... $39,771,000 $29,245,000 $19,529,000
----------- ----------- -----------
----------- ----------- -----------
Operating Earnings
Oil and gas............... $ 9,650,000 $ 8,315,000 $ 5,617,000
Oilfield services......... 551,000 299,000 104,000
Other..................... 536,000 340,000 141,000
----------- ----------- -----------
Total................... $10,737,000 $ 8,954,000 $ 5,862,000
----------- ----------- -----------
----------- ----------- -----------
Identifiable Assets
Oil and gas............... $48,080,000 $37,872,000 $31,803,000
Oilfield services......... 2,466,000 1,666,000 1,237,000
Other..................... 7,375,000 8,468,000 5,525,000
----------- ----------- -----------
Total................... $57,921,000 $48,006,000 $38,565,000
----------- ----------- -----------
----------- ----------- -----------
Depreciation, Depletion and
Amortization Expense
Oil and gas............... $ 5,088,000 $ 4,321,000 $ 4,138,000
Oilfield services......... 344,000 223,000 234,000
----------- ----------- -----------
Total................... $ 5,432,000 $ 4,544,000 $ 4,372,000
----------- ----------- -----------
----------- ----------- -----------
Capital Expenditures
Oil and gas............... $15,556,000 $ 8,251,000 $ 5,299,000
Oilfield services......... 986,000 331,000 132,000
----------- ----------- -----------
Total................... $16,542,000 $ 8,582,000 $ 5,431,000
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
42
<PAGE>
The Company operates principally in two industries, oil and gas
operations and oilfield services. Total revenue by industry 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 $921,000, $624,000 and
$481,000 for the years ended December 31, 1997, 1996 and 1995, respectively,
for intersegment sales. Oilfield services revenue is priced and accounted for
consistently for both unaffiliated and intersegment sales.
Identifiable assets by industry 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.
9. COMMITMENTS AND CONTINGENCIES
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 $112,000, $109,000 and $127,000 for the years ended December 31,
1997, 1996 and 1995, respectively. Future minimum annual rentals under
non-cancelable operating leases with remaining terms in excess of one year
are as follows:
<TABLE>
<S> <C>
Year ending December 31, 1998........... 129,000
Year ending December 31, 1999........... 132,000
Year ending December 31, 2000........... 124,000
--------
$385,000
--------
--------
</TABLE>
DELIVERY COMMITMENT
A participation agreement was executed May 24, 1989 between the Company
and an unrelated third party to supply the natural gas required for a 50
megawatt cogeneration facility in Brush, Colorado. The Company contracted to
supply 70% of the committed quantities. Also on May 24, 1989, the Company
and the third party signed a Gas Sales Agreement with the owner/operator of
the cogeneration facility. The Gas Sales Agreement required that
approximately 1,750,000 MMBtu's per year of natural gas for 15 years be
supplied to the cogeneration facility. Under the agreement, the
owner/operator was required to take or pay for 80% of the annual contract
quantity. The Company dedicated a substantial portion of its proved reserves
in Weld County, Colorado to cover its share of the commitment. The contract
price for the gas ($2.72 per MMBtu for 1998) escalated annually at the higher
of 3% or a sharing of the indexed energy payment rate received by the
owner/operator.
In January 1998, Prima terminated the contract, effective October 31,
1998, for $3,850,000, and other consideration. From January 1, 1998, through
October 31, 1998, Prima has agreed to supply 100% of the third party's
natural gas requirements. Under the termination agreement, Prima will
receive $2.72 per MMBtu from January 1, 1998 through March 31, 1998, and a
spot related index price from April 1, 1998 through October 31, 1998. At
that time, the parties have agreed to negotiate in good faith a new supply
contract through the year 2005, but neither party has an obligation to supply
or purchase from the other. As a result of the contract termination, Prima's
substantial dedication of gas reserves in the Wattenberg Area in northeast
Colorado for the long term contract will be released effective October 31,
1998.
43
<PAGE>
NOTE GUARANTEE
Bonny Gathering Company ("Bonny"), an unincorporated joint venture of
which Prima is 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 bears interest at the bank's prime interest rate less
1/2%, payable monthly on the last day of each calendar month. Funds may be
advanced on the line of credit through November 30, 1998 and the note is due
November 30, 2001. The note is collateralized by a first priority mortgage
and deed of trust on the assets of Bonny. Prima has guaranteed its 15.5%
proportionate share of the note. At December 31, 1997, Bonny had drawn
$915,000 on the note.
