<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, 1999
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 Identification No.)
incorporation or organization)
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, 1999, the Registrant had 5,720,031 shares of Common Stock,
$0.015 Par Value, outstanding.
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<PAGE> 2
PRIMA ENERGY CORPORATION
INDEX
<TABLE>
<CAPTION>
Page
----
PART I - FINANCIAL INFORMATION
<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 ............................................. 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk ................................. 18
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995 ............................................. 19
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K .......................................................... 20
Signatures ......................................................................................... 21
</TABLE>
<PAGE> 3
PART I. FINANCIAL INFORMATION
ITEM I. FINANCIAL STATEMENTS
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------ ------------
(Unaudited)
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents ......................... $ 25,623,000 $ 2,522,000
Available for sale securities, at market .......... 2,060,000 2,391,000
Receivables (net of allowance for doubtful
accounts: 9/30/99, $47,000; 12/31/98, $47,000)... 4,573,000 4,696,000
Tubular goods inventory ........................... 570,000 612,000
Other ............................................. 520,000 452,000
------------ ------------
Total current assets ........................ 33,346,000 10,673,000
------------ ------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method .................. 70,112,000 86,081,000
Less accumulated depreciation,
depletion and amortization ...................... (36,565,000) (33,135,000)
------------ ------------
Oil and gas properties - net ................ 33,547,000 52,946,000
------------ ------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ........................ 6,190,000 4,353,000
Furniture and equipment ........................... 646,000 815,000
Field offices, shops and land ..................... 473,000 439,000
------------ ------------
7,309,000 5,607,000
Less accumulated depreciation ..................... (3,144,000) (2,946,000)
------------ ------------
Property and equipment - net ................ 4,165,000 2,661,000
------------ ------------
OTHER ASSETS ...................................... 257,000 586,000
------------ ------------
$ 71,315,000 $ 66,866,000
============ ============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
3
<PAGE> 4
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------ ------------
(Unaudited)
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable .......................................... $ 631,000 $ 2,122,000
Amounts payable to oil and gas property owners ............ 1,695,000 973,000
Production taxes payable .................................. 1,351,000 1,552,000
Income taxes payable ...................................... 4,986,000 0
Accrued and other liabilities ............................. 331,000 439,000
Current portion of note payable ........................... 304,000 120,000
------------ ------------
Total current liabilities ........................... 9,298,000 5,206,000
NOTE PAYABLE .............................................. 0 120,000
PRODUCTION TAXES, non-current ............................. 1,033,000 1,088,000
DEFERRED TAX LIABILITY .................................... 4,857,000 9,144,000
------------ ------------
Total liabilities ................................... 15,188,000 15,558,000
------------ ------------
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, 12,000,000 shares
authorized; 5,925,556 and 5,835,556 shares issued ...... 89,000 87,000
Additional paid-in capital ................................ 5,542,000 4,417,000
Retained earnings ......................................... 53,230,000 47,550,000
Unrealized gain (loss) on available for sale securities ... (146,000) 51,000
Treasury stock - 185,277 and 63,787 shares, at cost ....... (2,588,000) (797,000)
------------ ------------
Total stockholders' equity .......................... 56,127,000 51,308,000
------------ ------------
$ 71,315,000 $ 66,866,000
============ ============
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
4
<PAGE> 5
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales ....................... $ 5,510,000 $ 4,034,000 $13,933,000 $12,310,000
Oilfield services ....................... 1,271,000 910,000 3,377,000 3,027,000
Trading revenues ........................ 929,000 655,000 2,010,000 3,235,000
Management and operator fees ............ 99,000 269,000 488,000 783,000
Interest and dividend income ............ 358,000 104,000 964,000 375,000
Other ................................... 8,000 5,000 38,000 3,862,000
----------- ----------- ----------- -----------
8,175,000 5,977,000 20,810,000 23,592,000
----------- ----------- ----------- -----------
EXPENSES
Depreciation, depletion and amortization 1,347,000 1,646,000 4,003,000 4,785,000
Lease operating expense ................. 544,000 503,000 1,576,000 1,524,000
Production taxes ........................ 468,000 289,000 1,188,000 953,000
Cost of oilfield services ............... 795,000 632,000 2,328,000 2,089,000
Cost of trading ......................... 1,253,000 733,000 2,354,000 3,177,000
