<PAGE> 1
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to _______
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
incorporation or organization) Identification No.)
1801 BROADWAY, SUITE 500, DENVER CO 80202
(Address of principal executive offices) (Zip Code)
(303) 297-2100
(Registrant's telephone number, including area code)
NO CHANGE
(Former name, former address and former fiscal year, if changed from last
report.)
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 [ ]
As of November 1, 2000, the Registrant had 8,518,394 shares of Common Stock,
$0.015 Par Value, outstanding.
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PRIMA ENERGY CORPORATION
INDEX
<TABLE>
<CAPTION>
PART I - FINANCIAL INFORMATION Page
----
<S> <C>
Item 1. Financial Statements
Unaudited consolidated balance sheets . . . . . . . . . . . . . . . . . . . . . . . 3
Unaudited consolidated statements of income . . . . . . . . . . . . . . . . . . . . 5
Unaudited consolidated statements of comprehensive income . . . . . . . . . . . . . 6
Unaudited consolidated statements of cash flows . . . . . . . . . . . . . . . . . . 7
Notes to unaudited consolidated financial statements. . . . . . . . . . . . . . . . 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations . . . . . . . . . . . . . . . . 11
Item 3. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . 16
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995. . . . . . . . . . . . . . . . . . 17
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . . . 18
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
</TABLE>
<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM I. FINANCIAL STATEMENTS
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
(Unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents ................................ $ 17,239,000 $ 18,883,000
Available for sale securities, at market ................. 2,244,000 1,949,000
Receivables (net of allowance for doubtful
accounts: 9/30/00, $47,000; 12/31/99, $45,000) ......... 8,403,000 5,284,000
Tubular goods inventory .................................. 1,950,000 837,000
Other .................................................... 832,000 988,000
------------ ------------
Total current assets ............................... 30,668,000 27,941,000
------------ ------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ......................... 97,105,000 77,700,000
Less accumulated depreciation,
depletion and amortization ............................. (42,171,000) (37,785,000)
------------ ------------
Oil and gas properties - net ....................... 54,934,000 39,915,000
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ............................... 7,739,000 6,814,000
Gathering system ......................................... 1,347,000 0
Furniture and equipment .................................. 704,000 659,000
Field offices, shops and land ............................ 488,000 481,000
------------ ------------
10,278,000 7,954,000
Less accumulated depreciation ............................ (4,175,000) (3,402,000)
------------ ------------
Property and equipment - net ........................ 6,103,000 4,552,000
------------ ------------
OTHER ASSETS ............................................. 257,000 257,000
------------ ------------
$ 91,962,000 $ 72,665,000
============ ============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
3
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PRIMA ENERGY CORPORATION
CONSOLIDATED AND BALANCE SHEETS (CONT'D.)
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------ ------------
(Unaudited)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable ............................................. $ 2,111,000 $ 2,085,000
Amounts payable to oil and gas property owners ............... 1,836,000 1,499,000
Production taxes payable ..................................... 2,171,000 1,210,000
Income taxes payable ......................................... 453,000 1,051,000
Accrued and other liabilities ................................ 811,000 384,000
Current portion of note payable .............................. 0 304,000
------------ ------------
Total current liabilities .............................. 7,382,000 6,533,000
PRODUCTION TAXES, non-current ................................ 2,178,000 1,516,000
DEFERRED TAX LIABILITY ....................................... 9,595,000 5,708,000
------------ ------------
Total liabilities ...................................... 19,155,000 13,757,000
------------ ------------
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued or outstanding ............... 0 0
Common stock, $0.015 par value, 18,000,000 shares
authorized; 8,944,016 and 8,893,366 shares issued ......... 134,000 133,000
Additional paid-in capital ................................... 6,709,000 5,693,000
Retained earnings ............................................ 71,141,000 56,577,000
Accumulated other comprehensive income (loss) ................ (148,000) (244,000)
Treasury stock - 425,622 and 322,305 shares, at cost ......... (5,029,000) (3,251,000)
------------ ------------
Total stockholders' equity ............................. 72,807,000 58,908,000
------------ ------------
$ 91,962,000 $ 72,665,000
============ ============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
4
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales ........................ $11,428,000 $ 5,510,000 $30,390,000 $13,933,000
Oilfield services ........................ 1,526,000 1,271,000 4,710,000 3,377,000
Trading revenues ......................... 0 929,000 0 2,010,000
Interest, dividend and other income ...... 310,000 366,000 922,000 1,002,000
----------- ----------- ----------- -----------
13,264,000 8,076,000 36,022,000 20,322,000
----------- ----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties ... 1,443,000 1,129,000 4,386,000 3,430,000
Depreciation of other property ........ 295,000 218,000 846,000 573,000
