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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, 1996.
[ ] 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 2,485,033 shares of Common Stock held by
non-affiliates of the Registrant as of March 7, 1997 was $41,003,045 (based upon
the mean of the closing bid and asked prices on the NASDAQ System).
As of March 7, 1997, Registrant had outstanding 5,790,556 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 1997 Annual Meeting of
Stockholders.
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TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
1. and 2. BUSINESS and PROPERTIES.......................................... 3
3. LEGAL PROCEEDINGS..................................................... 14
4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................... 14
PART II
5. MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
STOCKHOLDER MATTERS................................................... 17
6. SELECTED FINANCIAL DATA............................................... 18
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS................................... 19
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA........................... 24
9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES............................................. 24
PART III
10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................... 24
11. EXECUTIVE COMPENSATION................................................ 24
12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT........ 24
13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................ 24
PART IV
14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K...... 25
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 and in conjunction 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 14.
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 of 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 1986, Prima effected a one-for-fifteen reverse stock split of its
common stock.
On December 18, 1992, the Company elected to change its fiscal year
end from June 30 to December 31, effective December 31, 1992. This change was
made, among other reasons, to enhance comparability of the Company's results of
operations with other oil and gas companies, most of which report on a calendar
year basis.
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 split.
3
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OIL AND GAS OPERATIONS
The Company's oil and gas operating activities are conducted in the
Denver-Julesburg Basin in northeastern Colorado, Wind River Basin in central
Wyoming, and Powder River Basin in northeastern Wyoming. Prima also has leased
undeveloped acreage in the Green River Basin located in southwest Wyoming, and
in the Texas Panhandle. 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.
At December 31, 1996, the Company operated 334 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.
During 1996, Rocky Mountain spot natural gas prices averaged $1.45 per
MMBtu, rebounding from a $1.09 average price in 1995. Rocky Mountain spot
natural gas prices of $2.25 per MMBtu in November 1996, and $3.50 per MMBtu in
December 1996, were significant in raising the 1996 Rocky Mountain average spot
price to $1.45 per MMBtu. 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 1996, the average price received for the Company's natural gas production
increased 31% to $2.11 per Mcf from $1.61 per Mcf. The price received for the
Company's crude oil production also increased in 1996, averaging $20.84 per
barrel as compared to $17.19 in 1995. During 1996, the Company produced
4,646,000 Mcf of natural gas and 233,000 barrels of oil compared to 4,298,000
Mcf and 266,000 barrels in 1995. The Company drilled, or was in the process of
drilling, 39 gross (23.04 net) wells in 1996 compared to 49 gross (16.16 net)
well in 1995.
The Company's net proved reserves as of December 31, 1996, as
estimated by in-house engineers, consisted of over 52 Bcf of natural gas and
3,000,000 barrels of oil having an estimated pretax discounted present value,
using prices in effect at year end, of approximately $91 million. Approximately
90% 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 attributable to the Wattenberg Area. Approximately 76% of the reserves are
proved developed reserves and approximately 74% are attributable to natural gas
reserves.
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, 1996, the
Company owned interests in 158,000 gross, 107,000 net, undeveloped
acres primarily in the Rocky Mountain region and the Texas
Panhandle.
4
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- Prospect generation - The Company intends to utilize its own
personnel and outside consultants to develop oil and natural gas
prospects to be drilled 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.
1996 ACTIVITY
DENVER-JULESBURG 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. The Company
has drilled and completed about 150 wells in the area over the last five years.
Prima's leasehold position in the Wattenberg Field is 15,000 gross, 11,000 net,
developed acres, with an additional 12,000 gross, 9,000 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. Therefore, these two formations 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. Over the years, the
Company has developed an extensive database of well information and production
history. The 1996 gross production from Prima's Wattenberg Area operated wells
averaged 13,900 Mcf of natural gas and 940 barrels of crude oil per day, with
Prima's average share of such gross production being 9,200 Mcf and 620 barrels
per day.
During the third quarter of 1996, the Company commenced a nineteen well
(18.86 net) drilling program in the Wattenberg Area. At December 31, fourteen
of the wells had been drilled and one well was drilling. The remaining wells
were drilled in the first quarter of 1997. As of February 28, 1997, eighteen
of the wells were completed and on production with one well waiting on
completion. Additionally, during 1996 the Company successfully recompleted five
wells (4.6 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, 1996, the Company owned or
controlled nearly 300 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 all of these locations will ultimately be drilled or that
those wells drilled will ultimately prove to be commercially productive. At
December 31, 1996, the Company had classified 62 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 49 wells with
pay zones behind pipe as proved developed non-producing reserves. The Company
expects to recomplete several of these wells each year.
5
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BONNY FIELD
Prima owns a 15.5% non-operated working interest in approximately 100
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 1,700 feet.
Prima's leasehold position in the Bonny Field is 4,000 gross, 1,000 net,
developed acres, with an additional 13,000 gross, 2,000 net undeveloped acres.
During 1996 the working interest owners drilled 14 development wells, all of
which have been completed and are producing. At December 31, 1996, the Bonny
Field was producing approximately 5,100 Mcf of natural gas per day,
approximately 790 Mcf net to Prima's interest. Additionally, Prima 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. Approximately 5% of
Prima's year end reserves on a BOE basis were attributable to the Bonny Field.
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. The United
States Supreme Court denied the purchaser's petition for Writ of Certiorari on
June 4, 1996 concerning the term provision.
Prima intends to participate in the ongoing development of the Bonny Field.
WIND RIVER BASIN
During 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 is located on the northeastern
margin of the Wind River Basin in central Wyoming. 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 eleven wells drilled within
the Unit from July 1994 (inception of drilling within the Unit) through December
31, 1996, including two drilled during 1996. Eight of the wells were producing
and three were shut-in at December 31, 1996. Cave Gulch Unit 1996 production
averaged 51,000 Mcf of natural gas and 250 barrels of crude oil per day, with
Prima's respective share of 1996 production averaging 2,500 Mcf and 12 barrels
per day. Approximately 4% of Prima's year end reserves on a BOE basis were
attributable to the Cave Gulch Unit. Prima's leasehold position within a two
mile radius of the Unit discovery well is about 4,100 gross, 675 net,
undeveloped acres. Prima has not assigned any reserves to leasehold acreage
outside the Unit.
Currently, the pipelines taking gas from the Cave Gulch area are operating
at capacity. Plans have been announced by the pipeline companies to expand
their take-away capacity by approximately 200,000 MMBtu per day, and to expand
their delivery capabilities into the mid-continent gas markets by the third
quarter of 1997. Several of the wells at Cave Gulch are near raptor nesting
areas. Primarily due to the proximity of raptor nesting sites, the Bureau of
Land Management has directed that an Environmental Impact Statement ("EIS") be
prepared covering the Cave Gulch Unit and surrounding lands. Drilling,
completion and pipeline activities will be substantially curtailed during the
period in which this study is being conducted. Production activities, however,
will continue. The timing of future drilling will be impacted by the pipeline
expansions, completion of the EIS and the timing of obtaining drilling permits
after meeting various governmental regulations and requirements. It is unlikely
that additional wells will be drilled in the Cave Gulch area prior to the summer
of 1997 at the earliest.
6
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Prima has been active in the area of the Cave Gulch discovery since 1987.
The Company participated during 1987 and 1988 as a non-operated working interest
owner in the drilling and completion of two gas wells in the Frontier Formation
at depths of approximately 2,700 feet. The wells are believed to be capable of
modest commercial production but have not been connected to a sales line. Due
to the high volumes of natural gas being produced in the area, pipeline
constraints postponed the anticipated hook-up of these two wells in 1996. The
Company owns a 20% interest in the two wells. The Cave Gulch Unit is
approximately two miles from the shallow Frontier wells.
Prima, as operator, began drilling the Cave Gulch #32-12 well in August of
1996. The well is adjacent to the eastern boundary, but not within, the 440 acre
Cave Gulch Unit. The Company has a 51% working interest in this well. This
well, which targeted the Lance Formation, had been drilled and a completion
attempt was underway as of December 31, 1996. Information gathered during the
completion attempt suggests marginal flow rates. The Company conducted limited
production tests in January 1997, before suspending operations due at least in
part to comply with timing restrictions under its drilling permit. The Company
elected to defer setting production facilities and a pipeline connection pending
further analysis.