10. EMPLOYEE BENEFIT PLANS
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, 1997, options to acquire 367,500 shares
of the Company's common stock had been granted under the Plan. The exercise
prices, which equaled the market price of the stock on the date of grant,
ranged from $8.83 to $9.92 per share, with a weighted average price of $9.20
per share. As of December 31, 1997, the weighted average remaining
contractual life of the options outstanding is 6 years, 4 months.
A summary of options granted, exercised and outstanding during 1995,
1996 and 1997 is as follows:
<TABLE>
Number Weighted Average
of Shares Exercise Prices
--------- ----------------
<S> <C> <C>
Balance, December 31, 1994............. 255,000 8.88
Granted during 1995.................... 112,500 9.92
Exercised or canceled.................. 0 n/a
-------
Outstanding at December 31, 1995....... 367,500 9.20
Granted during 1996.................... 0 n/a
Exercised or canceled.................. 0 n/a
-------
Outstanding at December 31, 1996....... 367,500 9.20
Granted during 1997.................... 0 n/a
Exercised or canceled.................. (12,500) 8.93
-------
Outstanding at December 31, 1997....... 355,000 9.20
-------
-------
Exercisable at December 31, 1995....... 97,500 8.86
Exercisable at December 31, 1996....... 171,000 9.00
Exercisable at December 31, 1997....... 235,000 9.06
</TABLE>
The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"). Accordingly, no 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
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:
44
<PAGE>
<TABLE>
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Net income
As reported..................... $8,102,000 $6,669,000 $4,492,000
Pro forma....................... 8,018,000 6,509,000 4,492,000
Basic net income per share
As reported..................... $1.40 $1.15 $0.77
Pro forma....................... 1.39 1.12 0.77
Diluted net income per share
As reported..................... $1.37 $1.14 $0.77
Pro forma....................... 1.36 1.11 0.77
</TABLE>
The fair value of the options for disclosure purposes was estimated on
the date of the grant using the Black-Scholes Model with the following
assumptions:
<TABLE>
<S> <C>
Expected dividend yield.................. 0%
Expected price volatility................ 31%
Risk free interest rate.................. 6.6%
Expected life of options (in years)...... 9
</TABLE>
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, 1997,
1996 and 1995, the Company expensed $169,000, $125,000 and $93,000,
respectively, of contributions payable to the Plan.
11. DESIGNATED CASH AND RELATED AD VALOREM TAXES PAYABLE
The Company has designated a portion of its cash balance for payment of
ad valorem taxes withheld from third party revenue interest owners. The
non-current portion of ad valorem taxes payable relates to those taxes
collected and accrued for production through December 1997 which is not
payable until fiscal 1999 or later. The related cash collected from third
party revenue interest owners designated for payment of non-current ad
valorem taxes is reflected as a non-current asset.
45
<PAGE>
12. 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 the 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.
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. Prima, as
operator, commenced drilling a well in December 1997 in which Mr. Lockridge,
a director of Prima, is a 61% working interest owner. The estimated costs to
drill and complete the well are $1,686,800, or $1,026,000 net to Mr.
Lockridge. As of the end of February 1998, the most recent billing period,
Mr. Lockridge owed Prima $299,433 for his proportionate share of costs billed
through that date, net of prepayments made of $389,311. There were no
significant amounts due to or from any other officers or directors in 1997.
13. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
<TABLE>
Year Ended December 31,
----------------------------------------
1997 1996 1995
----------- ---------- ----------
<S> <C> <C> <C>
Acquisition costs:
Unproved properties.............. $ 1,427,000 $ 873,000 $1,319,000
Proved properties................ 30,000 63,000 27,000
Exploration costs.................. 1,228,000 401,000 202,000
Development costs.................. 12,565,000 6,605,000 3,634,000
----------- ---------- ----------
Total........................... $15,250,000 $7,942,000 $5,182,000
----------- ---------- ----------
----------- ---------- ----------
Amortization per equivalent
barrel of production............. $ 4.31 $ 4.18 $ 4.13
----------- ---------- ----------
----------- ---------- ----------
</TABLE>
46
<PAGE>
Results of operations for oil and gas producing activities are as follows:
<TABLE>
Year Ended December 31,
-----------------------------------------
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas sales............................ $17,840,000 $14,657,000 $11,502,000
----------- ----------- -----------
Expenses
Lease operating expense...................... 1,720,000 1,511,000 1,432,000
Ad valorem and production taxes.............. 1,355,000 981,000 736,000
Depreciation, depletion and amortization..... 4,935,000 4,210,000 4,058,000
----------- ----------- -----------
8,010,000 6,702,000 6,226,000
----------- ----------- -----------
Income before income taxes..................... 9,830,000 7,955,000 5,276,000
Income tax expense............................. 2,408,000 2,029,000 1,233,000
----------- ----------- -----------
Income from oil and gas producing properties... $ 7,422,000 $ 5,926,000 $ 4,043,000
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
The reserve information presented below was prepared by independent
engineers for the year ended December 31, 1997 and by Company personnel for
the years ended December 31, 1996 and 1995. 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 justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and natural gas that are
ultimately produced.
Proved oil and gas reserves are the estimated quantities of crude oil,
natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed oil and gas reserves are those proved reserves expected to be
recovered through existing wells with existing equipment and operating
methods.
47
<PAGE>
Proved oil and gas reserves of the Company, all of which are located in
the United States, are as follows:
<TABLE>
Year Ended December 31,
--------------------------------------------------------
1997 1996 1995
---------------- ---------------- -----------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
---------------- ---------------- -----------------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Beginning of year..................... 3,037 52,112 2,734 47,711 3,009 46,202
Purchases of oil and
gas reserves in place............... 27 251 14 231 14 123
Revisions of previous
estimates........................... (94) (1,843) 130 2,444 (39) (218)
Extensions, discoveries and
other additions..................... 643 18,314 392 6,372 17 5,924
Production............................ (255) (5,344) (233) (4,646) (266) (4,298)
Sales of oil and gas reserves
in place............................ 0 0 0 0 (1) (22)
----- ------ ----- ------ ----- ------
End of Year........................... 3,358 63,490 3,037 52,112 2,734 47,711
----- ------ ----- ------ ----- ------
----- ------ ----- ------ ----- ------
Proved developed reserves:
Beginning of year..................... 2,087 41,107 1,853 38,076 2,080 35,664
End of year........................... 2,286 48,139 2,087 41,107 1,853 38,076
</TABLE>
Standardized measures of discounted future net cash flows relating
to proved oil and gas reserves are as follows:
<TABLE>
Year Ended December 31,
--------------------------------------------
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C>
Future cash inflows..................... $209,689,000 $271,196,000 $148,101,000
Future production costs................. (51,203,000) (77,211,000) (47,648,000)
Future development costs................ (22,095,000) (17,548,000) (15,425,000)
------------ ------------ ------------
Future net cash flows................... 136,391,000 176,437,000 85,028,000
10% discount factor..................... (60,851,000) (84,991,000) (37,243,000)
Discounted future income taxes.......... (17,391,000) (22,481,000) (8,605,000)
------------ ------------ ------------
Standardized measure of discounted
future net cash flows................. $ 58,149,000 $ 68,965,000 $ 39,180,000
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
48
<PAGE>
The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:
<TABLE>
Year Ended December 31,
-------------------------------------------
1997 1996 1995
------------ ------------ -----------
<S> <C> <C> <C>
Beginning standardized measure.................... $ 68,965,000 $ 39,180,000 $38,095,000
Sales of oil and gas produced,
net of production costs......................... (14,765,000) (12,165,000) (9,334,000)
Net changes in prices and production costs....... (29,995,000) 37,015,000 (1,763,000)
Extensions, discoveries, and improved
recovery, less related costs.................... 20,922,000 11,187,000 8,505,000
Development costs incurred during the year........ 5,713,000 3,077,000 2,729,000
Changes in estimated future development costs..... (1,402,000) (558,000) (2,629,000)
Revisions of previous quantity
estimates and other............................. (3,658,000) 806,000 (1,291,000)
Purchases of reserves in place.................... 382,000 381,000 101,000
Sales of reserves in place........................ 0 0 (13,000)
Accretion of discount............................. 6,896,000 3,918,000 3,809,000
Net change in income taxes........................ 5,091,000 (13,876,000) 971,000
------------ ------------ -----------
Ending standardized measure....................... $ 58,149,000 $ 68,965,000 $39,180,000
------------ ------------ -----------
------------ ------------ -----------
</TABLE>
14. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each quarter
for the years ended December 31, 1997 and 1996.