Lease operating expense .................. 655,000 544,000 1,910,000 1,576,000
Production taxes ......................... 950,000 468,000 2,434,000 1,188,000
Cost of oilfield services ................ 1,215,000 795,000 3,833,000 2,328,000
Cost of trading .......................... 0 1,253,000 0 2,354,000
General and administrative ............... 787,000 480,000 2,129,000 1,283,000
----------- ----------- ----------- -----------
5,345,000 4,887,000 15,538,000 12,732,000
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES ............... 7,919,000 3,189,000 20,484,000 7,590,000
PROVISION FOR INCOME TAXES ............... 2,350,000 800,000 5,920,000 1,910,000
----------- ----------- ----------- -----------
NET INCOME ............................... $ 5,569,000 $ 2,389,000 $14,564,000 $ 5,680,000
=========== =========== =========== ===========
BASIC NET INCOME PER SHARE ............... $ 0.66 $ 0.28 $ 1.72 $ 0.66
=========== =========== =========== ===========
DILUTED NET INCOME PER SHARE ............. $ 0.63 $ 0.27 $ 1.65 $ 0.65
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING ..................... 8,500,856 8,562,519 8,491,432 8,565,234
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING
ASSUMING DILUTION ...................... 8,894,633 8,826,362 8,852,614 8,718,087
=========== =========== =========== ===========
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
5
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------------- -------------------------
2000 1999 2000 1999
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Net income .................................. $ 5,569,000 $ 2,389,000 $ 14,564,000 $ 5,680,000
Other comprehensive income:
Unrealized gain (loss) on
available-for-sale securities ............ 84,000 (83,000) 153,000 (316,000)
Deferred income tax expense related
to unrealized gain (loss) on
available-for-sale securities ............ (31,000) 32,000 (57,000) 119,000
------------ ------------ ------------ ------------
53,000 (51,000) 96,000 (197,000)
------------ ------------ ------------ ------------
COMPREHENSIVE INCOME ........................ $ 5,622,000 $ 2,338,000 $ 14,660,000 $ 5,483,000
============ ============ ============ ============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
6
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
----------------------------
2000 1999
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES
Net income ......................................................... $ 14,564,000 $ 5,680,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ........................ 5,232,000 4,003,000
Deferred income taxes ........................................... 3,891,000 1,738,000
Current taxes from sale of oil and gas properties ............... 0 (5,704,000)
Other ........................................................... 556,000 (12,000)
Changes in operating assets and liabilities:
Receivables ................................................... (3,119,000) 123,000
Inventory ..................................................... (1,113,000) 42,000
Other current assets .......................................... 95,000 33,000
Accounts payable and payables to owners ....................... 363,000 (769,000)
Production taxes payable ...................................... 1,623,000 (256,000)
Income taxes payable .......................................... (598,000) 4,986,000
Accrued and other liabilities ................................. 123,000 (108,000)
------------ ------------
Net cash provided by operating activities ................... 21,617,000 9,756,000
------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties ................................ (19,406,000) (11,035,000)
Purchases of other property ........................................ (2,486,000) (2,053,000)
Purchases of available for sale securities ......................... (216,000) (83,000)
Proceeds from sales of oil and gas and other property .............. 170,000 27,604,000
------------ ------------
Net cash provided by (used in) investing activities ......... (21,938,000) 14,433,000
------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ........................................... (1,778,000) (1,791,000)
Repayment of long-term debt ........................................ 0 (120,000)
Proceeds from issuance of common stock ............................. 455,000 823,000
------------ ------------
Net cash used in financing activities ...................... (1,323,000) (1,088,000)
------------ ------------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS ................................................ (1,644,000) 23,101,000
CASH AND CASH EQUIVALENTS, beginning of period ..................... 18,883,000 2,522,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ........................... $ 17,239,000 $ 25,623,000
============ ============
</TABLE>
Supplemental schedule of noncash investing and financing activities:
The Company purchased oilfield service assets in March 1999. A summary
of the transaction is as follows:
<TABLE>
<S> <C>
Fair value of assets acquired ...................................... $460,000
Cash paid .......................................................... 276,000
--------
Note payable issued to seller ...................................... $184,000
========
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
7
<PAGE> 8
PRIMA ENERGY CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The financial information contained herein is unaudited but includes all
adjustments (consisting of only normal recurring accruals) which, in the opinion
of management, are necessary to present fairly the information set forth. The
accounting policies followed by the Company are set forth in Note 1 to the
Company's financial statements in Form 10-K for the year ended December 31,
1999. These financial statements should be read in conjunction with the
financial statements and notes included in the Form 10-K.
