<PAGE>

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                       SECURITIES AND EXCHANGE COMMISSION
                            WASHINGTON, D.C.  20549

                                   FORM 10-K

[X]     Annual Report Pursuant to Section 13 or 15(d) of the Securities
        Exchange Act of 1934 for the fiscal year ended December 31, 1997.

[ ]     Transition Report Pursuant to Section 13 or 15(d) of the Securities
        Exchange Act of 1934.

                         COMMISSION FILE NUMBER 0-9408

                            PRIMA ENERGY CORPORATION
             (Exact name of Registrant as specified in its charter)

             DELAWARE                                 84-1097578
 (State or other jurisdiction of          (I.R.S. Employer Identification No.)
  incorporation or organization)

  1801 BROADWAY, SUITE 500, DENVER, COLORADO         80202
   (Address of principal executive offices)        (Zip Code)

                                  (303) 297-2100
              (Registrant's telephone number, including area code)

           Securities registered pursuant to Section 12(b) of the Act
                                      NONE

           Securities registered pursuant to Section 12(g) of the Act
                         COMMON STOCK, $0.015 PAR VALUE
                                (Title of Class)

Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.            Yes   [X]   No   [ ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of the Form 10-K or any amendment to this
Form 10-K.   [X]

Aggregate market value of the 2,632,637 shares of Common Stock held by
non-affiliates of the Registrant as of March 13, 1998 was $50,842,802 (based
upon the mean of the closing bid and asked prices on the Nasdaq System).

As of March 13, 1998, Registrant had outstanding 5,770,056 shares of Common
Stock, $0.015 Par Value, its only class of voting stock.

                       DOCUMENT INCORPORATED BY REFERENCE
Parts of the following document are incorporated by reference to Part III of the
Form 10-K Report:  Proxy Statement for the Registrant's 1998 Annual Meeting of
Stockholders.

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<PAGE>

                                        
                                TABLE OF CONTENTS
<TABLE>
                                        
ITEM                                                                   PAGE
----                                                                   ----
<S>    <C>                                                             <C>
                                     PART I
                                        
1. and 2. BUSINESS and PROPERTIES.....................................    3

3.     LEGAL PROCEEDINGS..............................................   15

4.     SUBMISSION OF MATTERS TO A VOTE OF SECURITYHOLDERS.............   15


                                     PART II
                                        
5.     MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
       STOCKHOLDER MATTERS............................................   18

6.     SELECTED FINANCIAL DATA........................................   19

7.     MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
       CONDITION AND RESULTS OF OPERATIONS............................   20

8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................   25

9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
       ACCOUNTING AND FINANCIAL DISCLOSURE............................   25


                                    PART III

10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.............   26

11.    EXECUTIVE COMPENSATION.........................................   26

12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
       MANAGEMENT.....................................................   26

13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................   26

                                     PART IV

14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON 
       FORM 8-K......................................................    27

</TABLE>


                                       2
<PAGE>

                                     PART I

ITEMS 1 and 2. BUSINESS and PROPERTIES

     "The Company" or "Prima" is used in this report to refer to Prima Energy 
Corporation and its consolidated subsidiaries.  Items 1 and 2 contain 
"forward-looking statements" and are made pursuant to the "safe harbor" 
provisions of the Private Securities Litigation Reform Act of 1995.  These 
statements include, without limitation, statements relating to the drilling 
and completion of wells, well operations, utilization rates of oilfield 
service equipment, reserve estimates (including estimates for future net 
revenues associated with such reserves and the present value of such future 
net reserves), business strategies and other plans and objectives of Prima 
management for future operations and activities and other such matters.  The 
words "believes," "plans," "intends," "strategy," or "anticipates" and 
similar expressions identify forward-looking statements.  Prima does not 
undertake to update, revise or correct any of the forward-looking 
information.  Readers are cautioned that such forward-looking statements 
should be read in connection with Prima's disclosures under the heading: 
"Cautionary Statement for the Purposes of the 'Safe Harbor' Provisions of the 
Private Securities Litigation Reform Act of 1995" beginning on page 15.

GENERAL

     Prima was incorporated in April 1980 as a start-up company for the 
purpose of engaging in the exploration for, and the acquisition, development 
and production of crude oil and natural gas and for other related business 
activities.  In October 1980, the Company became publicly owned with a $3.6 
million common stock offering.  In more recent years, the Company's 
activities, through its wholly owned subsidiaries, have expanded to include 
oil and gas property operations, oilfield services and natural gas marketing 
and trading.

     Prima's oil and gas exploration and production activities are conducted 
by Prima Oil & Gas Company, a wholly owned subsidiary.  Crude oil and natural 
gas marketing and trading is conducted by Prima Natural Gas Marketing, Inc., 
a wholly owned subsidiary of Prima Oil & Gas Company.  Action Oil Field 
Services, Inc., a wholly owned subsidiary of Prima Oil & Gas Company, is 
involved in various aspects of the oilfield service business.

     In 1993, Prima effected a two for one stock split of its common stock.

     The Board of Directors of Prima approved a three for two stock split of 
its common stock, to stockholders of record on February 20, 1997, distributed 
March 4, 1997.  As a result, the number of shares of common stock outstanding 
increased from 3,860,396  to 5,790,556 on the distribution date.  All share 
and per share amounts included in this Form 10-K have been restated to show 
the retroactive effects of the stock splits.

OIL AND GAS OPERATIONS

     The Company's oil and gas operating activities are conducted in the 
Denver-Julesburg Basin in northeastern Colorado, the Wind River Basin in 
central Wyoming, the Powder River Basin in northeastern Wyoming, and in the 
Texas Panhandle.  Prima also has leased undeveloped acreage in the Green 
River Basin located in southwest Wyoming. The Wattenberg Field Area 
("Wattenberg Area") in the Denver- Julesburg Basin is the Company's principal 
area of operation. Prima's business activities include oil and gas lease 
acquisition, exploration, development, production, marketing and operations.

                                      3
<PAGE>

     At December 31, 1997, the Company operated 372 producing wells.  It is 
an objective of the Company to operate, when possible, the oil and gas 
properties in which it has economic interests.  The Company believes, with 
the responsibility and authority as operator, it is in a better position to 
control costs, safety, and timeliness of work, as well as other critical 
factors affecting the economics of a well.

     The Company's natural gas production is marketed pursuant to a number of 
gas sales agreements which vary with respect to their specific provisions, 
including price, gross volumes and length of contract.  During 1997, the 
average price received for the Company's natural gas production was $2.39 per 
Mcf, as compared to $2.11 per Mcf in 1996.  The price Prima receives for its 
natural gas production is higher than the Rocky Mountain spot price because 
the Wattenberg Area production is rich gas (approximately 1,250 Btu) which 
commands a premium price, and because of its proximity to a major 
metropolitan market. Additionally, approximately 5% of Prima's production is 
sold pursuant to a $5.90 per MMBtu contract price which raises Prima's 
average gas price by approximately $0.19 per Mcf.  The price received for the 
Company's crude oil production  was $19.90 per barrel in 1997, as compared to 
$20.84 in 1996. During 1997, the Company produced 5,344,000 Mcf of natural 
gas and 255,000 barrels of oil compared to 4,646,000 Mcf and 233,000 barrels 
in 1996.  The Company drilled 50 gross (36.48 net) wells in 1997 compared to 
39 gross (23.04 net) wells in 1996.

     The Company's net proved reserves as of December 31, 1997, as estimated 
by the consulting engineering firm of Reed W. Ferrill & Associates, Inc., 
consisted of over 63 Bcf of natural gas and 3,358,000 barrels of oil having 
an estimated pretax discounted present value, using prices in effect at year 
end, of approximately $76 million.  Approximately 74% of Prima's year end 
estimated reserves on a barrel of oil equivalent ("BOE") basis, converted on 
the basis of six Mcf of natural gas to one barrel of oil, are proved 
developed reserves and approximately 76% are attributable to natural gas 
reserves.

     A summary of the Company's key statistics by area of activity at 
December 31, 1997 is as follows:

<TABLE>
                                                                                            
                                         Percent of               Daily Net Production                Percent of 
                                           Proved           ----------------------------------       Oil and Gas
                                          Reserves              Oil (bbls)        Gas (Mcf)            Revenue
                                        --------------      --------------     ---------------     ---------------
                                        1997      1996      1997      1996     1997       1996     1997       1996
                                        ----      ----      ----      ----     ----       ----     ----       ----
  <S>                                   <C>       <C>       <C>       <C>     <C>        <C>       <C>        <C>
  Wattenberg Area.................        77%       90%      680       622    10,265     9,217        75%       77%
  Bonny Field.....................         4         5         0         0       763       696         9        10
  Wind River Basin................         8         4         9        12     3,004     2,549        13        12
  Powder River Basin..............        11         1        10         3       590       232         3         1

</TABLE>

     The Company plans to continue to identify, develop and exploit 
opportunities in all of its areas of oil and gas operations over the next few 
years.  The Company intends to build upon past success utilizing the reserve, 
production and cash flow from core properties to create additional 
opportunities.  For the foreseeable future, the Company intends to emphasize:

- Further exploitation of the Company's inventory of potential drillsites and
  recompletion opportunities based upon its technical evaluation and activity in
  the areas where the Company is active.

- Acquisition of both developed and undeveloped properties.  The Company 
  regularly reviews opportunities for acquisition of assets or companies 
  related to the oil and gas industry which could expand or enhance its 
  existing business.  At December 31, 1997, the Company owned interests in 
  221,000 gross, 149,000 net, undeveloped acres in its areas of interest.

                                      4
<PAGE>

- Prospect generation - The Company utilizes its own personnel and outside
  consultants to develop oil and natural gas prospects for drilling either 
  solely by the Company or with partners on lease acreage acquired in Prima's 
  core areas. The Company also acquires interests in exploratory or development
  projects through acquisition or farm-ins from third parties.

1997 ACTIVITY

DENVER BASIN

WATTENBERG AREA

     The Wattenberg Area is located approximately 30 miles northeast of 
Denver, Colorado and encompasses an area in excess of 1,000 square miles.  
Prima's leasehold position in the Wattenberg Area is 15,439 gross, 11,799 
net, developed acres, with an additional 9,551 gross, 7,912 net, undeveloped 
acres.  See "Developed and Undeveloped Acreage" below.  The Company's 
drilling and production activities have been centered in a portion of the 
field where the primary productive reservoirs are the Codell and Niobrara 
formations with occasional production from the J-Sand, Parkman and Sussex 
formations.  The Codell and Niobrara reservoirs blanket large areas of the 
field and have moderate porosity and low permeability. These two formations, 
therefore, require stimulation to establish economic production.  Recoverable 
reserves in any individual well bore are controlled by reservoir quality, 
reservoir thickness, the gas-to-oil ratio, and fracture stimulation 
techniques.  The Company has developed an extensive database of well 
information and production history.  The 1997 production from Prima's 
Wattenberg Area properties accounted for approximately 75% of total oil and 
gas revenues, with natural gas production averaging 10,265 Mcf per day and 
oil production averaging 680 barrels per day net to Prima's interest.

     During the second quarter of 1997, the Company commenced a twenty well 
(19.7 net) drilling program in the Wattenberg Area.  At December 31, 1997, 
all twenty of the wells had been drilled.  Seventeen of the wells were 
completed and on production by December 31, and the remaining three wells 
were placed on production in January 1998.  Additionally, during 1997 the 
Company successfully recompleted 10 wells (9.1 net).

     The Company intends to continue its development and exploitation 
activities in the Wattenberg Area, with the timing of the activities largely 
dependent on natural gas and oil prices.  At December 31, 1997 the Company 
owned or controlled nearly 250 potential drillsites in the Wattenberg Area.  
A substantial number of these locations are in areas where the Company 
believes historical results of older producing wells have either been 
uneconomic or marginally economic.  The Company's strategy includes drilling 
and completing selected wells in these areas over the next few years 
utilizing advanced drilling and completion techniques, improved marketing, 
and cost controls in an attempt to improve the wells' economics and prove up 
additional acreage.  There is no assurance that any of these locations will 
ultimately be drilled or that any wells drilled will ultimately prove to be 
commercially productive.  At December 31, 1997 the Company had classified 45 
undrilled locations in the Wattenberg Area as proved undeveloped reserves in 
its year-end reserve report. Additionally, the Company included in its year 
end reserve report 74 wells with pay zones behind pipe as proved developed 
non-producing reserves.  The Company expects its primary exploitation efforts 
will focus on recompleting or restimulating its behind pipe reserves over the 
next few years.  The Company's reserve report contemplates 32 recompletions 
and 10 new wells at Wattenberg during 1998, with an estimated capital 
expenditure of $5,072,000.

                                      5
<PAGE>

DENVER INTERNATIONAL AIRPORT (DIA)

     In the second quarter of 1997, Prima acquired a 12,760 gross and net 
acre oil and gas lease from the City and County of Denver covering a portion 
of its Denver International Airport property.  The property is located 
approximately 20 miles northeast of downtown Denver.  The lease contains 
provisions which require that a well be drilled every 90 days, and that the 
Federal Aviation Administration approve each drill site.  Prima drilled, 
completed and turned to production two wells on this lease in the fourth 
quarter of 1997, in which the Company owns a 100% working interest.  The 
wells targeted the "D" and "J" sands in this area at approximately 8,000 
feet.  One well was deepened to the Dakota Formation at approximately 8,350 
feet but was not productive from that zone. The two wells are both productive 
from the "J" Formation.  The Company intends to continue to evaluate and 
develop this leasehold by drilling two wells which have been included in the 
reserve report as proved undeveloped locations.  These wells will be drilled 
during late spring and early summer of 1998 at an expected capital 
expenditure of $560,000.  The ongoing development of DIA will be reviewed 
following these two wells.

BONNY FIELD

     Prima owns non-operated working interests ranging from 15.5% to 33.3% in 
approximately 120 producing wells in the Bonny Field located in Yuma County 
in eastern Colorado.  The wells produce from the Niobrara Formation at a 
depth of about 1,800 feet.  Prima's leasehold position in the Bonny Field is 
4,371 gross, 720 net, developed acres, with an additional 11,882 gross, 1,923 
net, undeveloped acres.   During 1997 the working interest owners drilled 9 
development wells (2.29 net to Prima), which have all been completed and are 
producing.  For the year ended December 31, 1997, the Bonny Field accounted 
for approximately 9% of Prima's oil and gas revenues with production 
averaging approximately 763 Mcf of natural gas per day net to Prima's 
interest.

     The natural gas contract for the Bonny Field, for both existing and new 
wells, provides for a $5.90 per MMBtu price, no market-out, 95% take or-pay, 
and continued purchases beyond expiration of the primary term in May 2002.  
The contract has been fully litigated as to these terms and conditions.

     Approximately 4% of Prima's year end reserves on a BOE basis were 
attributable to the Bonny Field.  Prima intends to participate in the ongoing 
development of this field.

      Prima also owns a 15.5% interest in and serves as managing venturer and 
operator of the gathering and compression entity for the field, Bonny 
Gathering Company.  Prima and other non-managing owners participated in a 
renovation and upgrade of this gathering system beginning the third quarter 
of 1997, scheduled for completion the second quarter of 1998.  Gathering, 
compression and dehydration facilities are being replaced with new specially 
designed equipment in order to enhance deliverability of natural gas, improve 
run times and facilitate ongoing development of the field.  The renovation 
and upgrade will cost approximately $600,000 to Prima's interest.

WIND RIVER BASIN

     Prima owns between a 4.5% and 50% working interest in 22 wells located  
in the Cave Gulch Area of the Wind River Basin in central Wyoming.  The 
Company operates two of the 22 wells.  The Company has been active in this 
area since 1987 and 1988 when it participated in the drilling and completion 
of two gas wells in the Frontier Formation at depths of approximately 2,700 
feet.  These two wells are currently not being produced due to high line 
pressure on the interstate pipeline in the area of the wells.

                                      6
<PAGE>

     In 1994, Prima contributed approximately 27 net acres to the formation 
of a 440 acre federal unit, the Cave Gulch Unit ("Unit"), in which Prima owns 
a 6% non-operated working interest.  The Unit was formed to target a thick 
section of lenticular sandstones in the Fort Union and Lance formations of 
Tertiary and Upper Cretaceous age.  Prima has participated for its 6% 
interest in 12 wells drilled within the Unit from July 1994 (inception of 
drilling within the Unit) through December 31, 1997, including one well 
drilled during 1997.

      During 1997, Prima participated in the drilling of five wells directly 
north of the Unit (North Cave Gulch) in which the Company has non-operated 
working interests ranging from 6% to 18%. These wells also targeted the Fort 
Union and Lance formations. At year end, two of the wells were producing and 
three were being completed.  As of March 13, 1998, one additional well had 
been completed and was producing, and the remaining two were still in various 
stages of completion.

     In the fourth quarter of 1997, Prima began drilling its operated 
Northwest Cave Gulch #25-43 well approximately one mile west of the Unit.  
Prima has a 24% working interest in this well which  targeted  the Lance 
Formation sands at depths ranging from approximately 5,500 to 8,500 feet.  
The well reached total depth in January 1998, and completion was in progress 
as of March 13, 1998.