<TABLE>
Three Months Ended
---------------------------------------------------
3/31/97 6/30/97 9/30/97 12/31/97
----------- ---------- ---------- -----------
<S> <C> <C> <C> <C>
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
Three Months Ended
---------------------------------------------------
3/31/96 6/30/96 9/30/96 12/31/96
----------- ---------- ---------- -----------
Year Ended December 31, 1996
Revenues......................... $ 6,385,000 $5,875,000 $6,098,000 $10,263,000
Gross profit..................... 1,909,000 1,744,000 1,867,000 2,993,000
Net income....................... 1,529,000 1,401,000 1,538,000 2,201,000
Basic net income per share....... 0.26 0.24 0.26 0.38
Diluted net income per share..... 0.26 0.24 0.26 0.37
</TABLE>
49
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual
Report on Form 10-K to be signed on its behalf by the undersigned, thereunto
duly authorized, in Denver, Colorado on the 13th day of March, 1998.
PRIMA ENERGY CORPORATION
By: /s/ Richard H. Lewis
---------------------------
Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed below by the following persons in the
capacities indicated and on the dates indicated.
<TABLE>
SIGNATURE TITLE DATE
<S> <C> <C>
/s/ Richard H. Lewis Chairman, President, Treasurer, March 13, 1998
- ------------------------ (Principal Executive and
Richard H. Lewis Financial Officer)
/s/ Robert E. Childress March 13, 1998
- ------------------------ Director
Robert E. Childress
/s/ Douglas J. Guion March 13, 1998
- ------------------------ Director
Douglas J. Guion
/s/ John P. Lockridge March 13, 1998
- ------------------------ Director
John P. Lockridge
/s/ George L. Seward March 13, 1998
- ------------------------ Director
George L. Seward
/s/ Sandra J. Irlando March 13, 1998
- ------------------------ Vice President of Accounting
Sandra J. Irlando and Controller
</TABLE>
50
<PAGE>
EXHIBIT 10.2
AMENDMENT TO GAS SALES AGREEMENT
This Amendment made and entered into this 30th day of January, 1998,
between Colorado Power Partners (a/k/a Colorado Power Partnership), a
Colorado general partnership, with its principal place of business located at
4845 Pearl East Circle, Suite 300, Boulder, Colorado 80301 ("Buyer") and
Prima Oil & Gas Company ("Prima"), a Colorado corporation, with its principal
place of business at 1801 Broadway, Suite 500, Denver, Colorado 80202.
Recitals:
A. Buyer, Prima, and KN Marketing, Inc., a Colorado corporation, successor
in interest to KN Production Company, a Delaware corporation which was in
turn successor in interest to Fuel Resources Development Co., a Colorado
corporation, entered into that certain Gas Sales Agreement dated May 24,
1989, as amended October 12, 1990, December 17, 1992, February 1, 1994 and
December 31, 1997, providing for the sale of gas from Prima and KN Marketing,
Inc. to Buyer for consumption in Phase I at Buyer's co-generation facility
located near Brush, Colorado (the "Agreement").
B. KN Marketing, Inc., by amendment to the Agreement dated December 31,
1997, terminated its obligations under the Agreement as mutually agreed by
Prima and Buyer.
C. Buyer and Prima desire to enter into this Amendment to provide for an
early termination of Buyer's and Prima's rights, responsibilities and
obligations under the Agreement and to modify certain terms and provisions
relating to purposes and pricing as well as other matters related to the
Agreement.
Now therefore, in consideration of the mutual covenants and agreements
contained herein, the parties agree as follows:
1. Article I, PURPOSE AND COMMITMENTS, shall be modified by deleting
paragraph (d) and replacing it with the following new paragraph (d):
"(d) The parties agree that the sale of natural gas by Prima to Buyer shall
primarily be for consumption in Phase I at Buyer's co-generation
facility located near Brush, Colorado. Nothing however, shall be
construed to limit Buyer's ability to resell or otherwise dispose of
gas purchased hereunder at its sole option for those purchases on and
after March 31, 1998.