During 1996, Prima sold its deep rights, below 14,000 feet, in an
approximate three section pooled area for $695,000 cash and an overriding
royalty interest. An unrelated third party has drilled an approximate 19,000
foot well in the pooled area to test the deeper formations, both under and
adjacent to the Cave Gulch Unit. At February 28, 1997, total depth had been
reached, pipe had been set, and testing and evaluation of several deeper
formations was expected within the next several weeks.
In December of 1996 Prima committed to a 13.7% non-operated working
interest in a Fort Union test well located approximately 5 miles south of the
Cave Gulch Unit. As of February 28, 1997, the well was completed and connected
to pipeline for sales with initial production of approximately 1,600 Mcf of
natural gas per day, 180 Mcf net to Prima's interest.
Prima's leasehold position in the Wind River Basin is approximately 20,000
gross, 12,000 net, undeveloped acres at December 31, 1996.
POWDER RIVER BASIN
During late 1996 and early 1997, Prima drilled three (2.7 net) test wells
targeting the Turner Formation at a depth of approximately 10,000 feet in the
Porcupine-Tuit Draw area of the Powder River Basin. All three wells have been
completed and are on production. This brings the total operated wells in the
area to four. During February of 1997, these wells produced approximately 1,400
Mcf of natural gas and 45 barrels of oil per day, with 1,000 Mcf and 30 barrels
net to Prima's interest.
During the fourth quarter of 1996, the Company also participated for a 50%
non-operated working interest in a 14,300 foot wildcat well targeting the Muddy
and Dakota sands on the southwestern flank of the Powder River Basin. This well
was unsuccessful and has been plugged and abandoned.
Prima's leasehold position in the Powder River Basin at December 31, 1996
was 41,000 gross, 40,000 net, undeveloped acres. The Company has identified
several leads and/or prospects on this acreage on which future drilling is
planned.
7
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OTHER ACTIVITY
In the third quarter of 1996, the Company committed to a 15% non-operated
working interest in a well to be drilled on a 3-D seismically defined prospect
in shallow waters offshore Louisiana. This is a high risk well with large
reserve potential. The well was originally scheduled to be drilled in the
fourth quarter of 1996, but has been delayed pending the operator obtaining a
drilling rig. The Company currently anticipates a spud date near the end of the
first quarter of 1997.
At December 31, 1996, Prima held leasehold positions in the Texas Panhandle
of approximately 26,000 gross, 24,000 net, undeveloped acres. The Company
anticipates drilling or re-entering a few test wells to begin evaluating this
acreage during the second and third quarters of 1997.
Prima also has leasehold acreage in the Green River Basin in southwestern
Wyoming of 34,000 gross, 18,000 net, undeveloped acres at December 31, 1996.
PRODUCTION
The Company's net natural gas production averaged 12,694 Mcf per day for
the year ended December 31, 1996 compared to 11,775 Mcf per day for the year
ended December 31, 1995 and 11,156 Mcf per day during the year ended December
31, 1994. Net oil production averaged 637 barrels per day for the year ended
December 31, 1996 compared to 729 barrels per day during the year ended December
31, 1995 and 811 barrels per day during the year ended December 31, 1994. The
table below summarizes information with respect to the Company's producing oil
and gas properties for each of these periods.
Years Ended December 31,
----------------------------------
1996 1995 1994
---------- ---------- ----------
Quantities Sold:
Natural gas (net Mcf)............... 4,646,000 4,298,000 4,072,000
Oil (net barrels)................... 233,000 266,000 296,000
Average Sales Price:
Natural gas (per Mcf)............... $ 2.11 $ 1.61 $ 1.76
Oil (per barrel).................... $ 20.84 $ 17.19 $ 14.90
Average production (lifting)
costs per equivalent barrel (1)...... $ 2.47 $ 2.21 $ 2.44
________________
(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 December 31, 1996, averaging $24.69 per barrel
of oil and $3.76 per Mcf of natural gas. 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
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inaccurate. For further information concerning the reserves and the
discounted future net cash flows from these reserves, see Note 14 of the
Notes to Consolidated Financial Statements.
<TABLE>
December 31,
-------------------------------------
1996 1995 1994
----------- ---------- ----------
<S> <C> <C> <C>
Estimated proved natural gas reserves (Mcf)....... 52,112,000 47,711,000 46,202,000
Estimated proved oil reserves (barrels)........... 3,037,000 2,734,000 3,009,000
Present value of estimated future net cash
flows (before future income tax expense)........ $91,446,000 $47,785,000 $47,671,000
Standardized measure of discounted
future net cash flows........................... $68,965,000 $39,180,000 $38,095,000
</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, 1996. During March of 1997, both oil and natural gas
prices declined from the prices in effect at December 31, 1996. Oil and natural
gas prices have been volatile in the past and are expected to continue to be
volatile.
Since January 1, 1996, 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, 1996.
<TABLE>
Productive Wells
---------------------------------------
Oil Gas
----------------- -----------------
Gross(1) Net(2) Gross(1) Net(2)
-------- ------ -------- ------
<S> <C> <C> <C> <C>
Operated:
Colorado.......................... 8 7.1 324 254.1
Wyoming........................... 0 0.0 2 1.8
Non-operated:
Colorado.......................... 1 0.2 163 24.7
Oklahoma.......................... 2 0.2 0 0.0
Utah.............................. 0 0.0 2 0.4
Texas............................. 0 0.0 1 0.5
Wyoming........................... 0 0.0 9 0.6
--- ---- --- -----
Total (3)...................... 11 7.5 501 282.1
--- ---- --- -----
--- ---- --- -----
</TABLE>
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Additionally, the Company has a royalty interest in 136 of the gross
wells reported above in which it owns a working interest. Also, the Company
has royalty interests in an additional 26 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 186 dual or triple
completions. Multiple completions are counted as one well.
DEVELOPED AND UNDEVELOPED ACREAGE
At December 31, 1996, the Company held leased acreage as set forth
below:
Developed Acreage (1) Undeveloped Acreage (2)
--------------------- -----------------------
Location Gross (3) Net (4) Gross (3) Net (4)
-------- --------- ------- --------- -------
California................. 0 0 6,586 659
Colorado................... 18,900 11,574 25,067 11,550
Nevada..................... 0 0 3,840 360
Oklahoma................... 1,875 58 0 0
Texas...................... 482 325 25,657 24,016
Utah....................... 320 66 1,857 598
Wyoming.................... 819 245 94,698 69,683
------ ------ ------- -------
Total...................... 22,396 12,268 157,705 106,866
------ ------ ------- -------
------ ------ ------- -------
- ---------------------
(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.
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Acres Expiring
---------------
Twelve Months Ending: Gross Net
------ ------
December 31, 1997............................. 10,933 2,680
December 31, 1998............................. 26,545 20,476
December 31, 1999............................. 11,520 10,008
December 31, 2000............................. 6,199 5,152
December 31, 2001............................. 4,290 4,290
December 31, 2002 and later................... 73,253 52,799
DRILLING ACTIVITIES
Certain information with regard to the Company's drilling activities
for the years ended December 31, 1996, 1995 and 1994 is set forth below:
1996 1995 1994
------------ ----------- -------------
Gross Net Gross Net Gross Net
----- --- ----- --- ---- ---
Development:
Productive......................... 34 20.03 45 15.38 46 34.36
Dry................................ 0 0.00 0 0.00 0 0.00
-- ----- -- ----- -- -----
34 20.03 45 15.38 46 34.36
Exploratory:
Productive......................... 0 0.00 0 0.00 0 0.00
Dry................................ 2 1.00 4 0.78 0 0.00
-- ----- -- ----- -- -----
2 1.00 4 0.78 0 0.00
Total
Productive......................... 34 20.03 45 15.38 46 34.36
Dry................................ 2 1.00 4 0.78 0 0.00
-- ----- -- ----- -- -----
36 21.03 49 16.16 46 34.36
-- ----- -- ----- -- -----
-- ----- -- ----- -- -----
At December 31, 1996 the Company was participating in the drilling
and/or completion of three additional wells. One exploratory well (0.5 net)
was drilling at December 31, but has subsequently been plugged and abandoned.
One development well (1.0 net) which was drilling at December 31 was placed
on production in January of 1997. One development well (0.51 net) was being
tested when operations were suspended due to regulatory requirements.
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 purchase for resale margins.
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,
1996, all of the Company's production from the Bonny Field, which accounted
for approximately 5.5% 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, 1996,
11
<PAGE>
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.