     During 1997, Prima also participated for its 4.5% non-operated working 
interest share of a well located one half mile north of the Unit, and 
scheduled to test the Lakota, Dakota, Muddy and Frontier formations to a 
depth of approximately 19,000 feet.  This well was drilling at year end.  
During February 1998, a strong pressure kick was experienced upon drilling 
two feet into the Muddy Formation at a depth of 18,175 feet.  The kick 
necessitated extreme well control measures to avoid a more serious problem 
and the possible loss of the wellbore and/or rig.  Beginning February 19, 
1998, the gas flow was diverted into an emergency sales line at rates that 
have varied between 25 and 45 million cubic feet of gas per day on a 31/64 
inch dual choke with a flowing tubing pressure in excess of 10,800 pounds per 
square inch.  Current plans by the operator are to continue to produce the 
well and monitor its behavior before deciding whether to continue drilling or 
rig down and produce the well from the Muddy and Frontier formations.

     Development drilling in the Cave Gulch Area was delayed in 1996 and part 
of 1997 pending  issuance of an Environmental Impact Study for which the 
Record of Decision was issued in August 1997. Drilling in the area has 
progressed steadily since completion of the Study.  Also in 1997, two major 
interstate pipelines completed projects to move additional gas from the 
immediate area.  Additional capacity is estimated to be approximately 140,000 
Mcf per day.  Due to additional gas production from the area, however, 
pipeline capacity may be constrained from time to time in this area.

     Prima's leasehold position in the Wind River Basin is approximately 640 
gross, 67 net, developed acres, with an additional 27,584 gross, 17,826 net, 
undeveloped acres at December 31, 1997.  Average daily production from this 
area net to Prima's share in 1997 was approximately 3,004 Mcf and 9 barrels 
per day. The oil and natural gas revenues approximated 13% of Prima's total 
oil and gas sales for the year.  This area represents about 8% of Prima's 
year end reserves on a BOE basis.  After considering geological, engineering 
and marketing risks, Prima intends to continue its participation in 
development of this area on a well-by-well basis as it steps out from 
existing production.

POWDER RIVER BASIN

     Prima currently operates 7 wells (6.27 net) in the Powder River Basin, 
an extensive basin which covers the Northeast quadrant of the State of 
Wyoming. The wells are all located in Campbell County, Wyoming.  The Company 
is producing from the Turner Formation at a depth of approximately 10,000 
feet in four of its wells, and the Muddy Formation at a depth of 
approximately 9,500 in the three remaining wells.  Prima's initial well 
operations began in this basin in 1994.

                                      7
<PAGE>


     During the fourth quarter of 1997 and the first quarter of 1998, Prima 
drilled four Muddy Formation wells in which the Company owns from 66.67% to 
100% working interests.  Three of the four wells were completed and turned to 
production by January 1998.  These wells are included in the 7 operated well 
count in the preceding paragraph.  The three wells were producing 
approximately 2,200 Mcf of natural gas and 80 barrels per day net to Prima's 
interest at March 13, 1998.  The fourth well encountered gas shows while 
drilling, but the reservoir quality was not sufficient to deem an economic 
completion. Consequently, the well was plugged and abandoned.  Prima acquired 
its right to drill these wells in a farmout agreement, whereby after drilling 
the wells Prima earned additional lease acreage and drilling locations.  The 
three completed and producing wells provide the Company with offset 
development locations which the Company intends to drill in 1998. Prima 
believes at this time that it has a minimum of three and a maximum of eight 
development locations to be drilled in 1998.  The amount of locations 
actually drilled will depend on results of each offsetting well.

     Prima's leasehold position in the Powder River Basin at December 31, 
1997, was 459 gross, 391 net, developed acres, with an additional 60,380 
gross, 55,585 net, undeveloped acres.  Oil and gas sales from the area 
approximated 3% of Prima's total oil and gas sales for the year ended 
December 31, 1997, averaging 590 Mcf of natural gas and 10 barrels of oil per 
day.  The Powder River Basin Area contributed 11% of Prima's reserves on a 
BOE basis in 1997.  The Company has identified several additional leads and 
prospects in this basin on which future drilling is anticipated.

OTHER ACTIVITY

     During 1997, Prima drilled or re-entered five wells on its Texas 
Panhandle acreage.  Two of the wells were capable of marginal production, and 
three were dry holes.  Prima owns a 100% working interest and operates these 
wells which tested the Brown Dolomite Formation at a depth of approximately 
3,000 feet, and the Red Cave Formation at a depth of approximately 2,800 
feet.  Prima currently holds 1,444 gross, 1,288 net, developed acres, and 
26,954 gross, 25,187 net, undeveloped acres in this area.  The Company plans 
no additional expenditures, and is considering selling its wells and leases 
in this area.

     Prima has 66,028 gross, 26,499 net, undeveloped lease acres in the 
Greater Green River Basin located in west central Wyoming.  The Company has 
supported, through acreage options, the drilling of two 14,000 exploratory 
test wells in an area where Prima owns about 59,000 gross, 21,800 net, acres. 
Prima will not own an interest in the initial exploratory wells.  The 
initial well commenced operations in September 1997, and the decision was 
made by the operator to run casing and attempt completion.  The second 
exploratory well reached total depth during February 1998 and the operator 
elected to run casing.  The Company believes the operator will attempt a 
completion on these wells in the near future.  The results of these two 
exploratory wells will be key in evaluating the play and determining Prima's 
future activity in this area.

     In January 1998, Prima committed to a 6.25% non-operated working 
interest in a well to be drilled in Kern County, California.  The well is on 
a seismically defined structure, and is scheduled to spud in the second 
quarter of 1998.  This is a high risk well with large reserve potential.

PRODUCTION

     The Company's net natural gas production averaged 14,641 Mcf per day for 
the year ended December 31, 1997 compared to 12,694 Mcf per day for the year 
ended December 31, 1996 and 11,755 Mcf per day during the year ended December 
31, 1995.  Net oil production averaged 699 barrels per day for the year ended 
December 31, 1997 compared to 637 barrels per day during the year ended 
December 31, 1996 and 729 barrels per day during the year ended December 31, 
1995.  The table below summarizes information with respect to the Company's 
producing oil and gas properties for each of these periods.

                                      8
<PAGE>

<TABLE>
                                                          Year Ended December 31,
                                                   ---------------------------------------
                                                      1997          1996            1995
                                                   ---------      ---------      ---------
<S>                                                <C>            <C>            <C>
Quantities Sold:
  Natural gas (Mcf)..........................      5,344,000       4,646,000      4,298,000
  Oil (barrels)..............................        255,000         233,000        266,000
Average Sales Price:
  Natural gas (per Mcf)......................       $   2.39        $   2.11       $   1.61
  Oil (per barrel)...........................       $  19.90        $  20.84       $  17.19
Average production (lifting)                  
  costs per equivalent barrel (1)............       $   2.68        $   2.47       $   2.21
</TABLE>

---------------
(1)   Natural gas production has been converted to a common unit of
      production (barrel of oil) on the basis of relative energy content
     (six Mcf of natural gas to one barrel of oil).

RESERVES

     The table below sets forth the Company's estimated quantities of proved 
reserves, all of which are located in the continental United States, and the 
present value of estimated future net cash flows from these reserves on a 
non-escalated basis, except as provided by contract.  The quantities and 
values are based on prices in effect at year end (averaging $17.08 per barrel 
of oil and $2.40 per Mcf of natural gas at December 31, 1997 compared to 
$24.69 per barrel of oil and $3.76 per Mcf of natural gas at December 31, 
1996).  The future net cash flows were discounted by ten percent per year as 
of the end of each of the last three fiscal periods.  The ten percent 
discount factor is specified by the Securities and Exchange Commission and is 
not necessarily the most appropriate discount rate.  Present value, no matter 
what rate is used, is materially affected by assumptions as to timing of 
future production, which may prove to be inaccurate.  For further information 
concerning the reserves and the discounted future net cash flows from these 
reserves, see Note 13 of the Notes to Consolidated Financial Statements.

<TABLE>
                                                               December 31,
                                                 -----------------------------------------
                                                     1997           1996           1995
                                                 -----------    -----------    -----------
<S>                                              <C>            <C>            <C>
Estimated proved natural gas reserves (Mcf)..     63,490,000     52,112,000     47,711,000
Estimated proved oil reserves (barrels)......      3,358,000      3,037,000      2,734,000
Present value of estimated future net cash
  flows (before future income tax expense)...    $75,540,000    $91,446,000    $47,785,000
Standardized measure of discounted
  future net cash flows......................    $58,149,000    $68,965,000    $39,180,000
</TABLE>

     There are numerous uncertainties inherent in estimating quantities of 
proved reserves and in projecting future rates of production and timing of 
development expenditures.  The data in the above table represents estimates 
only.  Oil and gas reserve engineering must be recognized as a subjective 
process of estimating underground accumulations of oil and natural gas that 
cannot be measured in an exact way.  The accuracy of any reserve estimate is 
a function of the quality of available data and engineering, and geological 
interpretation and judgment.  Results of drilling, testing and production 
after the date of the estimate may justify revisions.  Accordingly, reserve 
estimates are often materially different from the quantities of oil and 
natural gas that are ultimately produced.  There has been no major discovery 
or other favorable event that is believed to have caused a significant upward 
change in estimated proved reserves subsequent to December 31, 1997.  Oil and 
natural gas prices declined during the first quarter of 1998.  Oil and 
natural gas prices have historically been volatile and are expected to 
continue to be so in the future. 

                                      9
<PAGE>

Changes in product prices affect the present value of estimated future net 
cash flows and the standardized measure of discounted future net cash flows. 
Although oil and natural gas prices have declined from those experienced at 
year end, the Company does not believe these price declines would result in 
an impairment to the book value of its oil and gas properties.

     Since January 1, 1997, the Company has filed Department of Energy Form 
EIA-23, "Annual Survey of Oil and Gas Reserves," as required by operators of 
domestic oil and gas properties.  There are differences between the reserves 
as reported on Form EIA-23 and reserves as reported herein.  Form EIA-23 
requires that operators report on total proved developed reserves for 
operated wells only and that the reserves be reported on a gross operated 
basis rather than on a net interest basis.

PRODUCTIVE WELLS

     The following table summarizes total gross and net productive wells for the
Company at December 31, 1997.

<TABLE>
                                              Productive Wells
                                  ---------------------------------------
                                          Oil                  Gas
                                  ----------------      -----------------
                                  Gross(1)  Net(2)      Gross(1)   Net(2)
                                  --------  ------      --------   ------
<S>                               <C>       <C>         <C>         <C>
 Operated:
  Colorado......................      8       7.1          354      286.7
  Texas.........................      0       0.0            3        2.5
  Wyoming.......................      0       0.0            7        6.3
 Non-operated:
  Colorado......................      1       0.2          147       28.7
  Oklahoma......................      2       0.2            0        0.0
  Utah..........................      0       0.0            2        0.4
  Wyoming.......................      0       0.0           15        1.0
                                     --       ---          ---      -----
     Total (3)..................     11       7.5          528      325.6
                                     --       ---          ---      -----
                                     --       ---          ---      -----
</TABLE>

     Additionally, the Company has a royalty interest in 127 of the gross 
wells reported above in which it owns a working interest.  Also, the Company 
has royalty interests in an additional 59 gross wells which are not included 
in the above table. 

------------------
(1)  A gross well is a well in which a working interest is held.  The number of
     gross wells is the total number of wells in which a working interest is
     owned.

(2)  A net well is deemed to exist when the sum of fractional ownership
     interests in gross wells equals one.  The number of net wells is the sum of
     the fractional working interests owned in gross wells expressed as whole
     numbers and fractions thereof.

(3)  Wells are classified as oil wells or gas wells according to their
     predominate production stream.  The totals include 190 dual or triple
     completions.  Multiple completions are counted as one well.

                                       10
<PAGE>

DEVELOPED AND UNDEVELOPED ACREAGE

   At December 31, 1997, the Company held leased acreage as set forth below:

<TABLE>
                                  Developed Acreage (1)        Undeveloped Acreage (2)
                                 -----------------------       -----------------------
     Location                    Gross (3)       Net (4)       Gross (3)       Net (4)
     --------                    ---------       -------       ---------       -------
<S>                              <C>             <C>           <C>            <C>
     Colorado...............      20,568         12,934         35,341         23,110
     Nevada.................           0              0          2,240            210
     Oklahoma...............       1,875             58              0              0
     Texas..................       1,445          1,288         26,954         25,187
     Utah...................         320             66          1,857            598
     Wyoming................       1,100            458        154,474        100,390
                                  ------         ------        -------        -------
    
     Total..................      25,308         14,804        220,866        149,495
                                  ------         ------        -------        -------
                                  ------         ------        -------        -------
</TABLE>
----------------
(1)  Developed acres are acres spaced or assigned to productive wells.

(2)  Undeveloped acreage are those lease acres on which wells have not been
     drilled or completed to a point that would permit the production of
     commercial quantities of oil or natural gas, regardless of whether such
     acreage contains proved reserves.

(3)  A gross acre is an acre in which a working interest is owned.  The number
     of gross acres is the total number of acres in which a working interest is
     owned.

(4)  A net acre is deemed to exist when the sum of the fractional ownership
     working interests in gross acres equals one.  The number of net acres is
     the sum of the fractional working interests owned in gross acres expressed
     as whole numbers and fractions thereof.

     Many of the leases summarized in the table above as undeveloped acreage
will expire at the end of their respective primary terms unless production has
been obtained from the acreage subject to the lease prior to that date, in which
event the lease will remain in effect until the cessation of production.  The
following table sets forth the expiration dates of the gross and net acres
subject to leases summarized in the table of undeveloped acreage.

<TABLE>
 
                                                      Acres Expiring
                                                  ----------------------
  Twelve Months Ending:                            Gross           Net
                                                  -------         ------
<S>                                               <C>             <C>
    December 31, 1998...........................   26,606         21,413
    December 31, 1999...........................   17,808         12,942
    December 31, 2000...........................    8,567          6,270
    December 31, 2001...........................    4,290          4,290
    December 31, 2002...........................    3,675          2,931
    December 31, 2003 and later.................  119,260         75,970
</TABLE>


                                        11

<PAGE>

DRILLING ACTIVITIES

     Certain information with regard to the Company's drilling activities for
the years ended December 31, 1997, 1996 and 1995 is set forth below:

<TABLE>
                             1997                 1996                1995
                        --------------       --------------      --------------
                        Gross     Net        Gross     Net       Gross     Net
                        -----    -----       -----    -----      -----    -----
<S>                     <C>      <C>         <C>      <C>        <C>      <C>
Development:
  Productive...........  46      33.74         34     20.03        45     15.38
  Dry..................   0       0.00          0      0.00         0      0.00
                        ----     -----       -----    -----      -----    -----
                         46      33.74         34     20.03        45     15.38
Exploratory:                                                   
  Productive...........   0       0.00          0      0.00         0      0.00
  Dry..................   4       2.70          2      1.00         4      0.78
                        ----     -----       -----    -----      -----    -----
                          4       2.70          2      1.00         4      0.78
Total                                                          
  Productive...........  46      33.74         34     20.03        45     15.38
  Dry..................   4       2.70          2      1.00         4      0.78
                        ----     -----       -----    -----      -----    -----
                              
                         50      36.44         36     21.03        49     16.16
                        ----     -----       -----    -----      -----    -----
                        ----     -----       -----    -----      -----    -----
</TABLE>

     Since December 31, 1997, the Company has participated in the drilling of
ten additional wells.  One exploratory well (1.0 net) in the Powder River Basin
was plugged and abandoned in January 1998.  One exploratory well (.045 net) at
Cave Gulch commenced production in February 1998.  Four development wells (0.8
net) at the Bonny Field also commenced production in February 1998.  Four
development wells at Cave Gulch were in various stages of completion as of March
13,1998.

OIL AND GAS MARKETING AND TRADING

     The Company's marketing and trading activities consist of marketing the 
Company's own production, marketing the production of others from wells 
operated by the Company, and gas trading activities that consist of the 
purchase and resale of natural gas.  Financial instruments are used from time 
to time in order to hedge the price of a portion of the Company's production, 
as well as purchases for resale.

     Total revenues from the sales of natural gas and oil produced by the 
Company were $17,840,000 or 46% of consolidated revenues, for the year ended 
December 31, 1997.  During 1997, two purchasers, Duke Energy Field Services, 
Inc. and Total Petroleum, accounted for 20%, and 11%, respectively, of the 
Company's total consolidated revenues.  These two purchasers are not 
affiliated with Prima.  Although the loss of either of these two customers 
could have a material adverse effect on the Company, the Company believes it 
would be able to locate alternate customers in the event of the loss of 
either or both of these purchasers.