General and administrative .............. 579,000 571,000 1,771,000 1,548,000
----------- ----------- ----------- -----------
4,986,000 4,374,000 13,220,000 14,076,000
----------- ----------- ----------- -----------
INCOME BEFORE INCOME TAXES .............. 3,189,000 1,603,000 7,590,000 9,516,000
PROVISION FOR INCOME TAXES .............. 800,000 353,000 1,910,000 2,658,000
----------- ----------- ----------- -----------
NET INCOME .............................. $ 2,389,000 $ 1,250,000 $ 5,680,000 $ 6,858,000
=========== =========== =========== ===========
BASIC NET INCOME PER SHARE .............. $ 0.42 $ 0.22 $ 0.99 $ 1.19
=========== =========== =========== ===========
DILUTED NET INCOME PER SHARE ............ $ 0.41 $ 0.21 $ 0.98 $ 1.16
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING .................... 5,706,636 5,772,556 5,708,774 5,771,796
=========== =========== =========== ===========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING
ASSUMING DILUTION ..................... 5,868,740 5,903,492 5,818,933 5,909,711
=========== =========== =========== ===========
</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,
------------------------------ ------------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Net income ........................ $ 2,389,000 $ 1,250,000 $ 5,680,000 $ 6,858,000
----------- ----------- ----------- -----------
Other comprehensive income:
Unrealized gain (loss) on
available-for-sale securities .. (83,000) 1,000 (316,000) 1,000
Deferred income tax expense related
to unrealized gain (loss) on
available-for-sale securities .. 32,000 0 119,000 0
----------- ----------- ----------- -----------
(51,000) 1,000 (197,000) 1,000
----------- ----------- ----------- -----------
COMPREHENSIVE INCOME .............. $ 2,338,000 $ 1,251,000 $ 5,483,000 $ 6,859,000
=========== =========== =========== ===========
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
6
<PAGE> 7
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
Nine Months Ended
September 30,
--------------------------------
1999 1998
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES
Net income ............................................. $ 5,680,000 $ 6,858,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ............ 4,003,000 4,785,000
Deferred income taxes ............................... 1,738,000 1,904,000
Current taxes from sale of oil and gas properties ... (5,704,000) 0
Other ............................................... (12,000) (81,000)
Changes in operating assets and liabilities:
Receivables ....................................... 123,000 1,829,000
Inventory ......................................... 42,000 154,000
Other current assets .............................. 33,000 (152,000)
Accounts payable and payables to owners ........... (769,000) (2,376,000)
Production taxes payable .......................... (256,000) (271,000)
Income taxes payable .............................. 4,986,000 0
Accrued and other liabilities ..................... (108,000) (76,000)
------------ ------------
Net cash provided by operating activities ....... 9,756,000 12,574,000
------------ ------------
INVESTING ACTIVITIES
Proceeds from sales of oil and gas and other property... 27,604,000 146,000
Additions to oil and gas properties .................... (11,035,000) (11,599,000)
Purchases of other property ............................ (2,053,000) (944,000)
Purchases of available for sale securities ............. (83,000) (491,000)
------------ ------------
Net cash provided by (used in) investing
activities .................................... 14,433,000 (12,888,000)
------------ ------------
FINANCING ACTIVITIES
Proceeds from issuance of common stock ................. 823,000 23,000
Treasury stock purchased ............................... (1,791,000) 0
Repayment of long-term debt ............................ (120,000) (120,000)
------------ ------------
Net cash used in financing activities .......... (1,088,000) (97,000)
------------ ------------
INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS .................................... 23,101,000 (411,000)
CASH AND CASH EQUIVALENTS, beginning of period ......... 2,522,000 5,644,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ............... $ 25,623,000 $ 5,233,000
============ ============
</TABLE>
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,
1998. 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, 1999. 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, 1999 and 1998 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, 1999.
2. NOTES PAYABLE AND LINE OF CREDIT
The Company's notes payable consist of the following:
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
------------- -------------
<S> <C> <C>
Total ............................ $ 304,000 $ 240,000
Less, current portion....... 304,000 120,000
------------- -------------
Long term .................. $ 0 $ 120,000
============= =============
</TABLE>
The Company has two notes payable at September 30, 1999. The first note is
dated June 10, 1997 and is due on June 10, 2000. Payments of principal and
accrued interest (8% per annum) 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 balance was $120,000 at September 30, 1999. The second note
is for $184,000. It is dated March 10, 1999 and is due in one annual installment
of principal and accrued interest (8% per annum) on March 10, 2000. The note
financed the purchase of oilfield service equipment by Action Energy Services, a
newly formed wholly owned subsidiary.