The results for interim periods are not necessarily indicative of
results to be expected for the fiscal year of the Company ending December 31,
2000. The Company believes that the nine month report filed on Form 10-Q is
representative of its financial position, its results of operations and its cash
flows for the periods ended September 30, 2000 and 1999 covered thereby.
The accompanying consolidated financial statements include the accounts
of Prima Energy Corporation and its subsidiaries, herein collectively referred
to as "Prima" or the "Company." All significant intercompany transactions have
been eliminated. Certain amounts in prior years have been reclassified to
conform with the classifications at September 30, 2000.
2. NOTES PAYABLE AND LINE OF CREDIT
The Company had two notes payable at December 31, 1999. Both notes were
paid in full during the nine months ended September 30, 2000 pursuant to their
terms.
Prima maintains an $8,000,000 unsecured line of credit with a commercial
bank. The line of credit, which matures on May 1, 2001, bears interest at the
bank's prime rate (9.5% at September 30, 2000), with interest payable monthly.
At December 31, 1999 and September 30, 2000, there were no amounts outstanding
under the line of credit.
3. HEDGING ACTIVITIES
The Company's marketing and trading activities consist of marketing the
Company's own production, marketing the production of others from wells operated
by the Company, and natural gas trading activities that consist of the purchase
and resale of natural gas. Crude oil and natural gas futures, options and swaps
are used from time to time in order to hedge the price of a portion of the
Company's production, as well as to hedge the margins on natural gas purchased
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 did not hedge any of its production during the first nine
months of 2000 and had no buy-for-resale transactions during that period. The
Company hedged approximately 39% of its oil production and 21% of its natural
gas production during the first nine
8
<PAGE> 9
months of 1999. Net hedging losses were $116,000 for the nine months ended
September 30, 1999 and were included in oil and gas revenues at the time the
hedged volumes were sold. At September 30, 2000 and November 1, 2000, the
Company had no open positions.
During June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 133 "Accounting for Derivative
Instruments and Hedging Activities" ("SFAS 133"). SFAS 133 establishes standards
for derivative instruments, including certain derivative instruments embedded in
other contracts (collectively referred to as derivatives) and for hedging
activities. SFAS 133 requires that an entity recognize all derivatives as either
assets or liabilities in the statement of financial position and measure those
instruments at fair value. The accounting for changes in the fair value of a
derivative (gains and losses) depends on the intended use of the derivative and
the resulting designation. The Company is required to adopt SFAS 133 on January
1, 2001. Management does not believe it would have a material impact on
financial position or results of operations.
4. COMMON STOCK
Pursuant to the provisions of the Prima Energy Corporation 1993 Stock
Incentive Plan, during the first nine months of 2000, 47,650 shares of Prima's
common stock were issued upon the exercise of stock options for total proceeds
of $425,000. Additionally, pursuant to the provisions of the Prima Energy
Corporation Non-Employee Directors' Stock Option Plan, 3,000 shares of common
stock were issued for total proceeds of $30,000. These transactions increased
the total number of shares of common stock outstanding to 8,518,394 as of
November 1, 2000.
During the nine months ended September 30, 2000, the Company repurchased
103,317 shares of its common stock as treasury stock for $1,778,000 pursuant to
a stock repurchase program. The Board of Directors has authorized the repurchase
of up to 5% of the Company's common stock, depending upon market conditions, the
Company's financial condition, anticipated capital requirements and liquidity,
among other factors. At September 30, 2000, the Company had repurchased 4.8% of
the shares currently issued.
The Board of Directors of Prima approved a three for two stock split of
the Company's common stock to shareholders of record on February 10, 2000,
distributed February 24, 2000. As a result, the number of shares of common stock
outstanding increased from 5,645,341 to 8,467,744 on the distribution date. All
share and per share amounts included in these financial statements have been
restated to show the retroactive effects of the stock split. During 2000, the
shareholders of Prima approved an amendment to Prima's Certificate of
Incorporation increasing the number of authorized shares of common stock from
12,000,000 shares to 18,000,000 shares.