     The Company has entered into a number of gas sales agreements with 
respect to the sale of gas from its producing wells.  These contracts vary 
with respect to their specific provisions, including price, quantity and 
length of contract. The Company's oil production is sold under contracts at 
prices which are based upon posted prices. For the year ended December 31, 
1997, all of the Company's production from the Bonny Field, which accounted 
for approximately 5% of the Company's total natural gas production, was 
committed to a gas sales contract that had a fixed price ($5.90 per MMBtu).  
At December 31, 1997, none of the Company's remaining production, except 
those reserves dedicated to a gas sales agreement with a cogeneration 
facility discussed below, had been sold under a fixed price contract or under 
a contract that required the Company to deliver any specified amount of 
production.

                                       12
<PAGE>

     In December 1997, Prima agreed to terminate its long-term, fixed-price 
with annual escalation contract to supply natural gas to Colorado Power 
Partnership ("CPP"), effective October 31, 1998, for $3,850,000, and other 
consideration. The payment and closing was scheduled for, and completed in 
January 1998. Prima's participating supply partner, KN Gas Marketing, Inc., 
also terminated its obligation to supply CPP.  Prima supplied 70%, and KN Gas 
Marketing, Inc. 30%, of CPP's gas requirements for approximately 1,750,000 
MMBtu per year.  KN Gas Marketing, Inc, has no right or obligation to supply 
CPP after December 31, 1997.  Initial sales to CPP began in the fall of 1990 
and the contract was to expire in the year 2005.  From January 1, 1998, 
through October 31, 1998, Prima has agreed to supply 100% of CPP's gas 
requirements.  Prima will receive $2.72 per MMBtu from January 1, 1998 
through March 31, 1998, and a spot related index price from April 1, 1998 
through October 31, 1998.  After that time, CPP and Prima have agreed to 
negotiate in good faith a new supply contract through the year 2005, but 
neither party has an obligation to supply or purchase from the other.  
Prima's substantial dedication of gas reserves in the Wattenberg Area in 
northeast Colorado for the long-term contract will be released effective 
October 31, 1998.

     To hedge its natural gas and crude oil production and purchases for 
resale, the Company from time to time uses futures and energy swaps.  The 
purpose of these hedges is to provide market price protection in the volatile 
environment of oil and natural gas spot pricing.  As a result of its trading 
activities, the Company may also from time to time have open purchase or sale 
commitments without corresponding contracts to offset these commitments, 
which could result in losses to the Company.  The Company attempts to control 
its exposure to these risks by monitoring its positions as it deems 
appropriate.  All hedges or open positions are reviewed by the Chief 
Executive Officer before they are committed to, and significant positions are 
reviewed by the Company's Board of Directors. With the exception of the CPP 
contract discussed above, the Company had no open trading positions to 
purchase or deliver natural gas at December 31, 1997. During 1997, the 
Company hedged a portion of its expected natural gas production in its key 
area of production, the Rocky Mountain Region, by entering into a one year 
commodity swap agreement covering 150,000 MMBtu per month, beginning April 1, 
at a fixed price of $1.575 per MMBtu.  At December 31, 1997, the Company had 
an unrealized loss of $155,000 on the remaining open months of January, 
February and March 1998.

     Subsequent to year end, the Company entered into two additional natural 
gas swap agreements to hedge a portion of its expected natural gas 
production.  The first hedge agreement is for a term of seven months 
beginning April 1, 1998 for 100,000 MMBtu per month at a fixed price of 
$1.5675 per MMBtu.  The second hedge agreement is for a term of twelve months 
beginning March 1, 1998 for 200,000 MMBtu per month at a fixed price of 
$1.855 per MMBtu.

     During the year ended December 31, 1997, revenues from trading 
activities, which included the cost of gas purchased or sold for trading 
purposes, were $15,999,000 representing 41% of the Company's consolidated 
revenues.  Trading revenues increased 60% over 1996 trading revenues of 
$10,001,000.  The increased trading revenues were attributable to purchasing 
larger volumes of natural gas at fixed or indexed prices, for resale at 
slightly higher fixed or indexed prices, realizing a known margin.  During 
1997, sales to KN Gas Marketing, Inc. accounted for 21%, and Colorado Power 
Partnership 10% of the Company's total consolidated revenues.   As previously 
mentioned, the Colorado Power Partnership contract has been terminated with 
monetary consideration paid to Prima.  The sales to KN Gas Marketing, Inc. 
were for a term of one year which expired and were not renewed.

                                       13
<PAGE>

OILFIELD SERVICES

     The Company's oilfield service business is conducted under the name of 
Action Oilfield Services, Inc. ("Action"), a wholly owned subsidiary.  Action 
owns seven completion rigs, a swab rig, and various trucking, water hauling 
and oilfield rental equipment including pumps, tanks, workstrings and 
blow-out preventors.  Action's activities are currently concentrated in the 
Wattenberg Area.  Action provides these services on wells owned and operated 
by Prima and for third parties.  During 1997, 22% of Action's revenues were 
from activities performed on wells owned by Prima.  The Company's share of 
fees paid to Action on Company owned properties and the costs associated with 
providing these services are eliminated in the consolidated financial 
statements.  Although drilling activity in the Wattenberg Area has stabilized 
at levels lower than those experienced in 1993 and 1994, an increased level 
of well re-works and recompletions has resulted in strong utilization of 
equipment.  Action purchased the assets of Centennial Well Service in June 
1997, which added two more working completion rigs to its fleet, bringing the 
total to six.  Centennial brought experienced employees with a good work 
reputation, which further augmented Action's capacity utilization in the 
Wattenberg Area.  Late in the year, Action refurbished its stacked rig, and 
put it into service in January 1998, bringing the rig count to seven.  
Revenues recorded by Action from third parties during the year ended December 
31, 1997 were $3,214,000 or 8% of consolidated revenues.

MANAGEMENT AND OPERATOR SERVICES

     The Company provides management and operator services for approximately 
372 wells which the Company operates pursuant to industry standard operating 
agreements with other working interest owners in the wells.  The Company also 
serves as managing venturer and operator of Bonny Gathering Company, a joint 
venture formed to construct and operate a natural gas gathering and pipeline 
facility in the Bonny Field in eastern Colorado.  Revenues attributable to 
management and operator services provided to third parties were $1,035,000 
for the year ended December 31, 1997, which was 3% of consolidated revenues.

PHYSICAL PROPERTIES

     The Company owns 160 acres of land in Weld County, Colorado near 
LaSalle, Colorado.  A shop, office building and yard facilities located on 
the land are used for the Company's field and oilfield service operations.  
Net book value of the land and buildings at December 31, 1997 was $186,000. 
The service company and field operations own related equipment, including 
completion rigs, a swab rig, water trucks, a dozer, a grader, rental 
equipment and various oil field vehicles with a net book value of $1,727,000 
at December 31, 1997.

     The Company owns a 15.5% interest in Bonny Gathering Company, a joint 
venture which owns a gas gathering and pipeline system located in Yuma 
County, Colorado.  The book value of this partnership interest was $227,000 
at December 31, 1997.  The facility consists of over 80 miles of gas 
gathering lines, 26 miles of main trunk line, an office and shop building, 
and related compression and dehydration facilities.      

     The Company is a 6% limited partner in a real estate limited partnership 
which currently owns approximately 22 acres of undeveloped land in Phoenix, 
Arizona for investment and capital appreciation.  The partnership owns the 22 
acres free and clear.  The book value of this partnership interest is 
$257,000 at December 31, 1997.

     The Company leases its Denver office space at an annual rate of $130,000 
per year.  Such offices consist of 11,717 square feet and the lease continues 
until November 30, 2000.  The Company owns office furniture and equipment 
with a net book value at December 31, 1997 of $198,000.

                                       14
<PAGE>

EMPLOYEES AND OFFICES

     As of December 31, 1997, the Company had 76 full-time employees, 
including 19 in its Denver office and 57 field employees.  Action Oilfield 
Services employed 42 of the field employees and 15 were employed in Prima's 
field production, pumping and gas gathering activities.  The Company believes 
its relations with its employees are good. The Company's principal executive 
offices are located at 1801 Broadway, Suite 500, Denver, Colorado  80202.

ITEM 3.   LEGAL PROCEEDINGS

     The Company is engaged from time to time in legal proceedings in the 
normal course of its daily business.  At December 31, 1997, Prima is not a 
party to any legal proceedings which it believes would have a material impact 
on the Company.

ITEM 4.   SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     No matters were submitted to a vote of the Company's security holders 
during the fourth quarter of the fiscal year ended December 31, 1997.

                               -------------

         CAUTIONARY STATEMENT FOR THE PURPOSES OF THE "SAFE HARBOR"
    PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

     Prima is including the following cautionary statement to take advantage 
of the "safe harbor" provisions of the Private Securities Litigation Reform 
Act of 1995 for any forward-looking statement made by, or on behalf of, the 
Company.  The factors identified in this cautionary statement are important 
factors (but not necessarily all of the important factors) that could cause 
actual results to differ materially from those expressed in any 
forward-looking statement made by, or on behalf of, the Company.  Where any 
such forward-looking statement includes a statement of the assumptions or 
bases underlying such forward-looking statement, the Company cautions that, 
while it believes such assumptions or bases to be reasonable and makes them 
in good faith, assumed facts or bases almost always vary from actual results, 
and the differences between assumed facts or bases and actual results can be 
material, depending upon the circumstances.  Where, in any forward-looking 
statement, the Company, or its management, expresses an expectation or belief 
as to the future results, such expectation or belief is expressed in good 
faith and believed to have a reasonable basis, but there can be no assurance 
that the statement of expectation or belief will result, or be achieved or 
accomplished.  The Company does not undertake to update, revise or correct 
any of the forward-looking information.  Taking into account the foregoing, 
the following are identified as important risk factors that could cause 
actual results to differ materially from those expressed in any 
forward-looking statement made by, or on behalf of, the Company:

     VOLATILITY OF OIL AND NATURAL GAS PRICES.  Historically, oil and natural 
gas prices have been volatile and are likely to continue to be volatile.  
Prices are affected by, among other things, market supply and demand factors, 
market uncertainty, and actions of the United States and foreign governments 
and international cartels.  These factors are beyond the control of the 
Company.  To the extent that oil and gas prices decline, the Company's 
revenues, cash flows, earnings and operations would be adversely impacted.  
The Company is unable to accurately predict future oil and natural gas prices.

                                       15
<PAGE>

     UNCERTAINTY OF OIL AND NATURAL GAS RESERVE ESTIMATES.  Estimates of the 
Company's proved reserves and future net revenues are based on engineering 
reports prepared by independent engineers.  These estimates are based on 
several assumptions that the Securities and Exchange Commission requires oil 
and natural gas companies to use, including for example, constant oil and 
natural gas prices.  Such estimates are inherently imprecise indications of 
future net revenues.  Actual future production, revenues, taxes, production 
costs and development costs may vary substantially from those assumed in the 
estimates. Any significant variance could materially affect the estimates.  
In addition, the Company's reserves might be subject to upward or downward 
adjustment based on future production, results of future exploration and 
development, prevailing oil and natural gas prices and other factors.

     RISKS OF OIL AND NATURAL GAS EXPLORATION, DEVELOPMENT AND PRODUCTION. 
The search for oil and natural gas often results in unprofitable efforts, not 
only from dry holes, but also from wells which, though productive, do not 
produce oil or natural gas in sufficient quantities to return a profit on the 
costs incurred.  No assurance can be given that any oil or natural gas 
reserves located by the Company in the future will be commercially 
productive.  In addition, the cost of drilling, completing and operating 
wells is often uncertain, and drilling may be delayed or cancelled as a 
result of many factors, including unacceptably low oil and natural gas 
prices, availability of drilling rigs, oil and natural gas property title 
problems, inclement weather conditions and financial instability of well 
operators and working interest owners. Furthermore, the availability of a 
ready market for the Company's oil and natural gas depends on numerous 
factors beyond its control, including demand for and supply of oil and 
natural gas, general economic conditions, proximity of natural gas reserves 
to pipelines, weather conditions and government regulation.

     NEED TO REPLACE RESERVES.   As is customary in the oil and gas 
exploration and production industry, the Company's future success depends 
upon its ability to continue to find, develop or acquire additional oil and 
gas reserves that are economically recoverable.  Unless the Company replaces 
the reserves that it produces through successful development, exploration or 
acquisition, the Company's proved reserves will decline.  Further, 
approximately 77% of the Company's proved reserves at December 31, 1997, were 
located in the Wattenberg Area of the Denver-Julesburg Basin, where wells are 
characterized by relatively rapid decline rates.  Additionally, approximately 
26% of the Company's total proved reserves at December 31, 1997, were 
undeveloped.  Recovery of such reserves will require significant capital 
expenditures and successful drilling operations.  There can be no assurance 
that the Company will continue to be successful in its effort to develop or 
replace its proved reserves.

     HEDGING ACTIVITIES.   Part of the Company's business strategy is to 
periodically use both commodity futures contracts and price swaps to hedge 
the impact of the volatility of oil and natural gas prices on a portion of 
its production and gas marketing activities.  In certain circumstances, 
significant reductions in production, due to unforeseen events, could require 
the Company to make payments under the hedge agreements even though such 
payments are not offset by production.  To reduce this risk, the Company 
strives to keep a percentage of its production unhedged.  Hedging will also 
prevent the Company from receiving the full advantage of increases in oil or 
natural gas prices above the amount specified in the hedge agreement.  Based 
upon average daily production during 1997, the Company's hedge agreements 
covered approximately 29% and 37% of the Company's daily average oil and 
natural gas production, respectively.

     COMPETITION.   The Company competes with numerous other companies and 
individuals, including many that have significantly greater resources, in 
virtually all facets of its business.  Such competitors may be able to pay 
more for desirable leases and to evaluate, bid for and purchase a greater 
number of properties than the financial or personnel resources of the Company 
permit.  The ability of the Company to increase reserves in the future will 
be dependent on its ability to select and acquire suitable producing 
properties and prospects for future exploration and development.  The 
availability of a market for oil and 

                                       16
<PAGE>

natural gas production depends upon numerous factors beyond the control of 
producers, including but not limited to the availability of other domestic or 
imported production, the locations and capacity of pipelines, and the effect 
of federal and state regulation on such production.  Domestic oil and natural 
gas must compete with imported oil and natural gas, coal, atomic energy, 
hydroelectric power and other forms of energy.

     OPERATING HAZARDS AND UNINSURED RISKS.  The oil and gas business 
involves a variety of operating risks, including the risk of fire, explosions 
and blow-outs, as well as risks associated with production, marketing and 
general economic conditions.  The Company maintains insurance against some, 
but not all, of these risks, any of which could result in substantial losses 
to the Company. There can be no assurance that any insurance would be 
adequate to cover any losses or exposure to liability or whether insurance 
will continue to be available at premium levels that justify its purchase or 
whether it will be available at all.

     GOVERNMENT REGULATION.  All aspects of the oil and gas industry are 
extensively regulated by federal, state and local governments in all areas in 
which the Company has operations.  Regulations govern such things as drilling 
permits, environmental protection and pollution control, spacing of wells, 
the unitization and pooling of properties, reports concerning operations, 
royalty rates and various other matters including taxation.  Oil and gas 
industry legislation and administrative regulations are periodically changed 
for a variety of political, economic and other reasons.  These regulations 
may substantially increase the cost of doing business and sometimes prevent 
or delay the commencement or continuance of any given exploration or 
development project and may adversely affect the economics of capital 
projects.  At the present time it is impossible to predict what effect 
current and future proposals or changes in existing laws or regulations will 
have on operations, estimates of oil and natural gas reserves, or future 
revenues.  The costs of complying, monitoring compliance and dealing with the 
agencies that administer these regulations can be significant.


                                       17
<PAGE>

                                    PART II

ITEM 5.  MARKET FOR THE REGISTRANT'S COMMON STOCK AND RELATED
         STOCKHOLDER MATTERS

     (a)  PRINCIPAL MARKET OR MARKETS.  Prima's common stock trades on the 
Nasdaq National Market tier of the Nasdaq Stock Market under the symbol 
"PENG."  The following table sets forth the Nasdaq high and low sales prices 
for Prima's common stock for each quarterly period during the Company's years 
ended December 31, 1997 and 1996.  These prices have been restated to reflect 
the effect of the three for two split of Prima's common stock on March 4, 
1997.

<TABLE>
        Year Ended December 31, 1997                 HIGH        LOW
        ----------------------------               -------     -------
<S>                                                <C>         <C>
 Quarter Ended March 31, 1997................      $18.000     $13.000
 Quarter Ended June 30, 1997.................       17.625      13.000
 Quarter Ended September 30, 1997............       24.750      15.625
 Quarter Ended December 31, 1997.............       25.500      17.000


        Year Ended December 31, 1996
        ----------------------------

 Quarter Ended March 31, 1996................      $ 9.333     $ 7.500
 Quarter Ended June 30, 1996.................       10.833       7.667
 Quarter Ended September 30, 1996............       11.667       9.750
 Quarter Ended December 31, 1996.............       18.500      11.167
</TABLE>

     On March 13, 1998 the closing sale price for the Company's common stock 
was $19.1875 per share.

     The above quotations are from sources believed to be reliable.  They do 
not include any retail mark-ups, mark-downs or commissions and may not 
represent actual transactions.