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 (8.25% at September 30, 1999), with interest payable monthly.
At December 31, 1998 and September 30, 1999, there were no amounts outstanding
under the line of credit.
8
<PAGE> 9
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 hedged approximately 39% of its oil production for the first
nine months of 1999. No oil was hedged for this period of 1998. The Company
hedged approximately 21% and 46% of its natural gas production for the first
nine months of 1999 and 1998, respectively. Net hedging losses were $116,000 and
$77,000 for the nine months ended September 30, 1999 and 1998, respectively, and
were included in oil and gas revenues at the time the hedged volumes were sold.
At September 30, 1999, the Company had the following derivative positions in
place:
<TABLE>
<CAPTION>
Volume Fixed Unrealized
Type of Derivative (barrels) Price Term Gain (Loss)
- -------------------------------- ------------- ------------- ------------------ ---------------
<S> <C> <C> <C> <C>
Crude oil futures contracts 5,000 $ 23.18 November 1999 $ (6,650)
Crude oil futures contracts 5,000 22.90 December 1999 (6,200)
Crude oil call options sold 5,000 24.50 November 1999 (900)
Crude oil call options sold 5,000 24.50 December 1999 (850)
</TABLE>
Additionally, Prima Natural Gas Marketing, Inc., a wholly owned subsidiary of
the Company, sold physical volumes of 6,000 MMBtu per day at fixed prices for
October 1999, which had unrealized losses of $156,000 at September 30, 1999.
These sales are reflected as trading revenues and cost of trading in the
accompanying income statement when the physical transaction occurs. At November
1, 1999, the Company had no hedges in place which extend beyond December of 1999
and had no commitments in its marketing subsidiary. At September 30 and November
1, 1999, the Company had no open futures transactions that did not correspond to
anticipated physical transactions.
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. The Company has not completed the process of evaluating the impact that
will result from adopting SFAS 133.
9
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4. COMMON STOCK
Pursuant to the provisions of the Prima Energy Corporation 1993 Stock
Incentive Plan, 90,000 shares of Prima's common stock were issued upon the
exercise of stock options during the nine months ended September 30, 1999, for
total proceeds of $823,000.
During the nine months ended September 30, 1999, the Company repurchased
121,490 shares of its common stock for $1,791,000 as treasury stock pursuant to
a stock repurchase program whereby 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.
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
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, 1999:
Basic Net Income per Share ..... $2,389,000 5,706,636 $ 0.42
==========
Effect of Stock Options ........ 162,104
---------- ----------
Diluted Net Income per Share ... $2,389,000 5,868,740 $ 0.41
========== ========== ==========
Quarter Ended September 30, 1998:
Basic Net Income per Share ..... $1,250,000 5,772,556 $ 0.22
==========
Effect of Stock Options ........ 130,936
---------- ----------
Diluted Net Income per Share ... $1,250,000 5,903,492 $ 0.21
========== ========== ==========
Nine Months Ended September 30, 1999:
Basic Net Income per Share ..... $5,680,000 5,708,774 $ 0.99
==========
Effect of Stock Options ........ 110,159
---------- ----------
Diluted Net Income per Share ... $5,680,000 5,818,933 $ 0.98
========== ========== ==========
Nine Months Ended September 30, 1998:
Basic Net Income per Share ..... $6,858,000 5,771,796 $ 1.19
==========
Effect of Stock Options ........ 137,915
---------- ----------
Diluted Net Income per Share ... $6,858,000 5,909,711 $ 1.16
========== ========== ==========
</TABLE>
10
<PAGE> 11
6. SALE OF OIL AND GAS PROPERTIES
The Company sold certain of its oil and gas properties and related assets
on January 21, 1999, for approximately $26 million. The assets sold consisted of
all of the Company's interest in 16,253 gross acres and 135 producing wells and
related equipment in the Bonny Field in Yuma County, Colorado. Prima also sold
its 15.5% interest in the Bonny Gathering Company joint venture, which owned the
pipeline, gathering, compression and dehydration facilities at the Bonny Field.
Prima had served as the managing venturer and operator of Bonny Gathering
Company since initial development of the field in 1982.