A participation agreement was executed May 24, 1989 between the
Company and an unrelated third party participant (now KN Gas Marketing, Inc.
or KNGM), to supply the natural gas required for a 50 megawatt cogeneration
facility in Brush, Colorado. The Company has contracted to supply 70% of the
committed quantities. Also on May 24, 1989, the Company and KNGM signed a
Gas Sales Agreement with Colorado Power Partnership ("CPP"), the
owner/operator of the cogeneration facility. The Gas Sales Agreement
requires that approximately 1,750,000 MMBtu's per year of natural gas for 15
years be supplied to the cogeneration facility. Deliveries of natural gas
began in the fall of 1990. Under the agreement, CPP is required to take or
pay for 80% of the annual contract quantity. The Company has dedicated a
substantial portion of its proved reserves in the Wattenberg Area to cover
its share of the commitment. The 1997 price for the gas is $2.64 per MMBtu,
which escalates annually at the higher of 3% or a sharing of the indexed
energy payment rate received by CPP. The agreement allows the Company to
supply the natural gas from other sources, substitute dedicated reserves or
secure marketing arrangements with third-party suppliers. During 1996, the
Company supplied all gas from marketing arrangements with third-party
suppliers.
Total revenues from the sales of natural gas and oil produced by the
Company were $14,657,000 or 51.2% of consolidated revenues, for the year
ended December 31, 1996. During 1996, two purchasers, PanEnergy Field
Services and Total Petroleum accounted for 19%, and 15%, respectively, of the
Company's total consolidated revenues. These two purchasers are not
affiliated with Prima. Although the loss of either of these two 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.
To hedge its natural gas and crude oil production, as well as purchase
for resale margins, the Company from time to time uses futures and energy
swaps. 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 participation agreement discussed
above, the Company had no open trading positions to purchase or deliver
natural gas at December 31, 1996. The Company, however, at December 31, 1996
had hedged oil production by selling futures contracts as follows: 15,000
barrels February 1997 NYMEX crude oil at $25.25, 10,000 barrels March 1997
NYMEX crude oil at $24.55, and 10,000 barrels April 1997 NYMEX crude oil at
$23.93. At December 31, 1996, the Company had an unrealized loss of $23,000
on these oil contracts.
During the year ended December 31, 1996, revenues from trading
activities, which included the cost of gas purchased or sold for trading
purposes, were $10,001,000, representing 34.9% of the Company's consolidated
revenues. Trading revenues increased 117% over 1995 revenues of $4,604,000.
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 1996, KN Gas
Marketing, Inc. accounted for 21.1%, and Colorado Power Partnership 11.3% of
the Company's total consolidated revenues. The loss of either of these
customers could have a material adverse effect on the Company.
12
<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 five completion rigs, a swab rig, and various trucking, earth moving,
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 1996, 21.6% 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. Activity in the Wattenberg Area declined
significantly in 1995 due to low gas prices. In 1996, Wattenberg Area
activity improved due to higher oil and gas prices, application of new
drilling technologies, and an increased level of well reworks and
recompletions. Action utilized four of its five rigs during 1996 compared
to three of its five rigs during 1995. The Company continues to monitor
activity and intends to optimize utilization rates to the extent practical.
Revenues recorded by Action from third parties during the year ended December
31, 1996 were $2,269,000 or 7.9% of consolidated revenues.
MANAGEMENT AND OPERATOR SERVICES
The Company provides management and operator services for
approximately 334 wells which the Company operates. 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 $1,003,000 for the year
ended December 31, 1996, which was 3.5% 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, 1996 was $200,000.
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 $983,000 at
December 31, 1996.
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 $88,000 at
December 31, 1996. The facility consists of 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, 1996.
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, 1996 of $197,000.
13
<PAGE>
EMPLOYEES AND OFFICES
As of December 31, 1996, the Company had 61 full-time employees,
including 17 in its Denver office and 44 field employees. Action Oilfield
Services employed 30 of the field employees and 14 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
At December 31, 1996, the Company is not a party to any filed or
pending litigation.
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, 1996.
--------------------
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. 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.
14
<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 Company personnel. 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 90% of the Company's proved reserves at December 31, 1996, were
located in the Wattenberg area of the Denver-Julesburg Basin, where wells are
characterized by relatively rapid decline rates. Additionally, approximately
24% of the Company's total proved reserves at December 31, 1996, 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. Based upon
average daily production during 1996, the Company's hedge agreements covered
approximately 27% and 0% 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
15
<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 starting or continuing 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.
16
<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, 1996 and 1995. These prices have been restated to reflect
the effect of the three for two split of Prima's common stock of March 4,
1997.
Year Ended December 31, 1996 HIGH LOW
---------------------------- ------- -------
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
Year Ended December 31, 1995
----------------------------
Quarter Ended March 31, 1995............ $ 9.500 $ 7.167
Quarter Ended June 30, 1995............. 10.333 8.917
Quarter Ended September 30, 1995........ 10.000 7.833
Quarter Ended December 31, 1995......... 9.833 8.833
On March 7, 1997 the closing sale price for the Company's common
stock was $17.00 per share.
The above quotations are from sources believed to be reliable.
They do not include any retail mark-ups, mark-downs or commissions and may
not represent actual transactions.
(b) APPROXIMATE NUMBER OF HOLDERS OF COMMON STOCK. The number of
holders of record of Prima's common stock at March 7, 1997 was 1,239.
(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. Future dividends, if any, will be
evaluated based among other things, on operating results and financial
condition of the Company at the time.
17
<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>
Years Ended Six Months Year
December 31, Ended Ended
------------------------------------- December June 30,
1996 1995 1994 1993 31, 1992 1992
------- ------- ------- ------- ------- -------
(in thousands, except per share data)
<S> <C> <C> <C> <C> <C> <C>
Income Statement Data:
Revenues:
Oil and gas sales..................... $14,657 $11,502 $11,558 $11,107 $ 3,924 $ 5,552
Trading revenues...................... 10,001 4,604 3,790 2,143 1,082 2,005
Oilfield services..................... 2,269 1,487 2,102 1,744 901 1,453
Management and operator fees.......... 1,003 1,084 1,014 1,063 571 1,092
Interest and dividend income.......... 411 154 143 196 131 326
Other................................. 280 217 1,477 211 219 1,227
------- ------- ------- ------- ------- -------
28,621 19,048 20,084 16,464 6,828 11,655
------- ------- ------- ------- ------- -------
Expenses:
Depreciation, depletion
and amortization..................... 4,544 4,372 4,313 3,869 1,315 2,071
Lease operating expense............... 1,511 1,432 1,512 1,336 468 787
Ad valorem and production taxes....... 1,981 736 863 999 351 462
Cost of trading....................... 9,060 3,613 3,334 1,849 913 1,556
Cost of oilfield services............. 1,759 1,170 1,334 1,112 637 1,013
General and administrative............ 1,812 1,863 1,925 1,958 913 1,692
------- ------- ------- ------- ------- -------
19,667 13,186 13,281 11,123 4,597 7,581
------- ------- ------- ------- ------- -------
Income before income taxes.............. 8,954 5,862 6,803 5,341 2,231 4,074
Income taxes............................ 2,285 1,370 1,572 1,090 445 815
------- ------- ------- ------- ------- -------
Net Income.............................. $ 6,669 $ 4,492 $ 5,231 $ 4,251 $ 1,786 $ 3,259
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Net Income per Common Share
and Common Share Equivalent:.......... $ 1.14 $ 0.77 $ 0.90 $ 0.73 $ 0.31 $ 0.55
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Cash Dividend per Common
Share................................. $ 0.17 $ 0.00 $ 0.00 $ 0.00 $ 0.00 $ 0.00
------- ------- ------- ------- ------- -------
------- ------- ------- ------- ------- -------
Balance Sheet Data
(at end of period):
Total assets............................ $48,006 $38,565 $35,716 $29,477 $21,731 $18,380
Net property and equipment.............. 32,325 29,118 28,177 21,428 13,624 8,693
Long-term debt.......................... 0 0 1,000 1,300 0 0
Stockholders' equity.................... 35,273 29,916 25,353 20,270 16,019 14,233
Working capital......................... 7,863 4,292 848 2,003 2,970 6,032
</TABLE>
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
This Item 7 contains "forward-looking statements" and are made pursuant
to the "safe harbor" provisions of the Private Securities Litigation Reform
Act of 1995. These statements include, without limitation, statements
relating to liquidity, financing of operations, continued volatility of oil
and natural gas prices and estimate of future net cash flows attributable to
proved undeveloped 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 and in conjunction 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 14.