     (b)  APPROXIMATE NUMBER OF HOLDERS OF COMMON STOCK.  The number of 
holders of record of Prima's common stock at March 13, 1998 was 1,198.

     (c)  DIVIDENDS.  Holders of common stock are entitled to receive such 
dividends as may be declared by Prima's Board of Directors.  The Board 
declared a special dividend of $0.17 (restated) per common share payable to 
stockholders of record as of the close of business August 26, 1996.  The 
dividend was paid August 30, 1996.  No dividends were declared or paid in 
1997.  Future dividends, if any, will be evaluated based among other things, 
on operating results and financial condition of the Company at the time.

                                     18
<PAGE>

ITEM 6.  SELECTED FINANCIAL DATA

     The following table sets forth a summary of selected consolidated 
financial data. This data should be read in conjunction with Management's 
Discussion and Analysis of Financial Condition and Results of Operations and 
the Consolidated Financial Statements and notes thereto.

<TABLE>
                                                           Year Ended December 31,
                                          --------------------------------------------------------
                                            1997         1996       1995        1994        1993
                                          --------    --------    --------    --------    --------
                                                    (in thousands, except per share data)
<S>                                       <C>         <C>         <C>         <C>         <C>
Income Statement Data:
Revenues:
 Oil and gas sales.....................   $ 17,840    $ 14,657    $ 11,502    $ 11,558    $ 11,107
 Trading revenues......................     15,999      10,001       4,604       3,790       2,143
 Oilfield services.....................      3,214       2,269       1,487       2,102       1,744
 Management and operator fees..........      1,035       1,003       1,084       1,014       1,063
 Interest and dividend income..........        546         411         154         143         196
 Other.................................        216         280         217       1,477         211
                                          --------    --------    --------    --------    --------
                                            38,850      28,621      19,048      20,084      16,464
                                          --------    --------    --------    --------    --------
Expenses:
 Depreciation, depletion
  and amortization.....................      5,432       4,544       4,372       4,313       3,869
 Lease operating expense...............      1,720       1,511       1,432       1,512       1,336
 Ad valorem and production taxes.......      1,355         981         736         863         999
 Cost of trading.......................     15,323       9,060       3,613       3,334       1,849
 Cost of oilfield services.............      2,368       1,759       1,170       1,334       1,112
 General and administrative............      1,915       1,812       1,863       1,925       1,958
                                          --------    --------    --------    --------    --------
                                            28,113      19,667      13,186      13,281      11,123
                                          --------    --------    --------    --------    --------
Income before income taxes.............     10,737       8,954       5,862       6,803       5,341
Provision for income taxes.............      2,635       2,285       1,370       1,572       1,090
                                          --------    --------    --------    --------    --------

Net Income.............................   $  8,102    $  6,669    $  4,492    $  5,231    $  4,251
                                          --------    --------    --------    --------    --------
                                          --------    --------    --------    --------    --------
Basic Net Income per Share (1).........   $   1.40    $   1.15    $   0.77    $   0.90    $   0.73
                                          --------    --------    --------    --------    --------
                                          --------    --------    --------    --------    --------
Diluted Net Income per Share (1).......   $   1.37    $   1.14    $   0.77    $   0.90    $   0.73
                                          --------    --------    --------    --------    --------
                                          --------    --------    --------    --------    --------
Cash Dividends per Share...............   $   0.00    $   0.17    $   0.00    $   0.00    $   0.00
                                          --------    --------    --------    --------    --------
                                          --------    --------    --------    --------    --------
Balance Sheet Data
    (at end of period):
Total assets...........................   $ 57,921    $ 48,006    $  38,565   $ 35,716    $ 29,477
Net property and equipment.............     43,181      32,325       29,118     28,177      21,428
Long-term debt.........................        240           0            0      1,000       1,300
Stockholders' equity...................     43,214      35,273       29,916     25,353      20,270
Working capital........................      7,531       7,863        4,292        848       2,003
</TABLE>

  (1)     Per share data has been restated to give effect to the adoption of
          SFAS 128 in the fourth quarter of 1997.  See "Earnings per Share"
          subheading of Note 1 of the Notes to Consolidated Financial Statements
          for discussion of SFAS 128.

                                      19
<PAGE>

ITEM 7.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
         AND RESULTS OF OPERATIONS

     This Item 7 contains "forward-looking statements" and are made pursuant 
to the "safe harbor" provisions of the Private Securities Litigation Reform 
Act of 1995.  These statements include, without limitation, statements 
relating to liquidity, financing of operations, continued volatility of oil 
and natural gas prices and estimates of future net cash flows attributable to 
proved reserves and other such matters.  The words "believes," "expects" or 
"estimates" and similar expressions identify forward-looking statements.  
Prima does not undertake to update, revise or correct any of the 
forward-looking information. Readers are cautioned that such forward-looking 
statements should be read in connection with Prima's disclosures under the 
heading: "Cautionary Statement for the Purposes of the 'Safe Harbor' 
Provisions of the Private Securities Litigation Reform Act of 1995" beginning 
on page 15.

     The following discussion is intended to assist in understanding the 
Company's financial position and results of operations for each year in the 
three year period ended December 31, 1997.  The Consolidated Financial 
Statements and notes thereto should be referred to in conjunction with this 
discussion.

LIQUIDITY AND CAPITAL RESOURCES

     The Company's principal internal sources of liquidity are cash flows 
generated from operations and existing cash and cash equivalents.  Net cash 
provided by operating activities totaled $14,589,000 for the year ended 
December 31, 1997, compared to $12,157,000 for the year ended December 31, 
1996 and $8,906,000 for the year ended December 31, 1995.  Net working 
capital at December 31, 1997 was $7,531,000 as compared to $7,863,000 at 
December 31, 1996. Current assets were $13,835,000 at December 31, 1997 
compared to $15,011,000 at December 31, 1996.  Current liabilities were 
$6,304,000 at December 31, 1997 compared to $7,148,000 at December 31, 1996. 
The Company had proceeds from the sales of oil and gas properties and other 
equipment and sales of securities of $405,000 in 1997.

     The Company has external borrowing capacity of $8,000,000 through an 
unsecured line of credit with a commercial bank, all of which is available to 
be drawn.

     The Company invested $15,250,000 in additions to oil and gas properties 
during the year ended December 31, 1997, compared to $7,942,000 during the 
year ended December 31, 1996 and $5,182,000 during the year ended December 
31, 1995. During 1997, $12,565,000 was paid for the Company's share of 
development well costs and recompletions, $1,228,000 for exploratory costs, 
$1,427,000 for acquisitions of unproved properties and $30,000 for purchases 
of proved properties.  Other uses of funds in 1997 included $1,291,000 for 
purchases of oilfield service equipment and facilities and office equipment, 
$358,000 for purchases of marketable securities and $404,000 for treasury 
stock purchases.

     The standardized measure of discounted future net cash flows of the 
Company's proved oil and natural gas reserves decreased to $58,149,000 at 
December 31, 1997 as compared to $68,965,000 at December 31, 1996 and 
$39,180,000 at December 31, 1995.  Estimated future net cash flows from 
proved oil and natural gas reserves decreased to $136,391,000 at December 31, 
1997 compared to $176,437,000 at December 31, 1996 and $85,028,000 at 
December 31, 1995.  Oil reserve volumes at December 31, 1997 increased 11% 
and natural gas reserve volumes increased 22% compared to December 31, 1996.  
The weighted average natural gas price received at December 31, 1997 on 
Company production was $2.40 per Mcf, a decrease of $1.37 per Mcf compared to 
December 31, 1996. The year end weighted average oil price was $17.08 per 
barrel, a decrease of $7.63 per barrel compared to December 31, 1996.

                                      20
<PAGE>

     At  December 31, 1997, the Company estimates that capital expenditures 
of $22,095,000 will be required to develop the Company's proved undeveloped 
and proved developed non-producing reserves over the next several years. 
Approximately $13,166,000, net of future development costs, of the estimated 
future net cash flows of the Company's proved oil and gas reserves at 
December 31, 1997 were proved undeveloped reserves.

     The Board of Directors of Prima approved a three for two stock split of 
the Company's common stock, to shareholders of record on February 20, 1997, 
distributed March 4, 1997.  As a result, the number of shares of common stock 
outstanding increased from 3,860,396 to 5,790,556 on the distribution date.  
All share and per share amounts included in this report on Form 10-K have 
been restated to show the retroactive effects of the stock split.

     The Company regularly reviews opportunities for acquisition of assets or 
companies related to the oil and gas industry which could expand or enhance 
its existing business.  The Company expects its operations, including 
acquisitions and drilling prospects, will be financed by funds provided from 
operations, working capital, various cost-sharing arrangements, borrowings 
under its line of credit or from other financing alternatives.

     Historically, oil and natural gas prices have been volatile and are 
likely to continue to be volatile.  Prices are affected by, among other 
things, market supply and demand factors, market uncertainty, and actions of 
the United States and foreign governments and international cartels.  These 
factors are beyond the control of the Company.  To the extent that oil and 
gas prices decline, the Company's revenues, cash flows, earnings and 
operations would be adversely impacted.  The Company is unable to accurately 
predict future oil and natural gas prices.

YEAR 2000 ISSUE

     The Year 2000 Issue is the result of computer applications being written 
using two digits rather than four to define the applicable year.  As the year 
2000 approaches, such applications may be unable to accurately process 
certain data-based information.  The Company has identified all significant 
programs that will require modification to ensure Year 2000 compliance.  
Internal and external resources are being used to make the required 
modifications and test compliance.  Modification and compliance should be 
completed by December 31, 1998.  The cost of Year 2000 compliance has not 
been and is not anticipated to be material to the Company's financial 
position or results of operations in any given year.  In addition, an 
assessment of the readiness of external companies with whom the Company does 
business, such as customers and vendors, is ongoing.

NEW ACCOUNTING PRONOUNCEMENTS

      In June 1997, the Financial Accounting Standards Board issued Statement 
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" 
("SFAS 130").  SFAS 130 establishes standards for reporting and display of 
comprehensive income and its components (revenues, expenses, gains and 
losses) in a full set of general purpose financial statements.  SFAS 130 
requires that all items that are required to be recognized under accounting 
standards as components of comprehensive income be reported in a financial 
statement that is displayed with the same prominence as other financial 
statements. Reclassification is required for financial statements from 
earlier periods provided for comparative purposes. Prima is required to adopt 
SFAS 130 in January 1998.  Prima has not completed the process of evaluating 
the impact that will result from adopting SFAS 130 or the manner that will be 
used to disclose the required information in its financial statements.

                                      21
<PAGE>

     In June 1997, the Financial Accounting Standards Board issued Statement 
of Financial Accounting Standards No. 131, "Disclosures about Segments of an 
Enterprise and Related Information" ("SFAS 131").  SFAS 131 supersedes FASB 
Statement No. 14, "Financial Reporting for Segments of a Business 
Enterprise." SFAS 131 establishes standards for the way that public business 
enterprises report information about operating segments in annual financial 
statements and requires that those enterprises report selected information 
about operating segments in interim financial reports issued to shareholders. 
It also establishes standards for related disclosures about products and 
services, geographic areas, and major customers.  SFAS 131 requires that a 
public business enterprise report financial and descriptive information about 
its reportable operating segments.  Operating segments are components of an 
enterprise about which separate financial information is available that is 
evaluated regularly by the chief operating decision maker in deciding how to 
allocate resources and in assessing performance.  Generally, financial 
information is required to be reported on the basis that it is used 
internally for evaluating segment performance and deciding how to allocate 
resources to segments.  The Company is required to adopt SFAS 131 in 1998 and 
comparative information for earlier years is required to be restated.  The 
Company has not completed the process of evaluating the impact that will 
result from adopting SFAS 131 or the manner that will be used to disclose the 
required information in its financial statements.

RESULTS OF OPERATIONS

1997 VS 1996

     For the year ended December 31, 1997, the Company earned net income of 
$8,102,000, or $1.37 per diluted share, on revenues of $38,850,000, compared 
to net income of $6,669,000, or $1.14 per diluted share, on revenues of 
$28,621,000 for the year ended December 31, 1996.  Operating expenses were 
$28,113,000 for 1997 compared to $19,667,000 for 1996.  Revenues increased 
$10,229,000 or 36%, expenses increased $8,446,000 or 43% and net income 
increased $1,433,000 or 21% in 1997.

     Oil and gas sales for the year ended December 31, 1997 were $17,840,000 
compared to $14,657,000 for the year ended December 31, 1996, an increase of 
$3,183,000 or 22%.  This increase was due primarily to increased production 
of both oil and natural gas and to increased natural gas prices.  The 
Company's net natural gas production was 5.34 Bcf for 1997 compared to 4.65 
Bcf in 1996, an increase of .69 Bcf or 15%.  Its net oil production was 
255,000 barrels compared to 233,000 barrels for the same periods, an increase 
of 22,000 barrels or 9%. On a BOE basis, the Company's production for 1997 
increased 139,000 BOE or 14%. The average price received per Mcf of natural 
gas sold was $2.39 for the year ended December 31, 1997 compared to $2.11 per 
Mcf for the year ended December 31, 1996, an increase of $.28 per Mcf or 13%. 
Approximately 5.2% and 5.5% of the natural gas production for the years 
ended December 31, 1997 and 1996, respectively, was attributable to 
production sold under a fixed contract price of $5.90 per MMBtu.  The average 
price for the Company's natural gas production exclusive of the fixed price 
contract gas was $2.20 per Mcf for the year ended December 31, 1997 and $1.89 
per Mcf for the year ended December 31, 1996.  The average price received per 
barrel of oil sold was $19.90 for 1997 compared to $20.84 for 1996, a 
decrease of $0.94 per barrel or 5%.  During the year ended December 31, 1997, 
the Company hedged approximately 29% of its oil production and 37% of its 
natural gas production.  The purpose of these hedges is to provide market 
price protection in the volatile environment of oil and natural gas spot 
pricing.  Hedging gains of $140,000 are included in oil and gas revenues for 
the year, which increased the average price received per barrel of oil by 
$0.50 and had no material effect on the price received per Mcf of natural 
gas.  During the year ended December 31, 1996, the Company hedged 
approximately 25% of its oil production.  Hedging losses of $116,000 reduced 
the price received per barrel of oil by $0.50.  No natural gas production was 
hedged in 1996.

                                      22
<PAGE>

     Depreciation, depletion and amortization ("DD&A") rates are affected by 
production levels and changes in reserve estimates.  Total DD&A expense was 
$5,432,000 in 1997 compared to $4,544,000 for 1996, an increase of $888,000 
or 20%.  The Company's depletion of oil and gas properties was $4,935,000 or 
$4.31 per BOE on 1,146,000 equivalent barrels produced in 1997, compared to 
$4,210,000 or $4.18 per BOE on 1,007,000 equivalent barrels produced in 1996. 
Included in DD&A expense for 1997 and 1996 is $497,000 and $334,000, 
respectively, attributable to depreciation of service equipment, furniture 
and equipment and buildings.  Depreciation expense increased $163,000, or 
49%, due primarily to acquisitions of oilfield service equipment in 1997.

     Lease operating expenses ("LOE") were $1,720,000 for the year ended 
December 31, 1997 compared to $1,511,000 for the year ended December 31, 
1996. Ad valorem and production taxes were $1,355,000 and $981,000 for the 
same periods.  Total lifting costs ( LOE plus ad valorem and production 
taxes) were 17% of oil and gas revenues and $2.68 per equivalent barrel of 
production for 1997 compared to 17% and $2.47 for 1996.  The increased rate 
for 1997 was due to workover expenses and additional production taxes 
resulting from higher product prices.

     Trading revenues and cost of trading represented the marketing of third 
party gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary. 
Trading revenues were $15,999,000 for 1997 compared to $10,001,000 for 1996, 
an increase of $5,998,000 or 60%.  The Company marketed 7,105,000 MMBtu's of 
third party gas in 1997 compared to 5,252,000 MMBtu's in 1996, an increase of 
1,853,000 MMBtu's or 35%.  Costs of trading were $15,323,000 for 1997 
compared to $9,060,000 for 1996, an increase of $6,263,000 or 69%.  Trading 
activities fluctuate with natural gas markets and the Company's ability to 
develop markets that meet the Company's trading criteria.  The increased 
trading revenues and costs for 1997 were attributable to purchasing larger 
volumes of natural gas at fixed or indexed prices, for resale at slightly 
higher fixed or indexed prices, realizing a known margin.

     Oilfield service revenues of $3,214,000 and $2,269,000 for the years 
ended December 31, 1997 and 1996, respectively, represent the revenues earned 
by Action Oilfield Services, Inc., a wholly owned subsidiary.  These revenues 
include well servicing fees from seven completion rigs, a swab rig, trucking, 
water hauling, dozer and roustabout work, rental equipment and other related 
activities.  Revenues increased $945,000, or 42% for 1997.  Cost of oilfield 
services were $2,368,000 for the year ended December 31, 1997 compared to 
$1,759,000 for the year ended December 31, 1996, an increase of $609,000 or 
35%. Utilization levels in the Wattenberg Area, where the service company is 
active, increased above 1996 levels.  The Company also purchased additional 
equipment which contributed to the increase in revenues.  For both the years 
ended December 31, 1997 and 1996, 22% of the gross fees billed by Action were 
for Company owned wells.  The Company's share of fees paid to Action on owned 
wells and the costs associated with providing the services are eliminated in 
consolidation.