The Company has accounted for the sale of the producing wells and leasehold
interests as a credit to the carrying value of its oil and gas properties, as
the properties sold were less than 25% of the Company's proved reserves. The
estimated federal and state income taxes due of approximately $5.7 million have
been reflected in the accompanying balance sheet as a current liability, net of
estimated payments.
11
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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,
1999 was $9,756,000 compared to $12,574,000 for the same nine month period of
1998. Net working capital at September 30, 1999 was $24,048,000 compared to
$5,467,000 at December 31, 1998. The increase in working capital of $18,581,000
was primarily generated by sales of oil and gas properties and by cash flows
from operations during the nine months ended September 30, 1999. The Company
also received proceeds from the exercise of stock options of $823,000 and
proceeds from the sales of securities and other assets of $601,000 during the
period. Cash flow from operations in 1998 benefited from a contract settlement
payment of $3,850,000, due to the early termination of a gas supply contract.
The Company has external borrowing capacity of $8,000,000 through an unsecured
line of credit with a commercial bank, all of which is available to be drawn.
On January 21, 1999, Prima closed on the sale of all of its interest in the
Bonny Field acreage, wells and gathering system for approximately $26 million.
Proceeds were credited against oil and gas properties with no gain recognition
in accordance with generally accepted accounting principles. Prima placed the
proceeds from this sale in a like-kind exchange escrow account with a qualified
intermediary. Prima did not close on any of the identified qualifying properties
pursuant to the like-kind exchange provisions of Section 1031 of the Internal
Revenue Code. The funds were disbursed from the escrow account in July 1999 and
will be subject to federal and state income taxes of approximately $5.7 million
after utilization of minimum tax credit carryforwards. This liability has been
reflected as a current liability, net of estimated payments, in the accompanying
balance sheet.
The Company invested $13,088,000 in property and equipment during the nine
months ended September 30, 1999 compared to $12,543,000 for the 1998 nine month
period. The Company expended $7,707,000 during the 1999 nine month period for
its proportionate share of the costs of drilling, completing and recompleting or
restimulating wells, $3,227,000 for purchases of undeveloped acreage, $101,000
for purchases of producing properties and $2,053,000 for other property and
equipment. These expenditures compare to $8,384,000 for well costs, $2,835,000
for undeveloped acreage, $380,000 for producing properties and $944,000 for
other property and equipment in the 1998 nine month period. The Company also
expended $1,791,000 for purchases of treasury stock during the first nine months
of 1999.
During the first nine months of 1999, the Company refractured or
recompleted 38 gross (31.64 net) wells in the Wattenberg Field Area of the
Denver Basin. All of these operations have been successfully completed and the
wells are back on production. The Company plans to refrac an additional 25 wells
during the remainder of 1999. As of November 5, 1999, ten additional refracs
(10.0 net) had been successfully completed. Production increases have averaged
180 Mcf of natural gas and 10 barrels of oil per day. In October of 1999, the
Company commenced a 15 - 25 well drilling program in the Wattenberg Field. Four
wells (3.95 net) were drilled during the month, with three on production and one
waiting on completion. The Company currently anticipates drilling the balance of
the wells in this area over the next few months. On its leases at Denver
12
<PAGE> 13
International Airport, the Company drilled two new wells (2.0 net) in August
1999. As of November 5, 1999, the wells had been placed on production and were
still cleaning up.
During the nine months ended September 30, 1999, the Company drilled three
(2.75 net) operated wells to the Muddy Formation in the Powder River Basin of
Wyoming. One well was completed and is producing, one is waiting on completion
and one has been plugged and abandoned. In October, the Company participated in
two (0.45 net) non-operated wells in this area. Both wells had been drilled and
cased and were waiting on completion as of November 5, 1999.
To date, the Company has drilled fifteen coalbed methane test wells in the
Powder River Basin of Wyoming. These wells were drilled to enable the Company to
begin to test and evaluate its acreage. The Company anticipates drilling
additional test wells and beginning multi-well test pods during the remainder of
1999 and into 2000. The number of wells and timing thereof will be dependent to
a great extent on the Company's ability to obtain drilling and water discharge
permits consistent with the Company's evaluation and development plans. The
Bureau of Land Management ("BLM") has stated the Record of Decision will be
issued in mid-November 1999 on the Wyodak Environmental Impact Study ("EIS").