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, 1996. The Consolidated Financial
Statements and notes thereto should be referred to in conjunction with this
discussion.
LIQUIDITY AND CAPITAL RESOURCES
The Company's principal internal sources of liquidity are cash flows
generated from operations and existing cash and cash equivalents. Net cash
provided by operating activities totaled $12,157,000 for the year ended
December 31, 1996 compared to $8,906,000 for the year ended December 31, 1995
and $10,090,000 for the year ended December 31, 1994. Net working capital at
December 31, 1996 was $7,863,000 as compared to $4,292,000 at December 31,
1995. Current assets were $15,011,000 at December 31, 1996 compared to
$8,792,000 at December 31, 1995. Current liabilities were $7,148,000 at
December 31, 1996 compared to $4,500,000 at December 31, 1995. Current
assets increased from December 31, 1995 levels by $6,219,000 and current
liabilities increased by $2,648,000 for the same period. The increase in
working capital of $3,571,000 was primarily generated by cash flows from
operations during the year. The Company also sold undeveloped acreage for
$831,000 and available for sale securities for $418,000 during 1996.
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 $7,942,000 in additions to oil and gas properties
during the year ended December 31, 1996, compared to $5,182,000 during the
year ended December 31, 1995 and $10,620,000 during the year ended December
31, 1994. During 1996, $6,605,000 was paid for the Company's share of
development well costs and recompletions, $401,000 for exploratory costs,
$873,000 for acquisitions of unproved properties and $63,000 for purchases of
proved properties. Other uses of funds in 1996 included $970,000 for
dividend payments, $640,000 for purchases of office equipment and oilfield
service equipment and facilities, $744,000 for purchases of marketable
securities and $383,000 for treasury stock purchases.
The standardized measure of estimated discounted future net cash flows
of the Company's proved oil and natural gas reserves increased to $68,965,000
at December 31, 1996 as compared to $39,180,000 at December 31, 1995 and
$38,095,000 at December 31, 1994. Estimated future net cash flows from
proved oil and natural gas reserves rose to $176,437,000 at December 31, 1996
compared to $85,028,000 at December 31, 1995 and $83,316,000 at December 31,
1994. Oil reserve volumes at December 31, 1996 increased 11% and natural gas
reserve volumes increased 9% compared to December 31, 1995. The
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<PAGE>
weighted average natural gas price received at December 31, 1996 on Company
production was $3.76 per Mcf, an increase of $1.88 per Mcf compared to
December 31, 1995. The year end weighted average oil price was $24.69 per
barrel, an increase of $5.96 per barrel compared to December 31, 1995.
In late 1990, the Company began deliveries of gas to the cogeneration
facility in Brush, Colorado, per its contract with the project owner. At
December 31, 1996, the contract price of $2.64 per MMBtu, escalated annually
at 3% pursuant to the pricing provisions of the contract, was used to value
gas reserves equivalent to one half of the minimum contract quantity or 6.7%
of the Company's estimated proved natural gas reserves, based on the
Company's estimate of the percentage of the minimum contract requirement that
will be fulfilled from its existing reserves.
During 1996, the Company adopted Statement of Financial Accounting
Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" ("SFAS 121"). SFAS 121 provides the
standards for accounting for the impairment of various long-lived assets.
Substantially all of the Company's long-lived assets consist of oil and gas
properties, which are accounted for using the full cost method of accounting,
which requires an impairment to be recorded when total capitalized costs
exceed the present value, discounted at 10%, of estimated future net revenues
from proved oil and natural gas reserves. Therefore, the adoption of SFAS
121 did not have a material effect on the financial position or results of
operations of Prima.
At December 31, 1996, the Company estimates that capital expenditures
of $17,548,000 will be required to develop the Company's proved undeveloped
and proved developed non-producing reserves over the next several years.
Approximately $14,038,000, net of future development costs, of the estimated
future net cash flows of the Company's proved oil and gas reserves at
December 31, 1996 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.
20
<PAGE>
RESULTS OF OPERATIONS
1996 VS 1995
For the year ended December 31, 1996, the Company earned net income of
$6,669,000, or $1.14 per share, on revenues of $28,621,000, compared to net
income of $4,492,000, or $0.77 per 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
50.3%, expenses increased $6,481,000 or 49.2% and net income increased
$2,177,000 or 48.5% 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 27.4%. 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 8.1%. Its net oil production was 233,000 barrels compared to
266,000 barrels for the same periods, a decrease of 33,000 barrels or 12.4%.
On a BOE basis, the Company's production for 1996 increased 24,000 BOE or
2.4%. 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 31.1%. 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 21.3%.
Depreciation, depletion and amortization ("DD&A") rates are affected by
production levels and changes in reserve estimates. Total DD&A expense was
$4,544,000 in 1996 compared to $4,372,000 for 1995, an increase of $172,000
or 3.9%. 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.
Lease operating expenses ("LOE") were $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 ( LOE plus ad valorem and production taxes) 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.
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 $10,001,000 for 1996 compared to $4,604,000 for 1995,
an increase of $5,397,000 or 117.2%. The Company marketed 5,252,000 MMBtu's
of third party gas in 1996 compared to 2,295,000 MMBtu's in 1995, an increase
of 2,957,000 MMBtu's or 128.8%. Costs of trading were $9,060,000 for 1996
compared to $3,613,000 for 1995, an increase of $5,447,000 or 150.8%.
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 1996 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.
21
<PAGE>
Oilfield service revenues of $2,269,000 and $1,487,000 for the years
ended December 31, 1996 and 1995, respectively, represented the revenues
earned by Action Oilfield Services, Inc., a wholly owned subsidiary. These
revenues include well servicing fees from five completion rigs, a swab rig,
trucking, water hauling, dozer and roustabout work, rental equipment and
other related activities. Activity in the Wattenberg Field 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. Revenues increased
$782,000, or 52.6% for 1996. 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, an increase of $589,000 or 50.3%. For the years ended
December 31, 1996 and 1995, 21.6% and 24.5% 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. 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
7.5%. Management and operator fees are earned pursuant to the Company's
roles as operator for approximately 334 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. Fees
decreased in 1996 due to reduced third party ownership in operated wells.
General and administrative expense ("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. G&A costs decreased by $51,000 or 2.7%. The Company's
G&A expense has been relatively consistent from 1995 to 1996 because
personnel levels and facility costs have 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.
Effective tax rates are affected by amounts of permanent differences in
financial and taxable income, consisting primarily of statutory depletion
deductions and Section 29 tax credits.
1995 VS 1994
For the year ended December 31, 1995, the Company earned net income of
$4,492,000, or $0.77 per share, on revenues of $19,048,000, compared to net
income of $5,231,000, or $0.90 per share, on revenues of $20,084,000 for the
year ended December 31, 1994. Operating expenses were $13,186,000 for the
1995 year compared to $13,281,000 for 1994. Revenues decreased $1,036,000 or
5%, expenses decreased $95,000 or 1% and net income decreased $739,000 or 14%
in 1995. The revenues, net income and earnings per share for 1994 include
$1,200,000, $750,000 and $.13, respectively, for proceeds received from a
non-recurring lawsuit settlement.
Oil and gas sales for the year ended December 31, 1995 were $11,502,000
compared to $11,558,000 for the year ended December 31, 1994, a decrease of
$56,000 or .5%. The Company's net natural gas production was 4.30 Bcf for
1995 compared to 4.07 Bcf in 1994, an increase of .23 Bcf or 5.7%. Its net
oil production was 266,000 barrels compared to 296,000 barrels for the same
periods, a decrease
22
<PAGE>
of 30,000 barrels or 10.1%. On a BOE basis, the Company's production for
1995 increased 9,000 BOE or 0.9%. The average price received per Mcf of
natural gas sold was $1.61 for the year ended December 31, 1995 compared to
$1.76 per Mcf for the year ended December 31, 1994, a decrease of $.15 per
Mcf or 8.5%. Approximately 4% of the natural gas production for the year
ended December 31, 1995 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 $1.43
per Mcf for the year ended December 31, 1995. The average price received per
barrel of oil sold was $17.19 for 1995 compared to $14.90 for 1994, an
increase of $2.29 per barrel or 15%.