<PAGE>
2. Article III, QUANTITY, shall be modified by adding a new
subparagraph (e), the intent of the parties to establish the quantities to be
delivered by Seller from January 1, 1998 through October 31, 1998 as follows:
"(e) Notwithstanding the preceding subparagraphs, the quantities of gas to
be delivered shall be all of the requirements of Buyer from January 1,
1998 through October 31, 1998".
3. Article VI, TERM, shall be modified by deleting paragraph (a) and
replacing it with the following new paragraph (a):
"(a) The parties agree that this Agreement, and the obligations to sell and
purchase gas, shall terminate as of October 31, 1998. This
termination date my be extended upon mutual consent of the parties.
4. Article XI, PRICE AND BILLING, shall be amended by deleting the
first sentence of paragraph (a) in its entirety and replacing it with the
following:
"(a) The price of gas sold hereunder for the period from January 1,
1998 through March 31, 1998 shall be Two Dollars and Seventy Two
Cents ($2.72) per MMBTU. The price of the gas sold hereunder for
the period from April 1, 1998 through October 31, 1998 (and any
extension mutually consented to) shall be the price per MMBTU as
reported in the Denver Julesburg Basin Index as published by the
Gas Daily, plus $.07 per MMBTU gross heating value at the Receipt
Point. Notwithstanding the preceding, the price of gas sold
hereunder shall in no event be less than $1.35 per MMBTU (lower
collar) nor greater than $1.85 MMBTU (upper collar) gross heating
value at the Receipt Point.
5. On February 2, 1998, Prima shall be paid in good funds the amount of
Three Million Eight Hundred Fifty Thousand Dollars ($3,850,000) in
consideration of the elimination of its obligation to provide gas to the
Buyer for the original Agreement term.
6. On or before October 31, 1998, Prima and Buyer shall execute a mutual
release releasing each other and Prima Oil & Gas Company from any and all
liability arising out of the Agreement.
7. Prima and Buyer agree to negotiate in good faith a replacement gas
supply agreement on or before October 31, 1998, but are not obligated to
enter into such an agreement.
2
<PAGE>
Except for the foregoing, all of the terms and provisions of the Gas Sales
Agreement dated May 24, 1989, as previously amended, shall remain in full
force and effect.
In witness whereof, the parties have executed this Amendment the date and
year first written above.
COLORADO POWER PARTNERS
By: /s/ Rodney E. Bellendir
-------------------------------------
Name: Rodney E. Bellendir
----------------------------------
Title: Management Committee Member
----------------------------------
PRIMA OIL & GAS COMPANY
<TABLE>
<S> <C>
By: /s/ Richard H. Lewis Attest: /s/ Sandra J. Irlando
------------------------------------- -----------------------------
Name: Richard H. Lewis Name: Sandra J. Irlando
---------------------------------- -------------------------------
Title: President Title: Secretary
---------------------------------- -------------------------------
</TABLE>
3
<PAGE>
EXHIBIT 21
SUBSIDIARIES OF THE REGISTRANT
Prima Energy Corporation has one direct wholly owned subsidiary, Prima Oil & Gas
Company, a Colorado corporation.
Prima Oil & Gas Company has two significant wholly owned subsidiaries. These
are as follows:
1. Action Oil Field Services, Inc., a Colorado corporation.
2. Prima Natural Gas Marketing, Inc., a Colorado corporation.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-K
FOR PRIMA ENERGY CORPORATION FOR THE YEAR ENDED DECEMBER 31, 1997 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 5,223,000
<SECURITIES> 1,866,000
<RECEIVABLES> 5,724,000
<ALLOWANCES> (43,000)
<INVENTORY> 882,000
<CURRENT-ASSETS> 13,835,000
<PP&E> 72,516,000
<DEPRECIATION> (29,335,000)
<TOTAL-ASSETS> 57,921,000
<CURRENT-LIABILITIES> 6,304,000
<BONDS> 240,000
0
0
<COMMON> 87,000
<OTHER-SE> 43,127,000
<TOTAL-LIABILITY-AND-EQUITY> 57,921,000
<SALES> 33,839,000
<TOTAL-REVENUES> 38,850,000
<CGS> 23,830,000
<TOTAL-COSTS> 26,198,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 10,737,000
<INCOME-TAX> 2,635,000
<INCOME-CONTINUING> 8,102,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 8,102,000
<EPS-PRIMARY> 1.40
<EPS-DILUTED> 1.37
</TABLE>