     Management and operator fees for the years ended December 31, 1997 and 
1996 were $1,035,000 and $1,003,000, respectively, an increase of $32,000 or 
3%. Management and operator fees are earned pursuant to the Company's roles 
as operator for approximately 372 oil and gas wells located primarily in the 
Wattenberg Area of Weld County, Colorado and as managing venturer of a joint 
venture which owns gas gathering and pipeline facilities in the Bonny Field 
in Yuma County, Colorado.  The Company is a working interest owner in each of 
the operated wells.  The Company is paid operating fees by the other working 
interest owners in the properties. Fees fluctuate with the number of wells 
operated, the percentage working interest in a property owned by third 
parties, and the amount of drilling activity during the period.

                                      23
<PAGE>

     General and administrative expense ("G&A") totaled $1,915,000 for the 
year ended December 31, 1997 compared to $1,812,000 for the year ended 
December 31, 1996.  G&A costs increased by $103,000 or 6%.  The Company's G&A 
expense has increased due to expansion of the Company's area of operations.

     The provision for income taxes was $2,635,000 for the year ended 
December 31, 1997 compared to $2,285,000 for the year ended December 31, 
1996.  The effective tax rate was 24.5% in 1997 compared to 25.5% in 1996. 
Effective tax rates are affected by amounts of permanent differences between 
financial and taxable income, consisting primarily of statutory depletion 
deductions and Section 29 tax credits.

1996 VS 1995

     For the year ended December 31, 1996, the Company earned net income of 
$6,669,000, or $1.14 per diluted share, on revenues of $28,621,000, compared 
to net income of $4,492,000, or $0.77 per diluted share, on revenues of 
$19,048,000 for the year ended December 31, 1995.  Operating expenses were 
$19,667,000 for the 1996 year compared to $13,186,000 for 1995.  Revenues 
increased $9,573,000 or 50%, expenses increased $6,481,000 or 49% and net 
income increased $2,177,000 or 49% in 1996.

     Oil and gas sales for the year ended December 31, 1996 were $14,657,000 
compared to $11,502,000 for the year ended December 31, 1995, an increase of 
$3,155,000 or 27%.  This increase was due primarily to increased product 
prices for both oil and natural gas.  The Company's net natural gas 
production was 4.65 Bcf for 1996 compared to 4.30 Bcf in 1995, an increase of 
 .35 Bcf or 8%.  Its net oil production was 233,000 barrels compared to 
266,000 barrels for the same periods, a decrease of 33,000 barrels or 12%.  
On a BOE basis, the Company's production for 1996 increased 24,000 BOE or 2%. 
 The average price received per Mcf of natural gas sold was $2.11 for the 
year ended December 31, 1996 compared to $1.61 per Mcf for the year ended 
December 31, 1995, an increase of $.50 per Mcf or 31%.  Approximately 5.5% 
and 4.3% of the natural gas production for the years ended December 31, 1996 
and 1995, respectively, was attributable to production sold under a fixed 
contract price of $5.90 per MMBtu.  The average price for the Company's 
natural gas production exclusive of the fixed price contract gas was $1.89 
per Mcf for the year ended December 31, 1996 and $1.43 per Mcf for the year 
ended December 31, 1995.  The average price received per barrel of oil sold 
was $20.84 for 1996 compared to $17.19 for 1995, an increase of $3.66 per 
barrel or 21%.  During the year ended December 31, 1996, the Company hedged 
approximately 25% of its oil production.  Hedging losses of $116,000 reduced 
the price received per barrel of oil by $0.50.  No natural gas production was 
hedged in 1996.  During the year ended December 31, 1995, the Company hedged 
approximately 11% of its oil production and 34% of its natural gas 
production.  Hedging gains of $80,000 are included in oil and gas revenues 
for the year, which increased the average price received per barrel of oil by 
$0.09 and the average price received per Mcf of natural gas by $0.01.

     DD&A expense was $4,544,000 in 1996 compared to $4,372,000 for 1995, an 
increase of $172,000 or 4%.  The Company's depletion of oil and gas 
properties was $4,210,000 or $4.18 per BOE on 1,007,000 equivalent barrels 
produced in 1996, compared to $4,058,000 or $4.13 per BOE on 983,000 
equivalent barrels produced in 1995.  Included in DD&A expense for 1996 and 
1995 is $334,000 and $314,000,  respectively, attributable to depreciation of 
service equipment, furniture and equipment and buildings.

     LOE was $1,511,000 for the year ended December 31, 1996 compared to 
$1,432,000 for the year ended December 31, 1995.  Ad valorem and production 
taxes were $981,000 and $736,000 for the same periods.  Total lifting costs 
were 17% of oil and gas revenues and $2.47 per equivalent barrel of 
production for 1996 compared to 19% and $2.21 for 1995.

                                      24
<PAGE>

     Trading revenues were $10,001,000 for 1996 compared to $4,604,000 for 
1995, an increase of $5,397,000 or 117%.  The Company marketed 5,252,000 
MMBtu's of third party gas in 1996 compared to 2,295,000 MMBtu's in 1995.  
Costs of trading were $9,060,000 for 1996 compared to $3,613,000 for 1995, an 
increase of $5,447,000 or 151%.

     Oilfield service revenues were $2,269,000 for the year ended December 
31, 1996 compared to $1,487,000 for the year ended December 31, 1995.  Fees 
increased by $782,000 or 53%.  Cost of oilfield services were $1,759,000 for 
the year ended December 31, 1996 compared to $1,170,000 for the year ended 
December 31, 1995.  Costs increased by $589,000 or 50%.  Activity in the 
Wattenberg Area where the service company is active had declined 
significantly in 1995 due to low natural gas prices.  In 1996, Wattenberg 
Area activity improved due to higher oil and natural gas prices, application 
of new drilling technologies, and an increased level of well reworks and 
recompletions.  For the years ended December 31, 1996 and 1995, 22% and 25% 
of the gross fees billed by Action were for Company owned wells.  The 
services performed for the Company increased in 1996 because the Company 
drilled more Wattenberg wells than in 1995, but the percentage is lower due 
to increased business with third party operators.

     Management and operator fees for the years ended December 31, 1996 and 
1995 were $1,003,000 and $1,084,000, respectively, a decrease of $81,000 or 
8%.  Fees decreased in 1996 due to reduced third party ownership in operated 
wells.

     G&A totaled $1,812,000 for the year ended December 31, 1996 compared to 
$1,863,000 for the year ended December 31, 1995, a decrease of $51,000 or 3%. 
The Company's G&A expense was relatively consistent from 1995 to 1996 because 
personnel levels and facility costs had not materially changed.

     The provision for income taxes was $2,285,000 for the year ended 
December 31, 1996 compared to $1,370,000 for the year ended December 31, 
1995.  The effective tax rate was 25.5% in 1996 compared to 23.4% in 1995.

ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The Consolidated Financial Statements that constitute Item 8 are 
attached at the end of this Annual Report on Form 10-K.  An index to these 
Consolidated Financial Statements is also included in Item 14(a) of this 
Annual Report on Form 10-K.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON           
ACCOUNTING AND FINANCIAL DISCLOSURE

     Since the Company's inception, there has not been any Form 8-K filed 
under the Securities Exchange Act of 1934 reporting a change in accountants 
in which there was a reported disagreement on any matter of accounting 
principles or practices or financial statement disclosure.


                                      25
<PAGE>

                                    PART III


ITEM 10.       DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

ITEM 11.       EXECUTIVE COMPENSATION

ITEM 12.       SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

ITEM 13.       CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12, and 13 are
omitted because the Company will file a definitive proxy statement pursuant to
Regulation 14A under the Securities Exchange Act of 1934 not later than 120 days
after the close of the fiscal year.  The information required by such Items will
be included in the definitive proxy statement to be so filed for the Company's
annual meeting of stockholders scheduled for May 13, 1998 and is hereby
incorporated by reference.






                                      26
<PAGE>

                                    PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a)  (1)   FINANCIAL STATEMENTS

                   INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
                                                                 PAGE
<S>                                                              <C>
Independent Auditors' Report..................................     28
Consolidated Balance Sheets at December 31, 1997 and 1996.....     29
Consolidated Statements of Income for the years ended
     December 31, 1997, 1996 and 1995.........................     31
Consolidated Statements of Stockholders' Equity for the years 
     ended December 31, 1997, 1996 and 1995...................     32
Consolidated Statements of Cash Flows for the years ended
     December 31, 1997, 1996 and 1995.........................     33
Notes to Consolidated Financial Statements for the years 
     ended December 31, 1997, 1996 and 1995...................     34
</TABLE>

     (a) (2)  FINANCIAL STATEMENT SCHEDULES

     Financial statement schedules have been omitted because they are not
applicable or the information required therein is included elsewhere in the
financial statements or notes thereto.

     (a) (3)  EXHIBITS

     The following Exhibits are filed herewith pursuant to Rule 601 of the
Regulation S-K or are incorporated by reference to previous filings.

        EXHIBIT NO.   DOCUMENT

           3.1        Certificate of Amendment of the Certificate of 
                      Incorporation - Prima Energy Corporation
                      (Incorporated by reference as Exhibit 3.1 to 
                      Form 10-Q filed November 14, 1997)
          10.1        Extension of Line of Credit Letter Agreement 
                      (Incorporated by reference as Exhibit 10-97.1
                      to Form 10-Q filed May 13, 1997)
          10.2        Agreement to Terminate CPP Natural Gas Supply Contract
          21          Subsidiaries of the Registrant
          27          Financial Data Schedules


     (b)   REPORTS ON FORM 8-K

     No reports on Form 8-K were filed during the Registrant's fiscal quarter 
ended December 31, 1997.  A Form 8-K was filed January 8, 1998, announcing 
the agreement to terminate the long term natural gas supply contract with 
Colorado Power Partners for $3,850,000.  See Note 9 of the Notes to 
Consolidated Financial Statements for additional discussion of this agreement.

                                       27
<PAGE>

                          INDEPENDENT AUDITORS' REPORT


Prima Energy Corporation:

     We have audited the accompanying consolidated balance sheets of Prima 
Energy Corporation ("Company") and subsidiaries as of December 31, 1997 and 
1996,  and the related consolidated statements of income, stockholders' 
equity, and cash flows for each of the three years in the period ended 
December 31, 1997.  These financial statements are the responsibility of the 
Company's management.  Our responsibility is to express an opinion on these 
financial statements based on our audits.

     We conducted our audits in accordance with generally accepted auditing 
standards.  Those standards require that we plan and perform the audit to 
obtain reasonable assurance about whether the financial statements are free 
of material misstatement.  An audit includes examining, on a test basis, 
evidence supporting the amounts and disclosures in the financial statements.  
An audit also includes assessing the accounting principles used and 
significant estimates made by management, as well as evaluating the overall 
financial statement presentation. We believe that our audits provide a 
reasonable basis for our opinion.

     In our opinion, such consolidated financial statements present fairly, 
in all material respects, the financial position of the Company and 
subsidiaries at December 31, 1997 and 1996, and the results of their 
operations and their cash flows for each of the three years in the period 
ended December 31, 1997 in conformity with generally accepted accounting 
principles.




DELOITTE & TOUCHE LLP

March 13, 1998
Denver, Colorado



                                     28
<PAGE>

                           PRIMA ENERGY CORPORATION

                          CONSOLIDATED BALANCE SHEETS
                           DECEMBER 31, 1997 AND 1996

                                   ASSETS
<TABLE>
                                                          1997           1996
                                                      -----------    -----------
<S>                                                   <C>            <C>
CURRENT ASSETS
Cash and cash equivalents.........................    $ 5,223,000    $ 6,704,000
Available for sale securities, at market..........      1,866,000      1,503,000
Receivables (net of allowance for doubtful
  accounts: 1997, $49,000; 1996, $45,000).........      5,681,000      5,921,000
Tubular goods inventory...........................        882,000        311,000
Other current assets..............................        183,000        572,000
                                                      -----------    -----------

      Total current assets........................     13,835,000     15,011,000
                                                      -----------    -----------

OIL AND GAS PROPERTIES, at cost, accounted
  for using the full cost method..................     67,945,000    52,885,000
Less accumulated depreciation,
  depletion and amortization......................    (26,875,000)   (21,940,000)
                                                      -----------    -----------

      Oil and gas properties - net................     41,070,000    30,945,000
                                                      -----------    -----------

PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment........................      3,504,000      2,387,000
Furniture and equipment...........................        711,000        652,000
Field office, shop and land.......................        356,000        341,000
                                                      -----------    -----------
                                                        4,571,000      3,380,000
Less accumulated depreciation.....................     (2,460,000)   (2,000,000)
                                                      -----------    -----------

      Property and equipment - net................      2,111,000      1,380,000
                                                      -----------    -----------

OTHER ASSETS
Cash, designated...................................       421,000        325,000
Other..............................................       484,000        345,000
                                                      -----------    -----------

      Total other assets..........................        905,000        670,000
                                                      -----------    -----------

                                                      $57,921,000    $48,006,000
                                                      -----------    -----------
                                                      -----------    -----------
</TABLE>
          See accompanying notes to consolidated financial statements.

                                      29
<PAGE>

                           PRIMA ENERGY CORPORATION

                     CONSOLIDATED BALANCE SHEETS (CONT'D.)
                           DECEMBER 31, 1997 AND 1996

                      LIABILITIES AND STOCKHOLDERS' EQUITY

<TABLE>
                                                          1997          1996
                                                      -----------   -----------
<S>                                                   <C>           <C>
CURRENT LIABILITIES
Accounts payable..................................    $ 3,250,000   $ 2,526,000
Amounts payable to oil and gas property owners.....     1,220,000     2,831,000
Ad valorem and production taxes payable............     1,279,000     1,094,000
Accrued and other liabilities......................       421,000       476,000
Current portion of notes payable...................       120,000             0
Deferred income taxes..............................        14,000       221,000
                                                      -----------   -----------

      Total current liabilities...................      6,304,000     7,148,000

NOTES PAYABLE......................................       240,000             0
AD VALOREM TAXES, non-current......................     1,280,000       984,000
DEFERRED INCOME TAXES..............................     6,883,000     4,601,000
                                                      -----------   -----------

      Total liabilities...........................     14,707,000    12,733,000
                                                      -----------   -----------

COMMITMENTS AND CONTINGENCIES  (Note 9)


STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
   authorized; no shares issued or outstanding....              0             0
Common stock, $0.015 par value, 12,000,000
   shares authorized; 5,833,056 and
   5,820,556 shares issued........................         87,000        87,000
Additional paid-in capital........................      4,385,000     4,222,000
Retained earnings.................................     39,485,000    31,383,000
Unrealized gain (loss) on available for sale 
   securities.....................................         44,000       (36,000)
Treasury stock, 63,000 and 30,000 shares at cost..       (787,000)     (383,000)
                                                      -----------   -----------

      Stockholders' equity - net..................     43,214,000    35,273,000
                                                      -----------   -----------

                                                      $57,921,000   $48,006,000
                                                      -----------   -----------
                                                      -----------   -----------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      30
<PAGE>

                            PRIMA ENERGY CORPORATION
                                        
                        CONSOLIDATED STATEMENTS OF INCOME
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
                                        
<TABLE>
                                                1997          1996           1995
                                            -----------    -----------    -----------
<S>                                         <C>            <C>            <C>
REVENUES
Oil and gas sales.......................... $17,840,000    $14,657,000    $11,502,000
Trading revenues...........................  15,999,000     10,001,000      4,604,000
Oilfield services..........................   3,214,000      2,269,000      1,487,000
Management and operator fees...............   1,035,000      1,003,000      1,084,000
Interest and dividend income...............     546,000        411,000        154,000
Other......................................     216,000        280,000        217,000
                                            -----------    -----------    -----------

                                             38,850,000     28,621,000     19,048,000
                                            -----------    -----------    -----------
EXPENSES
Depreciation, depletion and amortization...   5,432,000      4,544,000      4,372,000
Lease operating expense....................   1,720,000      1,511,000      1,432,000
Ad valorem and production taxes............   1,355,000        981,000        736,000
Cost of trading............................  15,323,000      9,060,000      3,613,000
Cost of oilfield services..................   2,368,000      1,759,000      1,170,000
General and administrative.................   1,915,000      1,812,000      1,863,000
                                            -----------    -----------    -----------

                                             28,113,000     19,667,000     13,186,000
                                            -----------    -----------    -----------

INCOME BEFORE INCOME TAXES.................  10,737,000      8,954,000      5,862,000
PROVISION FOR INCOME TAXES.................   2,635,000      2,285,000      1,370,000
                                            -----------    -----------    -----------

NET INCOME................................. $ 8,102,000    $ 6,669,000    $ 4,492,000
                                            -----------    -----------    -----------
                                            -----------    -----------    -----------
BASIC NET INCOME PER SHARE................. $      1.40    $      1.15    $      0.77
                                            -----------    -----------    -----------
                                            -----------    -----------    -----------
DILUTED NET INCOME PER SHARE .............. $      1.37    $      1.14    $      0.77
                                            -----------    -----------    -----------
                                            -----------    -----------    -----------
</TABLE>

         See accompanying notes to consolidated financial statements.