5. EARNINGS PER SHARE
Basic net income per share is computed by dividing net income by the
weighted average common shares outstanding during the period. Diluted net income
per share includes the potential dilution that could occur upon exercise of
options to acquire common stock, 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
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<PAGE> 10
Company with the proceeds from the exercise of the options (which were assumed
to have been at the average market price of the common shares during the
reporting period).
The following table reconciles the numerator and denominator used in
the calculation of basic and diluted net income per share.
<TABLE>
<CAPTION>
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ---------
<S> <C> <C> <C>
Quarter Ended September 30, 2000:
Basic Net Income per Share ............... $ 5,569,000 8,500,856 $0.66
Effect of Stock Options .................. 393,777 =====
----------- ---------
Diluted Net Income per Share ............. $ 5,569,000 8,894,633 $0.63
=========== ========= =====
Quarter Ended September 30, 1999:
Basic Net Income per Share ............... $ 2,389,000 8,562,519 $0.28
Effect of Stock Options .................. 263,843 =====
----------- ---------
Diluted Net Income per Share ............. $ 2,389,000 8,826,362 $0.27
=========== ========= =====
Nine Months Ended September 30, 2000:
Basic Net Income per Share ............... $14,564,000 8,491,432 $1.72
Effect of Stock Options .................. 361,182 =====
----------- ---------
Diluted Net Income per Share ............. $14,564,000 8,852,614 $1.65
=========== ========= =====
Nine Months Ended September 30, 1999:
Basic Net Income per Share ............... $ 5,680,000 8,565,234 $0.66
Effect of Stock Options .................. 152,853 =====
----------- ---------
Diluted Net Income per Share ............. $ 5,680,000 8,718,087 $0.65
=========== ========= =====
</TABLE>
10
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Liquidity and Capital Resources
The Company's principal internal sources of liquidity are cash flows
generated from operating activities and existing cash and cash equivalents. Net
cash provided by operating activities for the nine months ended September 30,
2000 was $21,617,000 compared to $9,756,000 for the same nine month period of
1999. Net working capital at September 30, 2000 was $23,286,000 compared to
$21,408,000 at December 31, 1999. The Company received $170,000 and $27,604,000
in proceeds from the sales of oil and gas and other property during the nine
months ended September 30, 2000 and 1999, respectively. The 1999 proceeds
resulted primarily from the disposition of the Bonny Field assets as previously
reported.
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 $21,892,000 in property and equipment during the
nine months ended September 30, 2000, compared to $13,088,000 for the 1999 nine
month period. The Company expended $17,550,000 during the 2000 period for its
proportionate share of the costs of drilling, completing and refracturing wells,
$1,651,000 for undeveloped acreage, $205,000 for developed properties and
$2,486,000 for other property and equipment. Included in other property and
equipment is $1,347,000 of costs for gas gathering facilities owned by Arete
Gathering Company LLC, a new wholly owned subsidiary formed to pursue gathering
and mid-stream investment opportunities. These expenditures compare to
$7,707,000 for well costs, $3,227,000 for undeveloped acreage, $101,000 for
producing properties and $2,053,000 for other equipment in the 1999 nine month
period. The Company also expended $1,778,000 for the purchase of 103,317 shares
of treasury stock during the first nine months of 2000 compared to $1,791,000
for 180,953 treasury shares during the 1999 nine month period.
The Company continues to develop its core property in the Wattenberg
Field area of the Denver Basin. During the first nine months of 2000, the
Company drilled twenty wells (20.0 net) to the Codell Formation in this area.
Nineteen of these wells were successfully completed and placed on production.
The pay zone was faulted out in the 20th well, which has been temporarily
abandoned. Four additional Codell wells have been drilled to date in the fourth
quarter of 2000, with another eight wells planned by year-end.
Prima has also continued its successful fracture re-stimulation
("refrac") program in the Wattenberg area. During the nine months ended
September 30, 2000, Prima refrac'd 45 Codell wells (41.6 net), all of which are
currently producing. Five additional Codell wells have been refrac'd to date in
the fourth quarter, with another ten planned by year-end. In addition to the
refrac program, Prima recompleted new producing intervals in five gross and net
wells during the first three quarters of 2000, with another three recompletions
planned through year-end.