In early November 1999, the BLM has stated it has received more
Applications for Permits to Drill ("APDs") on federal acreage than it will be
able to process and issue, and will no longer accept APDs on all oil and gas
wells in the Buffalo field office effective November 9, 1999. Currently filed
APDs, when combined with state and fee wells, exceed the 5,890 wells analyzed
and provided for in the Wyodak EIS and the Buffalo Resource Management Plan
("RMP"). Only a portion of the existing coalbed methane applications on federal
acreage will be approved based on the results of the coalbed methane lottery
system and confirmed drainage cases. BLM has stated that it is currently
evaluating various methods, including updating of the Buffalo RMP, to continue
future oil and gas development on federal acreage. The process is expected to be
determined in the near future.
The Company continues to acquire acreage in this burgeoning play, where it
has approximately 136,000 acres under lease as of the date of this report,
including 36,000 acres acquired in 1999. Within the Wyodak EIS study area, the
Company holds 107,000 acres, of which 77% is federal and 23% is fee or state.
The Wyoming Oil and Gas Commission is continuing to issue drilling permits on
fee and state lands.
The Company continues to participate in the development of the Cave Gulch
area in the Wind River Basin of Wyoming. During the nine months ended September
30, 1999, Prima participated in the drilling of six (0.37 net) non-operated
wells and the recompletions of three (0.18 net) non-operated wells. As of
November 5, 1999, the three recompletions were all back on production. Of the
six new wells, three were producing, two were waiting on completion and one was
waiting on pipeline hook-up. The Cave Gulch 1-29 LAK, which blew out in August
of 1998, was salvaged and placed back on production in October 1999. The well
was producing at a rate of approximately 11 MMcf per day. Prima owns a 4.57%
working interest and 3.69% net revenue interest in this well.
During March of 1999, the Company formed a new subsidiary oilfield service
company, Action Energy Services ("AES"). AES is a Wyoming corporation formed to
provide services for Prima and other parties in the Powder River Basin area. AES
acquired the assets of Star Drilling
13
<PAGE> 14
Company for $460,000 and other service equipment for $1,349,000 during the first
nine months of 1999. AES generated its first revenues during the second quarter
of this year.
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.
Year 2000 Compliance Program
The Year 2000 Issue is the result of computer applications being written
using two digits rather than four to define the applicable year. As the year
2000 approaches, such applications may be unable to accurately process certain
date-based information. The Company believes it has identified the significant
internal computer applications that required modification to ensure Year 2000
compliance. The Company has completed its identified modifications and is
continuing to test compliance.
An assessment of the readiness of third parties with whom the Company does
business, such as customers and vendors, is substantially complete. Third
parties with whom the Company has material relationships have been contacted
regarding their Year 2000 issues and responses were monitored to determine the
potential effect on Prima. Upon review of these responses, the Company is not
aware of any third party issues that would cause a significant disruption of its
business or operations. If any subsequent information is received from any
significant third party indicating that they will not be Year 2000 compliant, it
may be necessary to develop contingency plans to minimize any negative impact to
the Company.
The failure to correct a material Year 2000 problem could result in an
interruption in, or failure of, certain normal business activities or
operations. Such failures could materially and adversely affect the Company's
results of operations, liquidity and financial condition. The Company's program
has significantly reduced the Company's level of uncertainty about Year 2000
issues and, in particular, about Year 2000 compliance and readiness of its third
party vendors and associates. The Company believes that, with the modification
of its business systems and completion of its assessment program as scheduled,
the possibility of significant interruptions of normal operations should be
minimal. The cost of Year 2000 compliance has not been specifically tracked but
has not been material to the Company's financial position or results of
operations.
To mitigate Year 2000 compliance issues at year end, the Company will back
up all internal computer data to ensure the ability to restore that information.
The Company will have hard copies of all important internal computer information
and hard copies of the detail of any assets held by third parties such as banks
and investment brokers. If the Company is unable to produce its wells or
transport or sell its production due to Year 2000 compliance issues, wells will
be shut-in until normal operations can be resumed.
Results of Operations
For the quarter ended September 30, 1999, the Company earned net income of
$2,389,000, or $.41 per diluted share, on revenues of $8,175,000, compared to
net income of $1,250,000, or
14
<PAGE> 15
$.21 per diluted share on revenues of $5,977,000 for the comparable quarter of
1998. Expenses were $4,986,000 for the 1999 third quarter compared to $4,374,000
for the 1998 third quarter. Revenues increased $2,198,000, or 37%, expenses
increased $612,000, or 14%, and net income increased $1,139,000, or 91%.