                                      31
<PAGE>

                           PRIMA ENERGY CORPORATION

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995

<TABLE>
                                                    ADDITIONAL               UNREALIZED
                                          COMMON     PAID-IN     RETAINED   GAIN (LOSS) ON   TREASURY
                                          STOCK      CAPITAL     EARNINGS     SECURITIES       STOCK       TOTAL
                                          ------     -------     --------    ------------     -------      -----
<S>                                      <C>       <C>          <C>          <C>            <C>         <C>
BALANCES, January 1, 1995............    $87,000   $4,222,000   $21,192,000   $(148,000)    $       0   $25,353,000
Net income...........................                             4,492,000                               4,492,000
Change in unrealized gain (loss)
  on available for sale securities...                                            71,000                      71,000
                                         -------   ----------   -----------   ---------     ---------   -----------

BALANCES, December 31, 1995..             87,000    4,222,000    25,684,000     (77,000)            0    29,916,000
Net income...........................                             6,669,000                               6,669,000
Dividends paid.......................                              (970,000)                               (970,000)
Change in unrealized gain (loss)
  on available for sale securities...                                            41,000                      41,000
Treasury stock purchased.............                                                        (383,000)     (383,000)
                                         -------   ----------   -----------   ---------     ---------   -----------

BALANCES, December 31, 1996..             87,000    4,222,000    31,383,000     (36,000)     (383,000)   35,273,000
Net income...........................                             8,102,000                               8,102,000
Common stock issued..................          0      111,000                                               111,000
Tax benefit from exercise of non-
  qualified stock options............                  52,000                                                52,000
Change in unrealized gain (loss)
  on available for sale securities...                                            80,000                      80,000
Treasury stock purchased.............                                                        (404,000)     (404,000)
                                         -------   ----------   -----------   ---------     ---------   -----------

BALANCES, December 31, 1997..........    $87,000   $4,385,000   $39,485,000   $  44,000     $(787,000)  $43,214,000
                                         -------   ----------   -----------   ---------     ---------   -----------
                                         -------   ----------   -----------   ---------     ---------   -----------
</TABLE>

          See accompanying notes to consolidated financial statements.

                                      32
<PAGE>
                                       
                            PRIMA ENERGY CORPORATION

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 and 1995

<TABLE>

                                                               1997            1996            1995
                                                           ------------    ------------    ------------
<S>                                                        <C>             <C>             <C>
OPERATING ACTIVITIES
Net income ............................................... $  8,102,000    $  6,669,000    $  4,492,000
Adjustments to reconcile net income to net
  cash provided by operating activities:
    Depreciation, depletion and amortization..............    5,432,000       4,544,000       4,372,000
    Deferred income taxes.................................    2,028,000       1,761,000         889,000
    Other.................................................       83,000          26,000         (34,000)
    Changes in operating assets and liabilities:
      Receivables.........................................      240,000      (2,834,000)        338,000
      Inventory...........................................     (571,000)        (94,000)        261,000
      Other assets........................................       32,000        (342,000)         24,000
      Payables............................................     (702,000)      2,380,000      (1,512,000)
      Accrued and other liabilities.......................      (55,000)         47,000          76,000
                                                           ------------    ------------    ------------
        Net cash provided by operating activities.........   14,589,000      12,157,000       8,906,000
                                                           ------------    ------------    ------------

INVESTING ACTIVITIES
Additions to oil and gas properties.......................  (14,893,000)     (7,942,000)     (5,182,000)
Purchases of other property...............................     (931,000)       (640,000)       (249,000)
Purchases of securities...................................     (358,000)       (744,000)       (181,000)
Proceeds from sales of property...........................      292,000         831,000         125,000
Proceeds from sales of securities.........................      113,000         418,000               0
                                                           ------------    ------------    ------------
        Net cash used by investing activities.............  (15,777,000)     (8,077,000)     (5,487,000)
                                                           ------------    ------------    ------------

FINANCING ACTIVITIES
Treasury stock purchased..................................     (404,000)       (383,000)              0
Proceeds from issuance of common stock....................      111,000               0               0
Dividends paid............................................            0        (970,000)              0
Payments on line of credit................................            0               0      (1,000,000)
                                                           ------------    ------------    ------------
        Net cash used by financing activities.............     (293,000)     (1,353,000)     (1,000,000)
                                                           ------------    ------------    ------------

Increase (Decrease) in Cash and Cash Equivalents..........   (1,481,000)      2,727,000       2,419,000
Cash and Cash Equivalents, beginning of year..............    6,704,000       3,977,000       1,558,000
                                                           ------------    ------------    ------------

Cash and Cash Equivalents, end of year.................... $  5,223,000    $  6,704,000    $  3,977,000
                                                           ------------    ------------    ------------
                                                           ------------    ------------    ------------

Supplemental schedule of noncash investing and financing activities:

     The Company purchased oilfield service assets for $600,000 in June 1997.  A summary of the 
transaction is as follows:

Fair value of assets acquired............................. $    600,000
Cash paid.................................................      240,000
                                                           ------------
Note payable issued to seller............................. $    360,000
                                                           ------------
                                                           ------------
</TABLE>

         See accompanying notes to consolidated financial statements.
                                       


                                      33
<PAGE>
                                       
                            PRIMA ENERGY CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
              FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995


1.  ORGANIZATION AND SIGNIFICANT ACCOUNTING POLICIES

BUSINESS

     Prima Energy Corporation ("Prima") is an independent oil and gas company 
primarily engaged in the exploration for, acquisition, development and 
production of, crude oil and natural gas.  Through its wholly owned 
subsidiaries, Prima is also engaged in oil and gas property operations, 
oilfield services and natural gas gathering, marketing and trading.  Prima's 
current activities are principally conducted in the Rocky Mountain region.

BASIS OF PRESENTATION

     The accompanying consolidated financial statements include the accounts 
of Prima and its wholly owned subsidiaries, herein collectively referred to 
as the "Company."  The Company's proportionate share of capital expenditures, 
production revenue and operating expenses from working interests in oil and 
gas properties is included in the consolidated financial statements.  The 
Company's interest in an unincorporated joint venture, Bonny Gathering 
Company, is accounted for by the equity method.  All significant intercompany 
transactions have been eliminated.  Certain amounts in prior years have been 
reclassified to conform with the classifications at December 31, 1997.

USE OF ESTIMATES

     The preparation of the financial statements of the Company in conformity 
with generally accepted accounting principles requires management to make 
estimates and assumptions that affect the reported amounts of assets and 
liabilities and disclosure of contingent assets and liabilities at the date 
of the financial statements and the reported amounts of revenues and expenses 
during the reporting period.  Actual results could differ from these 
estimates.

CONSOLIDATED STATEMENTS OF CASH FLOWS

     Cash in excess of daily requirements is invested in money market 
accounts and commercial paper with maturities of three months or less.  Such 
investments are deemed to be cash equivalents for purposes of the 
consolidated statements of cash flows.

     Supplemental disclosures of cash flow information:

          Cash paid during the period for:

<TABLE>
                                      YEARS ENDED DECEMBER 31,
                                   -----------------------------
                                     1997       1996       1995
                                   --------   --------   -------
<S>                                <C>        <C>        <C>
            Income taxes.........  $787,000   $693,000   $     0
            Interest.............         0          0    29,000
</TABLE>
                                       


                                       34
<PAGE>

AVAILABLE FOR SALE SECURITIES

     The Company classifies all securities as "available for sale," states 
them at market value and reports unrealized gains and losses, net of deferred 
income taxes, as an adjustment to stockholders' equity.  Available for sale 
securities are readily marketable and available for use in the Company's 
operations should the need arise.  Therefore, the Company has classified its 
portfolio as a current asset.  Realized gains and losses are determined on 
the specific identification method.

INVENTORY

     Inventory consists of tubular goods stated at the lower of cost or 
market value using the specific identification method.

OIL AND GAS PROPERTIES

     The Company utilizes the full cost method of accounting for oil and gas 
activities.  Under this method, subject to a limitation based on estimated 
value, all costs associated with property acquisition, exploration and 
development, including costs of unsuccessful exploration, are capitalized 
within a cost center.  The Company's oil and gas properties are located 
within the United States, which constitutes one cost center.  No gain or loss 
is recognized upon normal sale or abandonment of undeveloped or producing oil 
and gas properties unless the gain significantly alters the relationship 
between capitalized costs and proved oil and gas reserves of the cost center. 
Depreciation, depletion and amortization of oil and gas properties is 
computed on the units of production method based on proved reserves.  
Amortizable costs include estimates of future development costs of proved 
undeveloped reserves.

     Capitalized costs of oil and gas properties may not exceed an amount 
equal to the present value, discounted at 10%, of the estimated future net 
cash flows from proved oil and gas reserves plus the cost, or estimated fair 
market value, if lower, of unproved properties.  Should capitalized costs 
exceed this ceiling, an impairment is recognized.  The present value of 
estimated future net cash flows is computed by applying year end prices of 
oil and natural gas to estimated future production of proved oil and gas 
reserves as of year end, less estimated future expenditures to be incurred in 
developing and producing the proved reserves and assuming continuation of 
existing economic conditions.

     The Company does not accrue costs for future site restoration, 
dismantlement and abandonment costs related to proved oil and gas properties 
because the Company estimates that such costs will be offset by the salvage 
value of the equipment sold upon abandonment of such properties.  The 
Company's estimates are based upon its historical experience and upon review 
of current properties and restoration obligations.

PROPERTY AND EQUIPMENT

     Property and equipment is recorded at cost.  Renewals and betterments 
which substantially extend the useful lives of the assets are capitalized. 
Maintenance and repairs are expensed when incurred.  Depreciation is provided 
using the straight-line method over the estimated useful lives, 3 to 10 
years, of the assets.

     Long-lived assets, other than oil and gas properties which are evaluated 
for impairment as described above, are evaluated for impairment whenever 
events or changes in circumstances indicate that the carrying amount may not 
be recoverable.  To date, Prima has not recognized any impairment losses.
                                       


                                      35

<PAGE>

TRADING

     The Company recognizes revenues and costs on natural gas trading 
transactions at the point in time when gas is delivered to the purchaser.  At 
December 31, 1997, the Company had delivered 8,000 MMBtu's into the pipeline 
which had not been delivered to the purchaser.  This gas is valued at the 
lower of cost or market value.  Market value for this purpose is deemed to be 
the sales price specified in the contract under which the Company intends to 
sell the gas.  Included in other current assets at December 31, 1997, is 
$19,000 representing the cost of gas which had been delivered into the 
pipeline but not delivered to the purchaser.

     At December 31, 1996, the Company had delivered 13,000 MMBtu's to the 
purchaser which had not been delivered into the pipeline.  This gas is also 
valued at the lower of cost or market value.  Included in amounts payable to 
oil and gas property owners at December 31, 1996 is $48,000 representing the 
cost of gas which had been delivered to the purchaser but not delivered into 
the pipeline.

HEDGING TRANSACTIONS

     The Company periodically uses both commodity futures contracts and price 
swaps to hedge the impact of natural gas and oil price fluctuations on a 
portion of its production and gas marketing activities.  In order to qualify 
for hedge accounting, the item to be hedged must expose the Company to price 
risk (which is the sensitivity of the Company's income for one or more future 
periods to changes in oil and gas spot prices) and the financial contract 
must reduce the price exposure of the Company and be designated as a hedge.  
Further, since the financial contracts for the sale of oil and gas relate to 
anticipated transactions, the significant characteristics and expected terms 
of the anticipated transaction must be identified (i.e., expected date of the 
transaction, the commodity involved, and the expected quantity to be 
purchased or sold) and it must be probable that the anticipated transaction 
will occur. Gains and losses on hedging transactions are deferred until the 
physical transaction occurs for financial reporting purposes.  Deferred gains 
and losses are evaluated in connection with the physical transaction 
underlying the hedge position.  Gains or losses on hedging activities are 
recorded in the income statement as adjustments of the revenue or cost of the 
underlying physical transaction.  Hedging activities are reported as 
operating activities in the statements of cash flows.

     When the Company enters into price swaps or commodities transactions 
that do not correspond to anticipated physical transactions (anticipated 
physical transactions include committed gas marketing activities or 
production from producing wells), the transactions do not qualify for hedge 
accounting.  In that event, the Company records the instruments at fair value 
and gains or losses are recorded as fair values fluctuate compared to cost.  
At December 31, 1997, the Company had no transactions that did not correspond 
to anticipated physical transactions.  For the years ended December 31, 1997, 
1996 and 1995, gains or losses for these transactions were not significant to 
the Company's results of operations.

GOVERNMENT REGULATION

     All aspects of the oil and gas industry are extensively regulated by 
federal, state and local governments in all areas in which the Company has 
operations.  Regulations govern such things as drilling permits, 
environmental protection and pollution control, spacing of wells, the 
unitization and pooling of properties, reports concerning operations, royalty 
rates and various other matters including taxation.  Oil and gas industry 
legislation and administrative regulations are periodically changed for a 
variety of political, economic and other reasons.  As of December 31, 1997, 
the Company had not been fined or cited for any violations of governmental 
regulations which would have a material adverse effect upon the financial 
condition, capital expenditures, earnings or competitive position of the 
Company in the oil and gas industry.
                                       


                                      36

<PAGE>

MANAGEMENT, OPERATOR AND OILFIELD SERVICE FEES

     The Company receives management fees for services performed as the 
managing venturer and operator for a gas gathering and pipeline joint 
venture.  Such fees are included in income.  Income from operating wells for 
third parties is recognized pursuant to the applicable operating agreements 
when the services are performed.  Oilfield services fees are recognized as 
income when the services are performed for third parties.

INCOME TAXES

     Income taxes are provided for the tax effects of transactions reported 
in the financial statements and consist of taxes currently payable plus 
deferred income taxes related to certain income and expenses recognized in 
different periods for financial and income tax reporting purposes.  The 
deferred income tax assets and liabilities represent the future tax return 
consequences of those differences, which will either be taxable or deductible 
when the assets and liabilities are recovered or settled.  Deferred income 
taxes are also recognized for tax credits that are available to offset future 
federal income taxes. Deferred income taxes are measured by applying 
currently enacted tax rates.

COMPREHENSIVE INCOME

      In June 1997, the Financial Accounting Standards Board issued Statement 
of Financial Accounting Standards No. 130 "Reporting Comprehensive Income" 
(SFAS 130).   SFAS 130 establishes standards for reporting and display of 
comprehensive income and its components (revenues, expenses, gains and 
losses) in a full set of general purpose financial statements.  SFAS 130 
requires that all items that are required to be recognized under accounting 
standards as components of comprehensive income be reported in a financial 
statement that is displayed with the same prominence as other financial 
statements. Reclassification is required for financial statements from 
earlier periods provided for comparative purposes.  Prima is required to 
adopt SFAS 130 in January 1998.  Prima has not completed the process of 
evaluating the impact that will result from adopting SFAS 130 or the manner 
that will be used to disclose the required information in its financial 
statements.

SEGMENT REPORTING

     In June 1997, the Financial Accounting Standards Board issued Statement 
of Financial Accounting Standards No. 131, "Disclosures about Segments of an 
Enterprise and Related Information" ("SFAS 131").  SFAS 131 supersedes FASB 
Statement No. 14, "Financial Reporting for Segments of a Business 
Enterprise." SFAS 131 establishes standards for the way that public business 
enterprises report information about operating segments in annual financial 
statements and requires that those enterprises report selected information 
about operating segments in interim financial reports issued to shareholders. 
It also establishes standards for related disclosures about products and 
services, geographic areas, and major customers.  SFAS 131 requires that a 
public business enterprise report financial and descriptive information about 
its reportable operating segments.  Operating segments are components of an 
enterprise about which separate financial information is available that is 
evaluated regularly by the chief operating decision maker in deciding how to 
allocate resources and in assessing performance.  Generally, financial 
information is required to be reported on the basis that it is used 
internally for evaluating segment performance and deciding how to allocate 
resources to segments.  The Company is required to adopt SFAS 131 in 1998 and 
comparative information for earlier years is required to be restated.  The 
Company has not completed the process of evaluating the impact that will 
result from adopting SFAS 131 or the manner that will be used to disclose the 
required information in its financial statements.
                                       


                                      37

<PAGE>

EARNINGS PER SHARE

     During February 1997, the Financial Accounting Standards Board issued 
Statement of Financial Accounting Standards No. 128, "Earnings per Share" 
("SFAS 128").  SFAS 128 establishes standards for computing and presenting 
earnings per share ("EPS"), and supersedes APB Opinion No. 15 and its related 
interpretations.  It replaces the presentation of primary EPS with a 
presentation of basic EPS, which excludes dilution, and requires dual 
presentation of basic and diluted EPS for all entities with complex capital 
structures.  Diluted EPS is computed similarly to fully diluted EPS pursuant 
to Opinion No. 15.  SFAS 128 is effective for periods ending after December 
15, 1997, including interim periods, and requires restatement of all prior 
period EPS data presented.  The Company adopted SFAS 128 effective December 
31, 1997, and has restated all prior period EPS data presented to give 
retroactive effect to the new accounting standard.