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The Company drilled 124 shallow coalbed methane ("CBM") wells in the
Powder River Basin of northeast Wyoming during the first nine months of 2000. Of
this total, 109 wells have been drilled at the Company's Stone's Throw Prospect,
located approximately 30 miles north of Gillette, Wyoming. The first phase of
the gathering system at Stone's Throw, which is owned and operated by Arete
Gathering Company, has been completed. Nine CBM wells were placed on production
October 9, 2000, and produced 300 to 400 Mcf of natural gas per day through
temporary compression facilities into the sales line until being shut-in on
November 8, 2000 for compression installation. The Company expects to install
three additional screw compressors and a 7,000 Mcf per day reciprocating
compressor over the next few weeks. These facilities are designed to deliver
natural gas into the sales line, which is currently under conversion to a high
pressure line. Concurrently, the Company is continuing the installation of
production and gathering facilities to hook-up additional wells at Stone's
Throw. The Company expects to have approximately 80 wells equipped and connected
to the permanent facilities by year end. Arete's system in this area is designed
to include a second 7,000 Mcf per day reciprocating compressor so that when all
facilities are installed and operational, the Company will have a system capable
of handling 14,000 Mcf per day at Stone's Throw.
The Company drilled and completed a 9,500 foot development well (100%
working interest) in the Cedar Draw area of the Powder River Basin of Wyoming
during the first quarter of 2000. A second 9,500 foot Cedar Draw well (50%
working interest), which spud on October 21, 2000, was completed as a dry hole.
The Company has spud a third well (50% working interest) on November 5, 2000,
which is currently drilling. A fourth well (50% working interest) is expected to
be drilled by year end.
The Company continues to participate in development of the Cave Gulch
area in the Wind River Basin of Wyoming. Prima participated in the drilling of
two non-operated wells during the first nine months of 2000. The Cave Gulch
4-19LAK, originally spud in July of 1998 and then converted to a relief well,
was re-entered in January 2000 to test the Frontier, Muddy and Lakota formations
at depths of 17,200 to 18,800 feet. This well, in which Prima has an 11.24%
working interest, is currently being tested. The Cave Gulch #20 (6% working
interest) was drilled to a depth of 9,176 feet during the second quarter of 2000
and placed on production during the third quarter of 2000.
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 acquisition,
drilling, completion and recompletion well costs, will be financed by funds
provided by operations, working capital, borrowings on the line of credit,
various cost-sharing arrangements, or from other financing alternatives.
Results of Operations
Quarters Ended September 30, 2000 and 1999
For the quarter ended September 30, 2000, the Company earned net income
of $5,569,000, or $0.63 per diluted share, on revenues of $13,264,000, compared
to net income of $2,389,000, or $0.27 per diluted share on revenues of
$8,076,000 for the comparable quarter of 1999. Expenses
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<PAGE> 13
were $5,345,000 for the 2000 third quarter compared to $4,887,000 for the 1999
third quarter. Revenues increased $5,188,000, or 64%, expenses increased
$458,000, or 9%, and net income increased $3,180,000, or 133%.
Oil and gas sales for the quarter ended September 30, 2000 were
$11,428,000 compared to $5,510,000 for the same quarter of 1999, an increase of
$5,918,000 or 107%. The Company's net natural gas production was 2,165,000 Mcf
and 1,755,000 Mcf for the third quarters of 2000 and 1999, respectively, an
increase of 410,000 Mcf or 23%. Its net oil production was 109,000 barrels
compared to 75,000 barrels for the same periods, an increase of 34,000 barrels
or 45%. The average price received for natural gas production for the third
quarter of 2000 was $3.73 per Mcf compared to $2.29 per Mcf for the third
quarter of 1999, an increase of $1.44 per Mcf or 63%. The average price received
for oil in the third quarter of 2000 was $30.80 per barrel compared to $19.88
per barrel for the third quarter of 1999, an increase of $10.92 per barrel or
55%. The Company did not hedge any of its production during the third quarter of
2000. During the third quarter of 1999, the Company hedged approximately 18% of
its natural gas production. Net hedging losses of $130,000 are included in oil
and gas revenues for this period, which decreased the average price received per
Mcf of natural gas by $0.07. No oil production was hedged during the third
quarter of 1999.