DD&A expense was $4,372,000 in 1995 compared to $4,313,000 for 1994, an
increase of $59,000 or 1.4%. The Company's depletion of oil and gas properties
was $4,058,000 or $4.13 per BOE on 983,000 equivalent barrels produced in 1995,
compared to $3,974,000 or $4.08 per BOE on 974,000 equivalent barrels produced
in 1994. Included in DD&A expense for 1995 and 1994 is $314,000 and $339,000,
respectively, attributable to depreciation of service equipment, furniture and
equipment and buildings.
LOE was $1,432,000 for the year ended December 31, 1995 compared to
$1,512,000 for the year ended December 31, 1994. Ad valorem and production
taxes were $736,000 and $863,000 for the same periods. Total lifting costs were
19% of oil and gas revenues and $2.21 per equivalent barrel of production for
1995 compared to 21% and $2.44 for 1994.
Trading revenues were $4,604,000 for 1995 compared to $3,790,000 for 1994,
an increase of $814,000 or 21%. The Company marketed 2,295,000 MMBtu's of
third party gas in 1995 compared to 1,678,000 MMBtu's in 1994. Costs of
trading were $3,613,000 for 1995 compared to $3,334,000 for 1994, an increase
of $279,000 or 8%.
Oilfield service revenues were $1,487,000 for the year ended December 31,
1995 compared to $2,102,000 for the year ended December 31, 1994. Fees
decreased by $615,000 or 29.3%. Cost of oilfield services were $1,170,000
for the year ended December 31, 1995 compared to $1,334,000 for the year
ended December 31, 1994. Costs decreased by $164,000 or 12.3%. These
decreases were attributable to decreased activity in the Wattenberg Field
Area where the service company is active. This decline in activity was due
at least in part to the decline in natural gas prices incurred during the
latter part of 1994 which continued into 1995 and resulted in a significant
decline in drilling activity in the area. For the years ended December 31,
1995 and 1994, 25% and 35% of the gross fees billed by Action were for
Company owned wells. The services performed for the Company declined in 1995
because the Company reduced the size of its 1995 Wattenberg drilling program
compared to previous years programs.
Management and operator fees for the years ended December 31, 1995 and
1994 were $1,084,000 and $1,014,000, respectively. The Company operated
approximately 310 oil and gas wells during 1995 compared to 300 for 1994.
Fees also increased in 1995 due to increased management fees earned as
managing venturer of the gas gathering system.
Other revenues for 1994 included $1,200,000 in net proceeds from the
settlement of prior litigation. The settlement proceeds were received and
the income recognized in the fourth quarter of 1994. The proceeds increased
the Company's net income by approximately $750,000 or $0.13 per share.
G&A totaled $1,863,000 for the year ended December 31, 1995 compared to
$1,925,000 for the year ended December 31, 1994. G&A costs decreased by
$62,000 or 3%. The Company reduced its G&A costs as less wells were drilled
based on management's decision to defer drilling due to low natural gas prices.
23
<PAGE>
The provision for income taxes was $1,370,000 for the year ended
December 31, 1995 compared to $1,572,000 for the year ended December 31, 1994.
The effective tax rate was 23.4% in 1995 compared to 23.1% in 1994.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Consolidated Financial Statements and schedules that constitute Item
8 are attached at the end of this Annual Report on Form 10-K. An index to these
Consolidated Financial Statements and Schedules 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 DISCLOSURES
Since the Company's inception, there has not been any Form 8-K filed
under the Securities Exchange Act of 1934 reporting a change in accountants in
which there was a reported disagreement on any matter of accounting principles
or practices or financial statement disclosure.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, and 13
are omitted because the Company will file a definitive proxy statement pursuant
to Regulation 14A under the Securities Exchange Act of 1934 not later than 120
days after the close of the fiscal year. The information required by such Items
will be included in the definitive proxy statement to be so filed for the
Company's annual meeting of stockholders scheduled for May 16, 1997 and is
hereby incorporated by reference.
24
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) (1) FINANCIAL STATEMENTS
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
----
Independent Auditors' Report................................................ 26
Consolidated Balance Sheets at December 31, 1996 and 1995................... 27
Consolidated Statements of Income for the years ended
December 31, 1996, 1995 and 1994.......................................... 29
Consolidated Statements of Stockholders' Equity for the years ended
December 31, 1996, 1995 and 1994.......................................... 30
Consolidated Statements of Cash Flows for the years ended
December 31, 1996, 1995 and 1994.......................................... 31
Notes to Consolidated Financial Statements for the years ended
December 31, 1996, 1995 and 1994.......................................... 32
(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
10.1 Extension of Line of Credit Letter Agreement
(Incorporated by reference as Exhibit 10-96.1 to
Form 10-Q filed May 6, 1996)
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, 1996. A Form 8-K was filed February 10, 1997, announcing the
approval by Prima's Board of Directors of a three for two split of the Company's
$0.015 par value common stock, payable to stockholders of record on February 20,
1997, payable on March 4, 1997.
25
<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, 1996 and
1995, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended
December 31, 1996. 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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996, in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
March 14, 1997
Denver, Colorado
26
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 1996 AND 1995
ASSETS
------
1996 1995
------------ ------------
CURRENT ASSETS
Cash and cash equivalents........................... $ 6,704,000 $ 3,977,000
Available for sale securities, at market............ 1,503,000 1,180,000
Receivables (net of allowance for doubtful
accounts: 1996, $45,000; 1995, $43,000).......... 5,921,000 3,087,000
Tubular goods inventory............................. 311,000 217,000
Deferred tax asset.................................. 0 101,000
Other current assets................................ 572,000 230,000
------------ ------------
Total current assets.......................... 15,011,000 8,792,000
------------ ------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method................... 52,885,000 45,774,000
Less accumulated depreciation,
depletion and amortization....................... (21,940,000) (17,730,000)
------------ ------------
Oil and gas properties - net.................. 30,945,000 28,044,000
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment.......................... 2,387,000 1,888,000
Furniture and equipment............................. 652,000 518,000
Field office, shop and land......................... 341,000 334,000
------------ ------------
3,380,000 2,740,000
Less accumulated depreciation....................... (2,000,000) (1,666,000)
------------ ------------
Property and equipment - net.................. 1,380,000 1,074,000
------------ ------------
OTHER ASSETS
Cash, designated.................................... 325,000 326,000
Other............................................... 345,000 329,000
------------ ------------
Total other assets............................ 670,000 655,000
------------ ------------
$48,006,000 $38,565,000
------------ ------------
------------ ------------
See accompanying notes to consolidated financial statements.
27
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
DECEMBER 31, 1996 AND 1995
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
1996 1995
----------- -----------
CURRENT LIABILITIES
Accounts payable.................................... $ 2,526,000 $ 1,746,000
Amounts payable to oil and gas property owners...... 2,831,000 1,086,000
Ad valorem and production taxes payable............. 1,094,000 1,239,000
Accrued and other liabilities....................... 476,000 429,000
Deferred tax liability.............................. 221,000 0
----------- -----------
Total current liabilities..................... 7,148,000 4,500,000
AD VALOREM TAXES, non-current....................... 984,000 1,012,000
DEFERRED TAX LIABILITY.............................. 4,601,000 3,137,000
----------- -----------
Total liabilities............................. 12,733,000 8,649,000
----------- -----------
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value,
2,000,000 shares authorized;
no shares issued or outstanding.................. 0 0
Common stock, $0.015 par value, 8,000,000
shares authorized; 5,820,556 shares issued ...... 87,000 87,000
Additional paid-in capital.......................... 4,222,000 4,222,000
Retained earnings................................... 31,383,000 25,684,000
Unrealized loss on available for sale securities.... (36,000) (77,000)
Treasury stock, 30,000 shares at cost............... (383,000) 0
----------- -----------
Stockholders' equity - net.................... 35,273,000 29,916,000
----------- -----------
$48,006,000 $38,565,000
----------- -----------
----------- -----------
See accompanying notes to consolidated financial statements.