     Basic net income per share is computed by dividing net income by the 
weighted average common shares outstanding during the period.  Diluted net 
income per share includes the potential dilution that could occur upon 
exercise of the options to acquire common stock described in Note 10, 
computed using the treasury stock method.  The treasury stock method assumes 
that the increase in the number of shares issued is reduced by the number of 
shares which could have been repurchased by the Company with the proceeds 
from the exercise of the options (which were assumed to have been at the 
average market price of the common shares during the reporting period).

     The following table reconciles the numerator and denominator used in the 
calculation of basic and diluted net income per share.

<TABLE>
                                            Income         Shares       Per Share
                                          (Numerator)   (Denominator)     Amount
                                          -----------   -------------   ---------
<S>                                       <C>           <C>             <C>
Year Ended December 31, 1997:
  Basic Net Income per Share............  $8,102,000      5,771,089       $ 1.40
  Effect of Stock Options...............                    139,362       ------
                                          ----------      ---------       ------

  Diluted Net Income per Share..........  $8,102,000      5,910,451       $ 1.37
                                          ----------      ---------       ------
                                          ----------      ---------       ------

Year Ended December 31, 1996:
  Basic Net Income per Share............  $6,669,000      5,820,594       $ 1.15
  Effect of Stock Options...............                     45,536       ------
                                          ----------      ---------       ------

  Diluted Net Income per Share..........  $6,669,000      5,866,130       $ 1.14
                                          ----------      ---------       ------
                                          ----------      ---------       ------

Year Ended December 31, 1995:
  Basic Net Income per Share............  $4,492,000      5,820,594       $ 0.77
  Effect of Stock Options...............                          0       ------
                                          ----------      ---------       ------

  Diluted Net Income per Share..........  $4,492,000      5,820,594       $ 0.77
                                          ----------      ---------       ------
                                          ----------      ---------       ------
</TABLE>

     The Board of Directors of Prima approved a three for two stock split of 
the Company's common stock, to shareholders of record on February 20, 1997, 
distributed March 4, 1997.  As a result, the number of shares of common stock 
outstanding increased from 3,860,396 to 5,790,556 on the distribution date.  
All share and per share amounts included in these financial statements have 
been restated to show the retroactive effects of the stock split.  During 
1997, the shareholders of Prima approved an increase in the number of 
authorized shares of common stock from 8,000,000 to 12,000,000 shares.
                                       


                                      38

<PAGE>

2.  ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

       Cash in excess of daily requirements is invested in money market 
accounts and commercial paper with maturities of three months or less.  The 
carrying amount of cash equivalents approximates fair value because of the 
short maturity of those investments.

     Natural gas hedge contracts are not recorded on the balance sheet at 
December 31, 1997 and 1996.  The fair value of the Company's liability under 
these contracts is estimated to be $155,000 and $23,000, respectively.  The 
estimated fair value of the natural gas hedge contracts is determined by 
multiplying the difference between year end natural gas prices and the hedge 
contract price by the quantities under contract.

     The fair market value of the Company's debt at December 31, 1997 is 
approximately equal to its carrying value since the Company could have 
obtained the debt for the same terms at December 31, 1997.

3.  AVAILABLE FOR SALE SECURITIES

     The Company's investments are comprised of marketable equity securities. 
For the years ended December 31, 1997 and 1996, the Company sold securities 
with a market value of $113,000 and $418,000 which resulted in realized 
losses of $10,000 and $70,000, respectively.  The net unrealized gain or loss 
on securities at December 31, 1997 and 1996 is included as a separate 
component of stockholders' equity, net of deferred income taxes of $27,000 
and ($20,000), respectively.  The change in net unrealized gain or loss on 
securities for the years ended December 31, 1997 and 1996 was determined as 
follows:

<TABLE>
                                                       1997          1996
                                                    ----------    ----------
<S>                                                 <C>           <C>
     Net unrealized loss, beginning of year.......  $   56,000    $  122,000
     Net unrealized loss, end of year.............           0       (56,000)
     Net unrealized gain, end of year.............      71,000             0
                                                    ----------    ----------
     Net change in unrealized gain or loss........  $  127,000    $   66,000
                                                    ----------    ----------
                                                    ----------    ----------
</TABLE>

The components of fair value as of December 31, 1997 and 1996 are as follows:

<TABLE>
                                                       1997          1996
                                                    ----------    ----------
<S>                                                 <C>           <C>
     Cost (including reinvested distributions)....  $1,795,000    $1,559,000
     Gross unrealized gains.......................     111,000         5,000
     Gross unrealized losses......................     (40,000)      (61,000)
                                                    ----------    ----------
     Fair value...................................  $1,866,000    $1,503,000
                                                    ----------    ----------
                                                    ----------    ----------
</TABLE>

4.  NOTE PAYABLE AND LINE OF CREDIT

     The note payable as of December 31, 1997, bears interest at an annual 
rate of 8% and is due on June 10, 2000.  Payments of principal and accrued 
interest on the note are to be made in three equal annual installments on the 
anniversary date of the note.  The note financed the purchase of oilfield 
service equipment by Action Oilfield Services, Inc., a wholly owned 
subsidiary.  The note is collateralized by oilfield service equipment with a 
net book value of approximately $558,000 at December 31, 1997.
                                       


                                      39

<PAGE>

     Prima has an $8,000,000 unsecured line of credit with a commercial bank. 
The line of credit, which matures on May 1, 1999, bears interest at the 
bank's prime rate (8.50% at December 31, 1997), with  interest payable 
monthly.  At December 31, 1997 and 1996, there were no amounts outstanding 
under the line of credit.

5.  HEDGING ACTIVITIES

     The Company's marketing and trading activities consist of marketing the 
Company's own production, marketing the production of others from wells 
operated by the Company, and natural gas trading activities that consist of 
the purchase and resale of natural gas.  Crude oil and natural gas futures, 
options and swaps are used from time to time in order to hedge the price of a 
portion of the Company's production and purchases for resale.  This is done 
to mitigate the risk of fluctuating oil and natural gas prices which can 
adversely affect operating results.  These transactions have been entered 
into with major financial institutions, thereby minimizing credit risk.  The 
Company hedged approximately 29%, 25% and 11% of its oil production in 1997, 
1996 and 1995, respectively, and hedged approximately 37%,  0% and 34% of its 
natural gas production in these same years.

     To hedge its natural gas and crude oil production and purchases for 
resale, the Company from time to time uses futures and energy swaps.  The 
purpose of these hedges is to provide market price protection in the volatile 
environment of oil and natural gas spot pricing.  As a result of its trading 
activities, the Company may also from time to time have open purchase or sale 
commitments without corresponding contracts to offset these commitments, 
which could result in losses to the Company.  The Company attempts to control 
its exposure to these risks by monitoring its positions as it deems 
appropriate.  All hedges or open positions are reviewed by the Chief 
Executive Officer before they are committed to, and significant positions are 
reviewed by the Company's Board of Directors. With the exception of the third 
party contract discussed in Note 9, the Company had no open trading positions 
to purchase or deliver natural gas at December 31, 1997.  During 1997, the 
Company had hedged a portion of its expected natural gas production in its 
key area of production, the Rocky Mountain Region, by entering into a one 
year commodity swap agreement covering 150,000 MMBtu per month beginning 
April 1, at a fixed price of $1.575 per MMBtu.  At December 31, 1997, the 
Company had an unrealized loss of $155,000 on the remaining open months of 
January, February and March 1998.

6.  INCOME TAXES

     The provision for income taxes consists of the following components:

<TABLE>
                                             Year Ended December 31,
                                     --------------------------------------
                                        1997          1996          1995
                                     ----------    ----------    ----------
<S>                                  <C>           <C>           <C>
Current:
  Federal..........................  $  524,000    $  400,000    $  354,000
  State............................      83,000       124,000       127,000
                                     ----------    ----------    ----------
                                        607,000       524,000       481,000
                                     ----------    ----------    ----------
Deferred:
  Federal..........................   2,277,000     1,741,000     1,116,000
  State............................     166,000       277,000       127,000
                                     ----------    ----------    ----------
                                      2,443,000     2,018,000     1,243,000
                                     ----------    ----------    ----------

Tax credits........................    (415,000)     (257,000)     (354,000)
                                     ----------    ----------    ----------

Provision for income taxes.........  $2,635,000    $2,285,000    $1,370,000
                                     ----------    ----------    ----------
                                     ----------    ----------    ----------
</TABLE>
                                       


                                      40

<PAGE>

     During 1997, the Company recognized income tax deductions of $143,000 
from the exercise of nonqualified stock options.  Stockholders' equity has 
been credited in the amount of $52,000 for the income tax benefit of these 
deductions.

     The significant components of deferred tax assets and deferred tax 
liabilities included in the balance sheet are as follows:

<TABLE>
                                                  1997           1996
                                              -----------    ----------
<S>                                           <C>            <C>
     Deferred Tax Assets:
       Minimum tax credit carryforwards.....  $ 3,151,000    $2,736,000
       State income taxes...................      380,000       322,000
       Accrued bonuses......................       86,000             0
       Other................................       32,000        94,000
                                              -----------    ----------
       Total Deferred Tax Assets............    3,649,000     3,152,000
                                              -----------    ----------

     Deferred Tax Liabilities:
       Intangible drilling costs............    9,963,000     7,351,000
       Deferred revenues....................       92,000        82,000
       Depreciation.........................       92,000        61,000
       Other................................      399,000       480,000
                                              -----------    ----------
       Total Deferred Tax Liabilities.......   10,546,000     7,974,000
                                              -----------    ----------

                                              $ 6,897,000    $4,822,000
                                              -----------    ----------
                                              -----------    ----------
</TABLE>

     The reconciliation of income tax computed at the federal statutory tax 
rate to the Company's effective tax rate is as follows:

<TABLE>
                                          YEAR ENDED DECEMBER 31,
                                          -----------------------
                                          1997     1996      1995
                                          ----     ----     -----
<S>                                       <C>      <C>      <C>
Federal statutory income tax rate.......  34.0%    34.0%     34.0%
Percentage depletion....................  (2.6)    (2.7)     (3.4)
Section 29 credits......................  (7.2)    (8.3)    (13.7)
State taxes, net of federal benefit.....   1.6      3.0       2.9
Other...................................  (1.3)    (0.5)      3.6
                                          ----     ----     -----
     Effective tax rate.................  24.5%    25.5%     23.4%
                                          ----     ----     -----
                                          ----     ----     -----
</TABLE>

     At December 31, 1997, the Company had minimum tax credit carryforwards 
of approximately $3,151,000, which may be carried forward indefinitely.
                                       


                                      41

<PAGE>

7.  MAJOR CUSTOMERS

     The following customers have each accounted for over 10% of the 
Company's consolidated revenues and are from the identified industry segment. 
Following is a table summarizing the percentage of sales made to each 
customer.  Although the loss of any of these customers could have a material 
adverse effect on the Company, the Company believes it would be able to 
locate other customers for the purchase of its production and would be able 
to secure additional marketing opportunities.

<TABLE>
                                               1997     1996     1995
                                               ----     ----     ----
<S>                                            <C>      <C>      <C>
     Oil and Gas Operations:
       Duke Energy Field Services, Inc.......   20%      19%      21%
       Total Petroleum.......................   11       15       20
     Natural Gas Marketing and Trading:
       Colorado Power Partnership............   10       11       13
       KN Gas Marketing, Inc.................   21       21
</TABLE>

8.  INDUSTRY SEGMENT INFORMATION

     The following table sets forth revenues, operating earnings before 
income taxes, identifiable assets, depreciation, depletion and amortization 
expense and capital expenditures for the years ended December 31, 1997, 1996 
and 1995 for the Company's two identifiable industry segments.

<TABLE>
                                  1997          1996          1995
                              -----------   -----------   -----------
<S>                           <C>           <C>           <C>
Revenues
  Oil and gas...............  $35,100,000   $26,011,000   $17,399,000
  Oilfield services.........    4,135,000     2,894,000     1,968,000
  Other.....................      536,000       340,000       162,000
                              -----------   -----------   -----------
    Total...................  $39,771,000   $29,245,000   $19,529,000
                              -----------   -----------   -----------
                              -----------   -----------   -----------

Operating Earnings
  Oil and gas...............  $ 9,650,000   $ 8,315,000   $ 5,617,000
  Oilfield services.........      551,000       299,000       104,000
  Other.....................      536,000       340,000       141,000
                              -----------   -----------   -----------
    Total...................  $10,737,000   $ 8,954,000   $ 5,862,000
                              -----------   -----------   -----------
                              -----------   -----------   -----------

Identifiable Assets
  Oil and gas...............  $48,080,000   $37,872,000   $31,803,000
  Oilfield services.........    2,466,000     1,666,000     1,237,000
  Other.....................    7,375,000     8,468,000     5,525,000
                              -----------   -----------   -----------
    Total...................  $57,921,000   $48,006,000   $38,565,000
                              -----------   -----------   -----------
                              -----------   -----------   -----------

Depreciation, Depletion and 
 Amortization Expense
  Oil and gas...............  $ 5,088,000   $ 4,321,000   $ 4,138,000
  Oilfield services.........      344,000       223,000       234,000
                              -----------   -----------   -----------
    Total...................  $ 5,432,000   $ 4,544,000   $ 4,372,000
                              -----------   -----------   -----------
                              -----------   -----------   -----------

Capital Expenditures
  Oil and gas...............  $15,556,000   $ 8,251,000   $ 5,299,000
  Oilfield services.........      986,000       331,000       132,000
                              -----------   -----------   -----------
    Total...................  $16,542,000   $ 8,582,000   $ 5,431,000
                              -----------   -----------   -----------
                              -----------   -----------   -----------
</TABLE>


                                      42

<PAGE>

     The Company operates principally in two industries, oil and gas 
operations and oilfield services.  Total revenue by industry segment includes 
both sales to unaffiliated customers, as reported in the Company's 
consolidated income statement, and intersegment sales, which are primarily 
oilfield services provided to Company owned wells which are eliminated in 
consolidation.  Oilfield services revenue includes $921,000, $624,000 and 
$481,000 for the years ended December 31, 1997, 1996 and 1995, respectively, 
for intersegment sales. Oilfield services revenue is priced and accounted for 
consistently for both unaffiliated and intersegment sales.

     Identifiable assets by industry segment are those assets that are used 
in the Company's operations in each segment.  Corporate assets are 
principally cash, cash equivalents and available for sale securities.

9.  COMMITMENTS AND CONTINGENCIES

OFFICE LEASE

     During 1995, the Company entered into an agreement to extend its current 
operating lease for office space for an additional five years, with a term 
through November 30, 2000.  Rental expense, net of sublease rental income, 
totaled $112,000, $109,000 and $127,000 for the years ended December 31, 
1997, 1996 and 1995, respectively.  Future minimum annual rentals under 
non-cancelable operating leases with remaining terms in excess of one year 
are as follows:

<TABLE>
     
     <S>                                          <C>
     Year ending December 31, 1998...........     129,000
     Year ending December 31, 1999...........     132,000
     Year ending December 31, 2000...........     124,000
                                                 --------
                                                 $385,000
                                                 --------
                                                 --------

</TABLE>

DELIVERY COMMITMENT

     A participation agreement was executed May 24, 1989 between the Company 
and an unrelated third party to supply the natural gas required for a 50 
megawatt cogeneration facility in Brush, Colorado.  The Company contracted to 
supply 70% of the committed quantities.  Also on May 24, 1989, the Company 
and the third party signed a Gas Sales Agreement with the owner/operator of 
the cogeneration facility.  The Gas Sales Agreement required that 
approximately 1,750,000 MMBtu's per year of natural gas for 15 years be 
supplied to the cogeneration facility. Under the agreement, the 
owner/operator was required to take or pay for 80% of the annual contract 
quantity.  The Company dedicated a substantial portion of its proved reserves 
in Weld County, Colorado to cover its share of the commitment.  The contract 
price for the gas ($2.72 per MMBtu for 1998) escalated annually at the higher 
of 3% or a sharing of the indexed energy payment rate received by the 
owner/operator.

     In January 1998, Prima terminated the contract, effective October 31, 
1998, for $3,850,000, and other consideration. From January 1, 1998, through 
October 31, 1998, Prima has agreed to supply 100% of the third party's 
natural gas requirements.  Under the termination agreement, Prima will 
receive $2.72 per MMBtu from January 1, 1998 through March 31, 1998, and a 
spot related index price from April 1, 1998 through October 31, 1998.  At 
that time, the parties have agreed to negotiate in good faith a new supply 
contract through the year 2005, but neither party has an obligation to supply 
or purchase from the other. As a result of the contract termination, Prima's 
substantial dedication of gas reserves in the Wattenberg Area in northeast 
Colorado for the long term contract will be released effective October 31, 
1998.