The Company's depletion of oil and gas properties was $1,443,000 or
$0.51 per Mcfe ($3.07 per BOE) on 2,817,000 equivalent Mcf (470,000 equivalent
barrels) produced during the third quarter of 2000, compared to $1,129,000 or
$0.51 per Mcfe ($3.07 per BOE) on 2,206,000 equivalent Mcf (368,000 equivalent
barrels) produced during the third quarter of 1999. Depreciation of other fixed
assets was $295,000 and $218,000 for the quarters ended September 30, 2000 and
1999, respectively, and is attributable to depreciation of service equipment,
furniture and equipment and buildings. Depreciation expense on these assets
increased $77,000, or 35%, due primarily to acquisitions of oilfield service
equipment.
Lease operating expenses ("LOE") were $655,000 for the quarter ended
September 30, 2000 compared to $544,000 for the quarter ended September 30,
1999, an increase of $111,000 or 20%. Ad valorem and production taxes were
$950,000 and $468,000 for the same periods, an increase of $482,000 or 103%.
Production taxes increase with higher production volumes and increased product
prices. Total lifting costs (LOE plus ad valorem and production taxes) were 14%
of oil and gas revenues and $0.57 per Mcfe ($3.42 per BOE) for the 2000 quarter
compared to 18% and $0.46 per Mcfe ($2.75 per BOE) for the 1999 quarter.
Oilfield services represent the revenues earned by Action Oilfield
Services, Inc. (Colorado) and Action Energy Services (Wyoming), wholly owned
subsidiaries. These revenues include well servicing fees from drilling,
completion and swab rigs, trucking, water hauling and rental equipment, and
other related activities. Revenues were $1,526,000 for the quarter ended
September 30, 2000 compared to $1,271,000 for the comparable quarter of 1999, an
increase of $255,000, or 20%. For the quarter ended September 30, 2000, 40% of
the fees billed by the service companies were for Company owned wells compared
to 29% for the quarter ended September 30, 1999. The Company's share of fees
paid to its service companies on Company owned properties and the costs
associated with providing the services are eliminated in consolidation. Costs of
oilfield services were $1,215,000 for the quarter ended September 30, 2000
compared to $795,000 for the same period of 1999, an increase of $420,000 or
53%.
Trading revenues and cost of trading represent the marketing of third
party natural gas by Prima Natural Gas Marketing, Inc., a wholly owned
subsidiary. The Company had no trading activity during the third quarter of
2000. Trading revenues were $929,000 for the quarter ended September 30, 1999
from the marketing of 552,000 MMBtus of natural gas. Costs of trading were
$1,253,000 for the 1999 quarter.
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<PAGE> 14
General and administrative expenses ("G&A"), net of third party
reimbursements, were $787,000 for the quarter ended September 30, 2000 compared
to $480,000 for the quarter ended September 30, 1999, an increase of $307,000 or
64%. In prior periods, the Company has presented management and operator fees as
revenue. Currently, these fees have been reclassified and presented as
reductions in G&A. Management and operator fees were $78,000 and $99,000 during
the quarter ended September 30, 2000 and 1999, respectively. The Company's G&A
costs have otherwise increased due to expansion of the Company's activities and
operations.
The provision for income taxes was $2,350,000 for the quarter ended
September 30, 2000 compared to $800,000 for the quarter ended September 30,
1999, an increase of $1,550,000 or 194%. The Company's effective tax rate
increased to 29.7% from 25.1%, primarily because income before income taxes
increased $4,730,000 or 148% for the 2000 quarter. The Company's effective tax
rates are less than statutory rates due to permanent differences in financial
and taxable income, consisting primarily of statutory depletion deductions and
Section 29 tax credits.
Nine Months Ended September 30, 2000 and 1999
For the nine months ended September 30, 2000, the Company earned net
income of $14,564,000, or $1.65 per diluted share, on revenues of $36,022,000,
compared to net income of $5,680,000, or $0.65 per diluted share, on revenues of
$20,322,000 for the nine months ended September 30, 1999. Expenses were
$15,538,000 for the 2000 nine month period compared to $12,732,000 for the 1999
nine month period. Revenues increased $15,700,000, or 77%, expenses increased
$2,806,000, or 22%, and net income increased $8,884,000, or 156%.