28
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
1996 1995 1994
----------- ----------- -----------
REVENUES
Oil and gas sales.................... $14,657,000 $11,502,000 $11,558,000
Trading revenues..................... 10,001,000 4,604,000 3,790,000
Oilfield services.................... 2,269,000 1,487,000 2,102,000
Management and operator fees......... 1,003,000 1,084,000 1,014,000
Interest and dividend income......... 411,000 154,000 143,000
Other................................ 280,000 217,000 1,477,000
----------- ----------- -----------
28,621,000 19,048,000 20,084,000
----------- ----------- -----------
EXPENSES
Depreciation, depletion and
amortization........................ 4,544,000 4,372,000 4,313,000
Lease operating expense.............. 1,511,000 1,432,000 1,512,000
Ad valorem and production taxes...... 981,000 736,000 863,000
Cost of trading...................... 9,060,000 3,613,000 3,334,000
Cost of oilfield services............ 1,759,000 1,170,000 1,334,000
General and administrative........... 1,812,000 1,863,000 1,925,000
----------- ----------- -----------
19,667,000 13,186,000 13,281,000
----------- ----------- -----------
INCOME BEFORE INCOME TAXES........... 8,954,000 5,862,000 6,803,000
PROVISION FOR INCOME TAXES........... 2,285,000 1,370,000 1,572,000
----------- ----------- -----------
NET INCOME........................... $ 6,669,000 $ 4,492,000 $ 5,231,000
----------- ----------- -----------
----------- ----------- -----------
NET INCOME PER COMMON SHARE
AND COMMON SHARE EQUIVALENT........ $ 1.14 $ 0.77 $ 0.90
----------- ----------- -----------
----------- ----------- -----------
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING AND COMMON SHARE
EQUIVALENTS........................ 5,848,001 5,824,764 5,828,117
----------- ----------- -----------
----------- ----------- -----------
See accompanying notes to consolidated financial statements.
29
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
ADDITIONAL UNREALIZED
COMMON PAID-IN RETAINED LOSS ON TREASURY
STOCK CAPITAL EARNINGS SECURITIES STOCK TOTAL
------- ---------- ----------- --------- --------- -----------
<S> <C> <C> <C> <C> <C> <C>
BALANCES, January 1, 1994.......... $87,000 $4,222,000 $15,961,000 $ 0 $ 0 $20,270,000
Net income......................... 5,231,000 5,231,000
Unrealized loss on available
for sale securities............... (148,000) (148,000)
------- ---------- ----------- --------- --------- -----------
BALANCES, December 31, 1994........ 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 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 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
------- ---------- ----------- --------- --------- -----------
------- ---------- ----------- --------- --------- -----------
</TABLE>
See accompanying notes to consolidated financial statements.
30
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
<TABLE>
1996 1995 1994
------------ ------------ ------------
<S> <C> <C> <C>
OPERATING ACTIVITIES
Net income ................................... $ 6,669,000 $ 4,492,000 $ 5,231,000
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation, depletion and amortization... 4,544,000 4,372,000 4,313,000
Deferred income taxes...................... 1,761,000 889,000 1,277,000
Other...................................... 26,000 (34,000) 52,000
Changes in operating assets and
liabilities:
Receivables............................. (2,834,000) 338,000 (1,426,000)
Inventory............................... (94,000) 261,000 286,000
Other assets............................ (342,000) 24,000 (159,000)
Payables................................ 2,380,000 (1,512,000) 467,000
Accrued and other liabilities........... 47,000 76,000 49,000
------------ ------------ ------------
Net cash provided by operating
activities.......................... 12,157,000 8,906,000 10,090,000
------------ ------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties........... (7,942,000) (5,182,000) (10,620,000)
Purchases of other property................... (640,000) (249,000) (481,000)
Purchases of securities....................... (744,000) (181,000) (70,000)
Proceeds from sales of property............... 831,000 125,000 42,000
Proceeds from sales of securities............. 418,000 0 488,000
------------ ------------ ------------
Net cash used by investing activities...... (8,077,000) (5,487,000) (10,641,000)
------------ ------------ ------------
FINANCING ACTIVITIES
Dividends paid................................ (970,000) 0 0
Treasury stock purchased...................... (383,000) 0 0
Borrowings under line of credit............... 0 0 2,000,000
Payments on line of credit.................... 0 (1,000,000) (2,300,000)
------------ ------------ ------------
Net cash used by financing activities...... (1,353,000) (1,000,000) (300,000)
------------ ------------ ------------
Increase (Decrease) in Cash and Cash
Equivalents.................................. 2,727,000 2,419,000 (851,000)
Cash and Cash Equivalents, beginning
of year...................................... 3,977,000 1,558,000 2,409,000
------------ ------------ ------------
Cash and Cash Equivalents, end of year........ $ 6,704,000 $ 3,977,000 $ 1,558,000
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
See accompanying notes to consolidated financial statements.
31
<PAGE>
PRIMA ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994
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, 1996.
USE OF ESTIMATES
The preparation of the financial statements for 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:
Years Ended December 31,
-----------------------------
1996 1995 1994
-------- ------- --------
Income taxes............ $693,000 $ 0 $584,000
Interest................ 0 29,000 59,000
32
<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 income tax
effect, as an adjustment to stockholders' equity. Available for sale securities
are readily marketable and used routinely in operations, 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.
During 1996, the Company adopted Statement of Financial Accounting
Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of" ("SFAS 121"). SFAS 121 provides the
standards for accounting for the impairment of various long-lived assets.
Substantially all of the Company's long-lived assets consist of oil and gas
properties which are evaluated for impairment as described above. Because the
new standard does not apply to costs capitalized pursuant to the full cost
method, the adoption of SFAS 121 did not have a material effect on the financial
position or results of operations of Prima.
33
<PAGE>
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.
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, 1996, the Company had delivered 13,000 MMBtu's to the purchaser
which had not been delivered into the pipeline. 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 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.
At December 31, 1995, the Company had delivered 48,000 MMBtu's into the
pipeline which had not been delivered to the purchaser. This gas is also valued
at the lower of cost or market value. Included in other current assets at
December 31, 1995, is $60,000 representing the cost of gas which had been
delivered into the pipeline but not delivered to the purchaser.
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. 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 scheduled physical transactions (scheduled physical
transactions include committed gas marketing activities or production from
producing wells), the transactions would 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,
1996, the Company had no transactions that did not correspond to scheduled
physical transactions. For the years ended December 31, 1996, 1995 and 1994,
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, 1996, 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.
34
<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 due plus deferred
taxes related to certain income and expenses recognized in different periods for
financial and income tax reporting purposes. The deferred tax assets and
liabilities represent the future tax consequences of those differences, which
will either be taxable or deductible when the assets and liabilities are
recovered or settled. Deferred tax assets are also recognized for tax credits
that are available to offset future federal income taxes. These deferred taxes
are measured by applying currently enacted tax rates.
EARNINGS PER SHARE
Net income per common share and common share equivalents is computed
using the weighted average number of shares of common stock and common stock
equivalents outstanding during each year. Options to purchase stock are
included as common stock equivalents, when dilutive, using the treasury stock
method.
2. SUBSEQUENT EVENT
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.
3. 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.
Oil hedge contracts are not recorded on the balance sheet at December
31, 1996. The Company estimates the fair value of these contracts to be
$(23,000). The estimated fair value of the oil hedge contracts is determined by
multiplying the difference between year end oil prices and the hedge contract
price by the quantities under contract.
35
<PAGE>
4. AVAILABLE FOR SALE SECURITIES
The Company's investments are comprised of marketable equity securities.
For the year ended December 31, 1996, the Company sold securities with a market
value of $418,000 which resulted in realized losses of $70,000. No securities
were sold in 1995. The net unrealized loss on securities at December 31, 1996
and 1995 is included as a separate component of stockholders' equity, net of
deferred income taxes of $20,000 and $45,000, respectively. The change in net
unrealized gain or loss on securities for the years ended December 31, 1996 and
1995 was determined as follows:
1996 1995
---------- ----------
Net unrealized loss, beginning of year ...... $ 122,000 $ 226,000
Net unrealized loss, end of year............. 56,000 122,000
---------- ----------
Net change in unrealized loss................ $ 66,000 $ 104,000
---------- ----------
---------- ----------
The components of fair value as of December 31, 1996 and 1995 are as follows:
1996 1995
---------- ----------
Cost (including reinvested distributions).... $1,559,000 $1,302,000
Gross unrealized gains....................... 5,000 1,000
Gross unrealized losses...................... (61,000) (123,000)
---------- ----------
Fair value................................... $1,503,000 $1,180,000
---------- ----------
---------- ----------
5. LINE OF CREDIT
Prima maintains an $8,000,000 unsecured line of credit with a commercial
bank. The line of credit, which matures on May 1, 1998, bears interest at the
bank's prime rate (8.25% at December 31, 1996), with interest payable monthly.
At December 31, 1996 and 1995, there were no amounts outstanding under the line
of credit.