                                      43
<PAGE>

NOTE GUARANTEE

     Bonny Gathering Company ("Bonny"), an unincorporated joint venture of 
which Prima is the managing joint venturer and operator, established a line 
of credit with a commercial bank in the amount of $3,500,000 during 1997.  
The promissory note bears interest at the bank's prime interest rate less 
1/2%, payable monthly on the last day of each calendar month.  Funds may be 
advanced on the line of credit through November 30, 1998 and the note is due 
November 30, 2001.  The note is collateralized by a first priority mortgage 
and deed of trust on the assets of Bonny.  Prima has guaranteed its 15.5% 
proportionate share of the note.  At December 31, 1997, Bonny had drawn 
$915,000 on the note.

10.  EMPLOYEE BENEFIT PLANS

STOCK OPTION PLAN

     Under the Prima Energy Corporation 1993 Stock Incentive Plan ("the 
Plan"), 600,000 shares of Prima's common stock are reserved for issuance to 
key employees at fair market value on the date of grant.  Options granted 
under the Plan vest at 20% per year for five years, and expire 10 years from 
the date of grant.  At December 31, 1997, options to acquire 367,500 shares 
of the Company's common stock had been granted under the Plan. The exercise 
prices, which equaled the market price of the stock on the date of grant, 
ranged from $8.83 to $9.92 per share, with a weighted average price of $9.20 
per share.  As of December 31, 1997, the weighted average remaining 
contractual life of the options outstanding is 6 years, 4 months.

     A summary of options granted, exercised and outstanding during 1995, 
1996 and 1997 is as follows:

<TABLE>

                                            Number           Weighted Average
                                           of Shares         Exercise Prices
                                           ---------         ----------------
   <S>                                    <C>               <C>
   Balance, December 31, 1994.............  255,000               8.88
   Granted during 1995....................  112,500               9.92
   Exercised or canceled..................        0                n/a
                                            -------
   Outstanding at December 31, 1995.......  367,500               9.20

   Granted during 1996....................        0                n/a
   Exercised or canceled..................        0                n/a
                                            -------
   Outstanding at December 31, 1996.......  367,500               9.20

   Granted during 1997....................        0                n/a
   Exercised or canceled..................  (12,500)              8.93
                                            -------
   Outstanding at December 31, 1997.......  355,000               9.20
                                            -------
                                            -------

   Exercisable at December 31, 1995.......   97,500               8.86
   Exercisable at December 31, 1996.......  171,000               9.00
   Exercisable at December 31, 1997.......  235,000               9.06

</TABLE>

     The Company has adopted the disclosure-only provisions of Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123").  Accordingly, no compensation cost has been
recognized for the Plan.  Had compensation expense for the Plan been determined
based on the fair value at the grant date for the options awarded in 1995
consistent with the provisions of SFAS 123, the Company's net income and net
income per share would have been reduced to the pro forma amounts indicated
below:

                                     44
<PAGE>

<TABLE>

                                            1997          1996          1995
                                        -----------    ----------    ----------
  <S>                                   <C>            <C>           <C>
  Net income    
       As reported.....................  $8,102,000    $6,669,000    $4,492,000
       Pro forma.......................   8,018,000     6,509,000     4,492,000
  Basic net income per share
       As reported.....................      $1.40          $1.15         $0.77
       Pro forma.......................       1.39           1.12          0.77
  Diluted net income per share
       As reported.....................      $1.37          $1.14         $0.77
       Pro forma.......................       1.36           1.11          0.77

</TABLE>

     The fair value of the options for disclosure purposes was estimated on 
the date of the grant using the Black-Scholes Model with the following 
assumptions:

<TABLE>
                <S>                                         <C>

                Expected dividend yield..................      0%
                Expected price volatility................     31%
                Risk free interest rate..................    6.6%
                Expected life of options (in years)......      9
</TABLE>

EMPLOYEE STOCK OWNERSHIP PLAN

     The Company has an Employee Stock Ownership Plan ("Plan") and a Trust to 
administer the Plan.  The Plan is qualified under Section 401(a) of the 
Internal Revenue Code of 1986, as amended, and is for the benefit of all 
eligible employees of the Company.  Allocations to participants are made 
annually as of the last day of the Plan year, September 30, and are allocated 
among the participants in proportion to their eligible compensation for the 
Plan year. Contributions to the plan are payable at a minimum rate of 5% of 
eligible salaries.  Through the Plan year ended September 30, 1993, the Plan 
provided for contributions to be made quarterly and to be used to purchase 
Prima common stock on the open market.  Effective October  1, 1993, the Plan 
was amended to allow fully vested employees the option to direct the Plan 
Trustees to diversify a portion of their Plan investments by selling a 
limited percent of Prima common stock and investing the proceeds in various 
investment options.  The Plan benefits all full-time employees and includes 
six year, 100% vesting provisions. For the years ended December 31, 1997, 
1996 and 1995, the Company expensed $169,000, $125,000 and $93,000, 
respectively, of contributions payable to the Plan.

11.  DESIGNATED CASH AND RELATED AD VALOREM TAXES PAYABLE

     The Company has designated a portion of its cash balance for payment of 
ad valorem taxes withheld from third party revenue interest owners.  The 
non-current portion of ad valorem taxes payable relates to those taxes 
collected and accrued for production through December 1997 which is not 
payable until fiscal 1999 or later.  The related cash collected from third 
party revenue interest owners designated for payment of non-current ad 
valorem taxes is reflected as a non-current asset.

                                      45
<PAGE>


12.  TRANSACTIONS WITH RELATED PARTIES

     The Company is a 6% limited partner in a real estate limited partnership 
which currently owns approximately 22 acres of undeveloped land in Phoenix, 
Arizona for investment and capital appreciation.  The partnership owns the 22 
acres free and clear.  One of the general partners of the partnership is a 
company controlled by the brother of the Company's president.  The Company 
participated on the same basis as the other limited partners.  This 
transaction was approved by the disinterested members of the Company's Board 
of Directors.

     Certain of the Company's directors and officers have participated, 
either individually or through entities which they control, in oil and gas 
prospects or properties in which the Company has an interest.  These 
participations, which have been on a working interest basis, have been in 
prospects or properties originated or acquired by the Company.  In some 
cases, the interests sold to affiliated and non-affiliated participants were 
sold on a promoted basis requiring these participants to pay a 
disproportionate share of well costs. Each of the participations by directors 
and officers has been on terms no less favorable to the Company than it could 
have obtained from non-affiliated participants.  It is expected that joint 
participations with the Company will continue to occur from time to time in 
the future.  All participations by the officers and directors have and will 
continue to be approved by the disinterested members of the Company's Board 
of Directors.

     At any point in time, there are receivables and payables with officers 
and directors that arise in the ordinary course of business.  Prima, as 
operator, commenced drilling a well in December 1997 in which Mr. Lockridge, 
a director of Prima, is a 61% working interest owner.  The estimated costs to 
drill and complete the well are $1,686,800, or $1,026,000 net to Mr. 
Lockridge.  As of the end of February 1998, the most recent billing period, 
Mr. Lockridge owed Prima $299,433 for his proportionate share of costs billed 
through that date, net of prepayments made of $389,311.  There were no 
significant amounts due to or from any other officers or directors in 1997.

13.  SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

     Costs incurred in oil and gas property acquisition, exploration and 
development activities are as follows:
              
<TABLE>
                                             Year Ended December 31,
                                     ----------------------------------------
                                        1997           1996           1995 
                                     -----------    ----------     ----------
<S>                                  <C>            <C>            <C>
Acquisition costs:
  Unproved properties..............  $ 1,427,000    $  873,000     $1,319,000
  Proved properties................       30,000        63,000         27,000
Exploration costs..................    1,228,000       401,000        202,000
Development costs..................   12,565,000     6,605,000      3,634,000
                                     -----------    ----------     ----------
   Total...........................  $15,250,000    $7,942,000     $5,182,000
                                     -----------    ----------     ----------
                                     -----------    ----------     ----------
Amortization per equivalent
  barrel of production.............      $  4.31       $  4.18        $  4.13
                                     -----------    ----------     ----------
                                     -----------    ----------     ----------

</TABLE>

                                      46
<PAGE>

     Results of operations for oil and gas producing activities are as follows:

<TABLE>
                                                          Year Ended December 31,
                                                 -----------------------------------------
                                                     1997           1996           1995
                                                 -----------    -----------    -----------
<S>                                              <C>            <C>            <C>
Revenues
  Oil and gas sales............................  $17,840,000    $14,657,000    $11,502,000
                                                 -----------    -----------    -----------
Expenses
  Lease operating expense......................    1,720,000      1,511,000      1,432,000
  Ad valorem and production taxes..............    1,355,000        981,000        736,000
  Depreciation, depletion and amortization.....    4,935,000      4,210,000      4,058,000
                                                 -----------    -----------    -----------
                                                   8,010,000      6,702,000      6,226,000
                                                 -----------    -----------    -----------

Income before income taxes.....................    9,830,000      7,955,000      5,276,000
Income tax expense.............................    2,408,000      2,029,000      1,233,000
                                                 -----------    -----------    -----------

Income from oil and gas producing properties...  $ 7,422,000    $ 5,926,000    $ 4,043,000
                                                 -----------    -----------    -----------
                                                 -----------    -----------    -----------
</TABLE>

     The reserve information presented below was prepared by independent 
engineers for the year ended December 31, 1997 and by Company personnel for 
the years ended December 31, 1996 and 1995.  There are numerous uncertainties 
inherent in estimating quantities of proved reserves and in projecting future 
rates of production and timing of development expenditures.  Oil and gas 
reserve engineering must be recognized as a subjective process of estimating 
underground accumulations of oil and natural gas that cannot be measured in 
an exact way. The accuracy of any reserve estimates is a function of the 
quality of available data and engineering and geological interpretation and 
judgment.  Results of drilling, testing and production after the date of the 
estimate may justify revisions.  Accordingly, reserve estimates are often 
materially different from the quantities of oil and natural gas that are 
ultimately produced.

     Proved oil and gas reserves are the estimated quantities of crude oil, 
natural gas, and natural gas liquids which geological and engineering data 
demonstrate with reasonable certainty to be recoverable in future years from 
known reservoirs under existing economic and operating conditions.  Proved 
developed oil and gas reserves are those proved reserves expected to be 
recovered through existing wells with existing equipment and operating 
methods.
                                       


                                      47

<PAGE>

     Proved oil and gas reserves of the Company, all of which are located in 
the United States, are as follows:

<TABLE>
                                                           Year Ended December 31,
                                          --------------------------------------------------------
                                                1997                1996               1995
                                          ----------------    ----------------   -----------------
                                            Oil      Gas        Oil      Gas       Oil       Gas
                                          (MBBLS)   (MMCF)    (MBBLS)   (MMCF)   (MBBLS)    (MMCF)
                                          ----------------    ----------------   -----------------
<S>                                       <C>       <C>       <C>       <C>      <C>       <C>
Proved reserves:
  Beginning of year.....................   3,037    52,112     2,734    47,711    3,009    46,202
  Purchases of oil and
    gas reserves in place...............      27       251        14       231       14       123
  Revisions of previous
    estimates...........................     (94)   (1,843)      130     2,444      (39)     (218)
  Extensions, discoveries and
    other additions.....................     643    18,314       392     6,372       17     5,924
  Production............................    (255)   (5,344)     (233)   (4,646)    (266)   (4,298)
  Sales of oil and gas reserves
    in place............................       0         0         0         0       (1)      (22)
                                           -----    ------     -----    ------    -----    ------

  End of Year...........................   3,358    63,490     3,037    52,112    2,734    47,711
                                           -----    ------     -----    ------    -----    ------
                                           -----    ------     -----    ------    -----    ------
Proved developed reserves:
  Beginning of year.....................   2,087    41,107     1,853    38,076    2,080    35,664

  End of year...........................   2,286    48,139     2,087    41,107    1,853    38,076
</TABLE>

            Standardized measures of discounted future net cash flows relating
to proved oil and gas reserves are as follows:

<TABLE>
                                                     Year Ended December 31,
                                          --------------------------------------------
                                              1997            1996            1995
                                          ------------    ------------    ------------
<S>                                       <C>             <C>             <C>
Future cash inflows.....................  $209,689,000    $271,196,000    $148,101,000
Future production costs.................   (51,203,000)    (77,211,000)    (47,648,000)
Future development costs................   (22,095,000)    (17,548,000)    (15,425,000)
                                          ------------    ------------    ------------

Future net cash flows...................   136,391,000     176,437,000      85,028,000
10% discount factor.....................   (60,851,000)    (84,991,000)    (37,243,000)
Discounted future income taxes..........   (17,391,000)    (22,481,000)     (8,605,000)
                                          ------------    ------------    ------------

Standardized measure of discounted
  future net cash flows.................  $ 58,149,000    $ 68,965,000    $ 39,180,000
                                          ------------    ------------    ------------
                                          ------------    ------------    ------------
</TABLE>


                                      48


<PAGE>

     The principal sources of change in the standardized measure of discounted
future net cash flows are as follows:

<TABLE>
                                                               Year Ended December 31,
                                                    -------------------------------------------
                                                        1997            1996            1995
                                                    ------------    ------------    -----------
<S>                                                 <C>             <C>             <C>
Beginning standardized measure....................  $ 68,965,000    $ 39,180,000    $38,095,000
Sales of oil and gas produced,
  net of production costs.........................   (14,765,000)    (12,165,000)    (9,334,000)
Net changes in prices and  production costs.......   (29,995,000)     37,015,000     (1,763,000)
Extensions, discoveries, and improved
  recovery, less related costs....................    20,922,000      11,187,000      8,505,000
Development costs incurred during the year........     5,713,000       3,077,000      2,729,000
Changes in estimated future development costs.....    (1,402,000)       (558,000)    (2,629,000)
Revisions of previous quantity
  estimates and other.............................    (3,658,000)        806,000     (1,291,000)
Purchases of reserves in place....................       382,000         381,000        101,000
Sales of reserves in place........................             0               0        (13,000)
Accretion of discount.............................     6,896,000       3,918,000      3,809,000
Net change in income taxes........................     5,091,000     (13,876,000)       971,000
                                                    ------------    ------------    -----------
Ending standardized measure.......................  $ 58,149,000    $ 68,965,000    $39,180,000
                                                    ------------    ------------    -----------
                                                    ------------    ------------    -----------
</TABLE>

14.  QUARTERLY FINANCIAL DATA (UNAUDITED)

     The following is a summary of the unaudited financial data for each quarter
for the years ended December 31, 1997 and 1996.

<TABLE>
                                                      Three Months Ended
                                     ---------------------------------------------------
                                       3/31/97       6/30/97      9/30/97      12/31/97
                                     -----------   ----------   ----------   -----------
<S>                                  <C>           <C>          <C>          <C>
Year Ended December 31, 1997
  Revenues.........................  $11,913,000   $9,460,000   $8,561,000   $ 8,916,000
  Gross profit.....................    3,565,000    2,559,000    2,033,000     2,034,000
  Net income.......................    2,677,000    1,954,000    1,577,000     1,894,000
  Basic net income per share.......         0.46         0.34         0.27          0.33
  Diluted net income per share.....         0.45         0.33         0.27          0.32

                                                      Three Months Ended
                                     ---------------------------------------------------
                                       3/31/96       6/30/96      9/30/96      12/31/96
                                     -----------   ----------   ----------   -----------
Year Ended December 31, 1996
  Revenues.........................  $ 6,385,000   $5,875,000   $6,098,000   $10,263,000
  Gross profit.....................    1,909,000    1,744,000    1,867,000     2,993,000
  Net income.......................    1,529,000    1,401,000    1,538,000     2,201,000
  Basic net income per share.......         0.26         0.24         0.26          0.38
  Diluted net income per share.....         0.26         0.24         0.26          0.37
</TABLE>


                                      49

<PAGE>
                                       
                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Prima Energy Corporation has duly caused this Annual
Report on Form 10-K to be signed on its behalf by the undersigned, thereunto
duly authorized, in Denver, Colorado on the 13th day of March, 1998.


                                                 PRIMA ENERGY CORPORATION


                                                 By: /s/ Richard H. Lewis
                                                     ---------------------------
                                                     Richard H. Lewis, President

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed below by the following persons in the
capacities indicated and on the dates indicated.

<TABLE>
      SIGNATURE                          TITLE                          DATE
<S>                          <C>                                   <C>

/s/ Richard H. Lewis         Chairman, President, Treasurer,       March 13, 1998
------------------------     (Principal Executive and
Richard H. Lewis             Financial Officer)


/s/ Robert E. Childress                                            March 13, 1998
------------------------     Director
Robert E. Childress


/s/ Douglas J. Guion                                               March 13, 1998
------------------------     Director
Douglas J. Guion


/s/ John P. Lockridge                                              March 13, 1998
------------------------     Director
John P. Lockridge


/s/ George L. Seward                                               March 13, 1998
------------------------     Director
George L. Seward             


/s/ Sandra J. Irlando                                              March 13, 1998
------------------------     Vice President of Accounting
Sandra J. Irlando            and Controller
</TABLE>


                                      50