Oil and gas sales for the nine months ended September 30, 2000 were
$30,390,000 compared to $13,933,000 for the nine months ended September 30,
1999, an increase of $16,457,000 or 118%. The Company's net natural gas
production was 6,574,000 Mcf and 5,299,000 Mcf for the first nine months of 2000
and 1999, respectively, an increase of 1,275,000 Mcf or 24%. Its net oil
production was 333,000 barrels compared to 235,000 barrels for the same nine
month periods, an increase of 98,000 barrels or 42%. The average price received
for natural gas production was $3.18 per Mcf for the nine months ended September
30, 2000 compared to $1.95 per Mcf for the nine months ended September 30, 1999,
an increase of $1.23 per Mcf or 63%. The average price received for oil for the
first nine months of 2000 was $28.51 per barrel compared to $15.41 per barrel
for the same period of 1999, an increase of $13.10 per barrel or 85%. The
Company did not hedge any of its production during the nine months ended
September 30, 2000. During the nine months ended September 30, 1999, the Company
hedged approximately 39% of its oil production and 21% of its natural gas
production. Hedging losses of $116,000 were included in oil and gas sales for
the period and reduced the average price received per barrel of oil by $0.18 and
reduced the average price received per Mcf of natural gas by $0.01.
The Company's depletion of oil and gas properties was $4,386,000 or
$0.51 per Mcfe ($3.07 per BOE) on 8,571,000 equivalent Mcf (1,428,000 equivalent
barrels) produced during the first nine months of 2000, compared to $3,430,000
or $0.51 per Mcfe ($3.07 per BOE) on 6,707,000 equivalent Mcf (1,118,000
equivalent barrels) produced during the first nine months of 1999. Depreciation
of other fixed assets was $846,000 and $573,000 for the nine months ended
September 30, 2000 and 1999, respectively, an increase of $273,000, or 48%.
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<PAGE> 15
LOE was $1,910,000 for the nine months ended September 30, 2000 compared
to $1,576,000 for the nine months ended September 30, 1999, an increase of
$334,000 or 21%. Ad valorem and production taxes were $2,434,000 and $1,188,000
for the same periods, an increase of $1,246,000 or 105%. Total lifting costs
were 14% of oil and gas revenues and $0.51 per Mcfe ($3.04 per BOE) for the 2000
period compared to 20% and $0.41 per Mcfe ($2.47 per BOE) for 1999.
Oilfield services revenues were $4,710,000 for the nine months ended
September 30, 2000 compared to $3,377,000 for the comparable nine month period
of 1999, an increase of $1,332,000 or 39%. For the nine months ended September
30, 2000, 35% of the fees billed by the service companies were for Company owned
wells compared to 29% for the nine months ended September 30, 1999. Costs of
oilfield services were $3,833,000 for the nine months ended September 30, 2000
compared to $2,328,000 for the same period of 1999, an increase of $1,505,000 or
65%.
The Company had no trading activity during the nine months ended
September 30, 2000. Trading revenues were $2,010,000 for the nine months ended
September 30, 1999 from the marketing of 1,128,000 MMBtus of natural gas. Costs
of trading were $2,354,000 for the 1999 nine month period. Trading activities
fluctuate with natural gas markets and the Company's ability to identify markets
that meet the Company's trading criteria.
G&A was $2,129,000 for the nine months ended September 30, 2000 compared
to $1,283,000 for the nine months ended September 30, 1999, an increase of
$846,000 or 66%. Management and operator fees were $318,000 and $488,000 during
the nine months ended June 30, 2000 and 1999, respectively. Management fees
received from third parties have decreased as the Company has acquired
additional working interests in operated wells and sold interests in properties
it previously operated.
The provision for income taxes was $5,920,000 for the nine months ended
September 30, 2000 compared to $1,910,000 for the same nine month period of
1999. Income before income taxes increased $12,894,000 for the 2000 nine month
period and the effective tax rate increased to 28.9% from 25.2%.
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.
The Company's primary source of revenues is from the sale of oil and
natural gas production. Levels of revenues and earnings are affected by volumes
of oil and natural gas production and by the prices at which oil and natural gas
are sold. As a result, the Company's operating results for any period are not
necessarily indicative of future operating results because of fluctuations in
oil and natural gas prices and production volumes.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company's primary market risks relate to changes in the prices
received from sales of oil and natural gas. The Company's primary risk
management strategy is to partially mitigate the risk of adverse changes in its
cash flows caused by decreases in oil and natural gas prices by entering into
derivative commodity instruments, including commodity futures contracts and
price swaps. By hedging only a portion of its market risk exposures, the Company
is able to participate in the increased earnings and cash flows associated with
increases in oil and natural gas prices; however, it is exposed to risk on the
unhedged portion of its oil and natural gas production.