6. 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, as well as purchase for resale margins. 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 27%, 11% and 40% of its oil production in 1996, 1995 and 1994,
respectively, and hedged approximately 0%, 34% and 33% of its natural gas
production in these same years. Hedging gains and losses are included in oil
and gas revenues at the time the hedged volumes are sold. At December 31, 1996,
the Company had sold crude oil futures contracts as follows:
Unrealized
Price Barrels Term Gain or (Loss)
------- ------- ------------- --------------
$ 25.25 15,000 January, 1997 $ (10,000)
24.55 10,000 February, 1997 (7,000)
23.93 10,000 March, 1997 (6,000)
36
<PAGE>
At December 31, 1996, the Company purchased a swap on 600,000 MMBtu
(60,000 MMBtu per month for ten months) to provide for a fixed margin per
MMBtu on a sales agreement for a similar volume of natural gas. In a typical
"swap" agreement, the Company receives the difference between a fixed price
per unit of production and the index price, if the index price is lower. If
the index price is higher, the Company pays the difference. Current hedging
agreements are settled on a monthly basis. All current contracts specify the
third party index to be the "Inside FERC" first of the month spot price for
Colorado Interstate Gas Co.
7. INCOME TAXES
The provision for income taxes consists of the following components:
Years Ended December 31,
1996 1995 1994
---------- ---------- ----------
Current:
Federal.............................. $ 400,000 $ 354,000 $ 199,000
State................................ 124,000 127,000 96,000
---------- ---------- ----------
524,000 481,000 295,000
---------- ---------- ----------
Deferred:
Federal.............................. 1,741,000 1,116,000 1,260,000
State................................ 277,000 127,000 232,000
---------- ---------- ----------
2,018,000 1,243,000 1,492,000
---------- ---------- ----------
Tax credits............................ (257,000) (354,000) (215,000)
---------- ---------- ----------
Provision for income taxes............. $2,285,000 $1,370,000 $1,572,000
---------- ---------- ----------
---------- ---------- ----------
The significant components of deferred tax assets and deferred tax
liabilities included in the balance sheet are as follows:
1996 1995
---------- ----------
Deferred Tax Assets:
Minimum tax credit carryforwards............ $2,736,000 $2,478,000
State deferred income taxes................. 322,000 226,000
Investment in partnerships.................. 42,000 58,000
Other....................................... 52,000 114,000
---------- ----------
Total Deferred Tax Assets................... 3,152,000 2,876,000
---------- ----------
Deferred Tax Liabilities:
Intangible drilling costs................... 7,351,000 5,340,000
Deferred revenues........................... 82,000 0
Depreciation................................ 61,000 42,000
Other....................................... 480,000 530,000
---------- ----------
Total Deferred Tax Liabilities.............. 7,974,000 5,912,000
---------- ----------
$4,822,000 $3,036,000
---------- ----------
---------- ----------
37
<PAGE>
The reconciliation of income tax computed at the federal statutory tax
rate to the Company's effective tax rate is as follows:
Years Ended December 31,
1996 1995 1994
------- ------- -------
Statutory income tax rate.................. 34.0% 34.0% 34.0%
Percentage depletion....................... (2.7) (3.4) (2.2)
Section 29 credits......................... (8.3) (13.7) (8.6)
State taxes, net of federal benefit........ 3.0 2.9 3.1
Other...................................... (0.5) 3.6 (3.2)
------- ------- -------
Effective tax rate.................... 25.5% 23.4% 23.1%
------- ------- -------
------- ------- -------
At December 31, 1996, the Company had minimum tax credit carryforwards
of approximately $2,736,000, which may be carried forward indefinitely.
8. MAJOR CUSTOMERS
The following customers have each provided over 10% of the Company's revenues
from the identified industry segment. Following is a table summarizing the
percentage provided by 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 alternate customers for the purchase of its
production and would be able to secure additional marketing opportunities.
1996 1995 1994
---- ---- ----
Oil and Gas Operations:
PanEnergy Field Services, Inc........... 19% 21% 26%
Total Petroleum......................... 15 20 20
Natural Gas Marketing and Trading:
Colorado Power Partnership.............. 11 13 14
KN Gas Marketing, Inc................... 21
38
<PAGE>
9. 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, 1996, 1995
and 1994 for the Company's two identifiable industry segments.
<TABLE>
1996 1995 1994
----------- ----------- -----------
<S> <C> <C> <C>
Revenues
Oil and gas....................................... $26,011,000 $17,399,000 $17,916,000
Oilfield services................................. 2,894,000 1,968,000 3,214,000
Other............................................. 340,000 162,000 66,000
----------- ----------- -----------
Total........................................... $29,245,000 $19,529,000 $21,196,000
----------- ----------- -----------
----------- ----------- -----------
Operating Earnings
Oil and gas....................................... $ 8,315,000 $ 5,617,000 $ 6,307,000
Oilfield services................................. 299,000 104,000 489,000
Other............................................. 340,000 141,000 7,000
----------- ----------- -----------
Total........................................... $ 8,954,000 $ 5,862,000 $ 6,803,000
----------- ----------- -----------
----------- ----------- -----------
Identifiable Assets
Oil and gas........................................ $37,872,000 $31,803,000 $30,975,000
Oilfield services.................................. 1,666,000 1,237,000 1,394,000
Other.............................................. 8,468,000 5,525,000 3,347,000
----------- ----------- -----------
Total........................................... $48,006,000 $38,565,000 $35,716,000
----------- ----------- -----------
----------- ----------- -----------
Depreciation, Depletion and Amortization Expense
Oil and gas........................................ $ 4,321,000 $ 4,138,000 $ 4,032,000
Oilfield services.................................. 223,000 234,000 281,000
----------- ----------- -----------
Total........................................... $ 4,544,000 $ 4,372,000 $ 4,313,000
----------- ----------- -----------
----------- ----------- -----------
Capital Expenditures
Oil and gas....................................... $ 8,251,000 $ 5,299,000 $10,678,000
Oilfield services................................. 331,000 132,000 423,000
----------- ----------- -----------
Total........................................ $ 8,582,000 $ 5,431,000 $11,101,000
----------- ----------- -----------
----------- ----------- -----------
</TABLE>
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 and are eliminated in
consolidation. Oilfield services revenue includes $624,000, $481,000 and
$1,112,000 for the years ended December 31, 1996, 1995 and 1994,
respectively, for intersegment sales. Oilfield services revenue are 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.
39
<PAGE>
10. 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 $109,000, $127,000 and $124,000 for the years ended December 31,
1996, 1995 and 1994, respectively. Future minimum annual rentals are as
follows:
Year ending December 31, 1997........................ $126,000
Year ending December 31, 1998........................ 129,000
Year ending December 31, 1999........................ 132,000
Year ending December 31, 2000........................ 124,000
--------
$511,000
--------
--------
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 has
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
requires 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 is required to take or pay for 80% of the annual contract
quantity. The Company has dedicated a substantial portion of its proved
reserves in Weld County, Colorado to cover its share of the commitment. The
1997 price for the gas is $2.64 per MMBtu, which escalates annually at the
higher of 3% or a sharing of the indexed energy payment rate received by the
owner/operator.
11. 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 of a stock option.
Options granted under the Plan vest at 20% per year for five years, with a
term of 10 years from the date of grant. At December 31, 1996, 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. The remaining contractual life of the
options outstanding ranged from 6.75 years to 8.5 years.
40
<PAGE>
A summary of options granted, exercised and outstanding during 1994,
1995 and 1996 is as follows:
Number Weighted Average
of Shares Exercise Prices
--------- ----------------
Balance, December 31, 1993.................. 232,500 $8.83
Granted during 1994......................... 22,500 9.33
Exercised or canceled....................... 0 n/a
-------
Outstanding at 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
-------
Balance at December 31, 1996................ 367,500 9.20
-------
-------
Exercisable at December 31, 1994............ 46,500 8.83
Exercisable at December 31, 1995............ 97,500 8.86
Exercisable at December 31, 1996............ 171,000 9.00
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:
1996 1995
---------- ----------
Net income: As reported............ $6,669,000 $4,492,000
Pro forma.............. 6,509,000 4,492,000
Net income per share: As reported.. $1.14 $0.77
Pro forma.... 1.11 0.77
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:
Expected dividend yield.............. 0%
Expected price volatility............ 31%
Risk free interest rate.............. 6.6%
Expected life of options (in years).. 9
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
41
<PAGE>
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, 1996,
1995 and 1994, the Company expensed $117,000, $93,000 and $119,000,
respectively, of contributions payable to the Plan.