Historically, the Company has attempted to hedge the exposure related to
its forecasted oil and natural gas production in amounts which it believes are
prudent based on the prices of available derivatives and, in the case of
production hedges, the Company's deliverable volumes. The Company does not use
or hold derivative instruments for trading purposes nor does it use derivative
instruments with leveraged features. The Company's derivative instruments are
designed and effective as hedges against its identified risks, and do not of
themselves expose the Company to market risk because any adverse change in the
cash flows associated with the derivative instrument is accompanied by an
offsetting change in the cash flows of the hedged transaction.
Note 4 to the unaudited consolidated financial statements provides
further disclosure with respect to derivatives and related accounting policies.
All derivative activity is carried out by personnel who have appropriate
skills, experience and supervision. The personnel involved in derivative
activity must follow prescribed trading limits and parameters that are regularly
reviewed by the Company's Chief Executive Officer. All hedges or open positions
are reviewed by the Chief Executive Officer before they are committed to, and
significant positions are reviewed by the Company's Board of Directors. The
Company uses only well-known, conventional derivative instruments and attempts
to manage its credit risk by entering into financial contracts with reputable
financial institutions.
Following are disclosures regarding the Company's market risk
instruments. Investors and other users are cautioned to avoid simplistic use of
these disclosures. Users should realize that the actual impact of future
commodity price movements will likely differ from the amounts disclosed below
due to ongoing changes in risk exposure levels and concurrent adjustments to
hedging positions. It is not possible to accurately predict future movements in
oil and natural gas prices.
The Company periodically hedges a portion of the price risk associated
with the sale of its oil and natural gas production through the use of
derivative commodity instruments, which consist of commodity futures contracts
and price swaps. These instruments reduce the Company's exposure to decreases in
oil and natural gas prices on the hedged portion of its production by enabling
it to effectively receive a fixed price on its oil and natural gas sales. As of
November 1, 2000, the Company had no derivative positions in place.
During the first nine months of 2000, the Company sold 333,000 barrels
of oil. A hypothetical decrease of $2.85 per barrel (10% of average prices for
the period) would have decreased the Company's production revenues by $948,000
for the period. The Company sold 6,574,000 Mcf of natural gas during the same
period. A hypothetical decrease of $0.32 per Mcf (10% of average prices for the
period) would have decreased the Company's production revenues by $2,104,000 for
the period.
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CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
"Managements Discussion and Analysis of Financial Condition and Results
of Operations" included in Item 2 of this Report 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 liquidity, financing of operations, capital
expenditures (both the amount and the source of funds), continued volatility of
oil and natural gas prices, future drilling plans and other such matters. The
words "anticipates," "intends," "expects" "plans," or "believes" and similar
expressions identify forward-looking statements. Such statements are based on
certain assumptions and analyses made by the Company in light of its experience
and its perception of historical trends, current conditions, expected future
developments and other factors it believes are appropriate in the circumstances.
Prima does not undertake to update, revise or correct any of the forward-looking
information. Factors that could cause actual results to differ materially from
the Company's expectations expressed in the forward-looking statements include,
but are not limited to, the following: industry conditions, including
availability of drilling rigs and other equipment and services; volatility of
oil and natural gas prices; hedging activities; the ability to obtain drilling,
water discharge and air quality permits; operational risks (such as blowouts,
fires and loss of production); insurance coverage limitations; potential
liability imposed by government regulation (including environmental regulation);
the need to develop and replace its oil and natural gas reserves; the
substantial capital expenditures required to recover its operations; risks
related to exploration and developmental drilling; and uncertainties about oil
and natural gas reserve estimates. For a more complete explication of these
various factors, see "Cautionary Statement for the Purposes of the 'Safe Harbor'
Provisions of the Private Securities Litigation Reform Act of 1995" included in
the Company's Annual Report on Form 10-K for the year ended December 31, 1999
beginning on page 17.
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PART II OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibits are filed herewith pursuant to rule 601 of
Regulation S-K.
3.1 Certificate of Amendment of the Certificate of
Incorporation of Prima Energy Corporation
27.1 Financial Data Schedules
(b) Reports on Form 8-K
No reports on Form 8-K were filed during the Registrants' fiscal quarter
ended September, 30, 2000.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PRIMA ENERGY CORPORATION
(Registrant)
Date November 9, 2000 By /s/ Richard H. Lewis
---------------- ---------------------------
Richard H. Lewis,
President and
Principal Financial Officer
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INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
-------- -----------
<S> <C>
3.1 Certificate of Amendment of the Certificate of Incorporation of
Prima Energy Corporation
27.1 Financial Data Schedules
</TABLE>