12. 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 1996 which is not
payable until fiscal 1998 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.
13. 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. These amounts
are not significant.
42
<PAGE>
14. SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)
Costs incurred in oil and gas property acquisition, exploration and
development activities are as follows:
Years Ended December 31,
------------------------------------
1996 1995 1994
---------- ----------- ----------
Acquisition costs:
Unproved properties..................... $ 873,000 $1,319,000 $ 688,000
Proved properties....................... 63,000 27,000 402,000
Exploration costs......................... 401,000 202,000 0
Development costs......................... 6,605,000 3,634,000 9,530,000
---------- ---------- -----------
Total.................................. $7,942,000 $5,182,000 $10,620,000
---------- ---------- -----------
---------- ---------- -----------
Amortization per equivalent
barrel of production.................... $ 4.18 $ 4.13 $ 4.08
---------- ---------- -----------
---------- ---------- -----------
Results of operations for oil and gas producing activities are as
follows:
Years Ended December 31,
------------------------------------
1996 1995 1994
---------- ----------- ----------
Revenues
Oil and gas sales....................... $14,657,000 $11,502,000 $11,588,000
----------- ----------- -----------
Expenses
Lease operating expense................. 1,511,000 1,432,000 1,512,000
Ad valorem and production taxes......... 981,000 736,000 863,000
Depreciation, depletion and amortization 4,210,000 4,058,000 3,974,000
----------- ----------- -----------
6,702,000 6,226,000 6,349,000
----------- ----------- -----------
Income before income taxes................ 7,955,000 5,276,000 5,239,000
Income tax expense........................ 2,029,000 1,233,000 1,048,000
----------- ----------- -----------
Income from oil and gas producing
properties.............................. $ 5,926,000 $ 4,043,000 $ 4,191,000
----------- ----------- -----------
----------- ----------- -----------
The reserve information presented below has been prepared by the
Company's personnel. 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.
43
<PAGE>
Proved oil and gas reserves of the Company, all of which are located
in the United States, are as follows:
Years Ended December 31,
----------------------------------------------
1996 1995 1994
--------------- -------------- --------------
Oil Gas Oil Gas Oil Gas
(MBBLS) (MMCF) (MBBLS) (MMCF) (MBBLS) (MMCF)
------- ------ ------- ------ ------- ------
Proved reserves:
Beginning of year.............. 2,734 47,711 3,009 46,202 2,702 42,638
Purchases of oil and
gas reserves in place........ 14 231 14 123 4 345
Revisions of previous
estimates.................... 130 2,444 (39) (218) (90) (2,624)
Extensions, discoveries and
other additions.............. 392 6,372 17 5,924 689 9,915
Production..................... (233) (4,646) (266) (4,298) (296) (4,072)
Sales of oil and gas reserves
in place..................... 0 0 (1) (22) 0 0
------- ------ ------ ------ ------ ------
End of Year.................... 3,037 52,112 2,734 47,711 3,009 46,202
------- ------ ------ ------ ------ ------
------- ------ ------ ------ ------ ------
Proved developed reserves:
Beginning of year.............. 1,853 38,076 2,080 35,664 1,724 30,422
End of year.................... 2,087 41,107 1,853 38,076 2,080 35,664
Standardized measures of discounted future net cash flows relating to
proved oil and gas reserves are as follows:
Years Ended December 31,
----------------------------------------
1996 1995 1994
------------ ------------ ------------
Future cash inflows................... $271,196,000 $148,101,000 $144,215,000
Future production costs............... (77,211,000) (47,648,000) (47,347,000)
Future development costs.............. (17,548,000) (15,425,000) (13,552,000)
------------ ------------ ------------
Future net cash flows................. 176,437,000 85,028,000 83,316,000
10% discount factor................... (84,991,000) (37,243,000) (35,645,000)
Discounted future income taxes........ (22,481,000) (8,605,000) (9,576,000)
------------ ------------ ------------
Standardized measure of discounted
future net cash flows.............. $ 68,965,000 $ 39,180,000 $ 38,095,000
------------ ------------ ------------
------------ ------------ ------------
44
<PAGE>
The principal sources of change in the standardized measure of
discounted future net cash flows are as follows:
<TABLE>
Years Ended December 31,
----------------------------------------------
1996 1995 1994
-------------- ------------- -------------
<S> <C> <C> <C>
Sales of oil and gas produced,
net of production costs.......................... $ (12,165,000) $ (9,334,000) $ (9,183,000)
Net changes in prices and production costs....... 37,015,000 (1,763,000) (3,980,000)
Extensions, discoveries, and improved recovery,
less related costs............................... 11,187,000 8,505,000 13,899,000
Development costs incurred during the year........ 3,077,000 2,729,000 3,609,000
Changes in estimated future development costs..... (558,000) (2,629,000) (103,000)
Revisions of previous quantity estimates
and other........................................ 806,000 (1,291,000) (2,383,000)
Purchases of reserves in place.................... 381,000 101,000 208,000
Sales of reserves in place........................ 0 (13,000) 0
Accretion of discount............................. 3,918,000 3,809,000 3,494,000
Net change in income taxes........................ (13,876,000) 971,000 (2,401,000)
-------------- ------------- -------------
Net change........................................ $ 29,785,000 $ 1,085,000 $ 3,160,000
-------------- ------------- -------------
-------------- ------------- -------------
</TABLE>
15. QUARTERLY FINANCIAL DATA (UNAUDITED)
The following is a summary of the unaudited financial data for each
quarter for the years ended December 31, 1996 and 1995.
<TABLE>
<CAPTION>
Three Months Ended
------------------------------------------------------
3/31/96 6/30/96 9/30/96 12/31/96
------------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
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 1,897,000 2,993,000
Net income........................... 1,529,000 1,401,000 1,538,000 2,201,000
Net income per share................. 0.26 0.24 0.26 0.37
<CAPTION>
Three Months Ended
------------------------------------------------------
3/31/95 6/30/95 9/30/95 12/31/95
------------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
Year Ended December 31, 1995
Revenues............................. $ 5,702,000 $ 3,954,000 $ 4,003,000 $ 5,389,000
Gross profit......................... 1,606,000 1,266,000 1,305,000 1,531,000
Net income........................... 1,257,000 1,001,000 1,008,000 1,226,000
Net income per share................. 0.21 0.17 0.17 0.21
</TABLE>
45
<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 14th day of March, 1997.
PRIMA ENERGY CORPORATION
By: /s/ RICHARD H. LEWIS
---------------------------
Richard H. Lewis, President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed below by the following persons in
the capacities indicated and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ RICHARD H. LEWIS March 14, 1997
- --------------------------
Richard H. Lewis Chairman, President, Treasurer,
(Principal Executive and
Financial Officer)
/s/ ROBERT E. CHILDRESS
- -------------------------- March 14, 1997
Robert E. Childress Director
/s/ DOUGLAS J. GUION March 14, 1997
- --------------------------
Douglas J. Guion Director
/s/ JOHN P. LOCKRIDGE March 14, 1997
- --------------------------
John P. Lockridge Director
/s/ GEORGE L. SEWARD March 14, 1997
- --------------------------
George L. Seward Director
/s/ SANDRA J. IRLANDO March 14, 1997
- --------------------------
Sandra J. Irlando Vice President of Accounting
and Controller
46
<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 SCHEDULED CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM Form 10-k
for Prima Energy Corporation for the year ended December 31, 1996 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-END> DEC-31-1996
<CASH> 6,704,000
<SECURITIES> 1,503,000
<RECEIVABLES> 5,966,000
<ALLOWANCES> (45,000)
<INVENTORY> 311,000
<CURRENT-ASSETS> 15,011,000
<PP&E> 56,265,000
<DEPRECIATION> (23,940,000)
<TOTAL-ASSETS> 48,006,000
<CURRENT-LIABILITIES> 7,148,000
<BONDS> 0
0
0
<COMMON> 87,000
<OTHER-SE> 35,186,000
<TOTAL-LIABILITY-AND-EQUITY> 48,006,000
<SALES> 24,658,000
<TOTAL-REVENUES> 28,621,000
<CGS> 16,096,000
<TOTAL-COSTS> 16,096,000
<OTHER-EXPENSES> 0
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<INCOME-PRETAX> 8,954,000
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<EXTRAORDINARY> 0
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<NET-INCOME> 6,669,000
<EPS-PRIMARY> 1.14
<EPS-DILUTED> 1.14
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