For the nine months ended September 30, 1999, the Company earned net income
of $5,680,000, or $0.98 per diluted share, on revenues of $20,810,000, compared
to net income of $6,858,000, or $1.16 per diluted share on revenues of
$23,592,000 for the nine months ended September 30, 1998. Expenses were
$13,220,000 for the 1999 nine month period compared to $14,076,000 for the 1998
nine month period. Revenues decreased $2,782,000, or 12%, expenses decreased
$856,000, or 6%, and net income decreased $1,178,000, or 17%. During the first
quarter of 1998, the Company recorded non-recurring revenues of $3,850,000
($2,500,000 after taxes) from the early termination of a gas sales agreement.
Oil and gas sales for the quarter ended September 30, 1999 were $5,510,000
compared to $4,034,000 for the same quarter of 1998, an increase of $1,476,000
or 37%. The Company's net natural gas production was 1,755,000 Mcf and 1,662,000
Mcf for the third quarters of 1999 and 1998, respectively, an increase of 93,000
Mcf or 6%. Its net oil production was 75,000 barrels compared to 69,000 barrels
for the same periods, an increase of 6,000 barrels or 9%. The average price
received for natural gas production for the third quarter of 1999 was $2.29 per
Mcf compared to $1.91 per Mcf for the third quarter of 1998, an increase of $.38
per Mcf or 20%. Approximately 5% of natural gas production for the three months
ended September 30, 1998 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 $1.69 per Mcf for
the 1998 quarter. The wells subject to the fixed price contract were sold by the
Company effective January 1, 1999. The average price received for oil in the
third quarter of 1999 was $19.88 per barrel compared to $12.47 per barrel for
the third quarter of 1998, an increase of $7.41 per barrel or 59%. 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. During the third quarter of 1998, the Company hedged approximately
44% of its natural gas production. Net hedging gains of $116,000 are included in
oil and gas revenues for this period, which increased the average price received
per Mcf of natural gas by $0.07. No oil production was hedged during either
quarter.
Oil and gas sales for the nine months ended September 30, 1999 were
$13,933,000 compared to $12,310,000 for the nine months ended September 30,
1998, an increase of $1,623,000 or 13%. The Company's net natural gas production
was 5,299,000 Mcf and 4,819,000 Mcf for the first nine months of 1999 and 1998,
respectively, an increase of 480,000 Mcf or 10%. Its net oil production was
235,000 barrels compared to 208,000 barrels for the same nine month periods, an
increase of 27,000 barrels or 13%. The average price received for natural gas
production was $1.95 per Mcf for the nine months ended September 30, 1999
compared to $1.98 per Mcf for the nine months ended September 30, 1998, a
decrease of $0.03 per Mcf or 2%. Approximately 5% of the natural gas production
for the nine months ended September 30, 1998 was attributable to production sold
under the fixed contract price of $5.90 per MMBtu. The average price received
for the Company's natural gas production exclusive of the fixed price contract
gas was $1.78 per Mcf for the nine months ended September 30, 1998. The average
price received for oil for the first nine months of 1999 was $15.41 per barrel
compared to $13.35 per barrel for the same
15
<PAGE> 16
period of 1998, an increase of $2.06 per barrel or 15%. 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 are
included in oil and gas revenues for this period, which decreased the average
price received per barrel of oil by $0.18 and the average price per Mcf of
natural gas by $0.01. During the nine months ended September 30, 1998, the
Company hedged approximately 46% of its natural gas production. Hedging losses
of $77,000 are included in oil and gas revenues for this period, which decreased
the average price received per Mcf of natural gas by $0.02. No oil was hedged
during this period.
Lease operating expenses and production taxes ("LOE") were $1,012,000 for
the third quarter of 1999 compared to $792,000 for the 1998 quarter, an increase
of $220,000 or 28%. Production taxes increased due to higher product prices.
Depreciation, depletion and amortization ("DD&A") was $1,347,000 and $1,646,000
for the same periods, a decrease of $299,000 or 18%. Production for the quarter
ended September 30, 1999 was 368,000 barrels of oil equivalent ("BOE") compared
to 345,000 BOE for the quarter ended September 30, 1998, an increase of 23,000
BOE or 7%. LOE per equivalent barrel of production was $2.75 for the third
quarter of 1999 compared to $2.29 for the comparable quarter of 1998, primarily
due to higher production taxes. DD&A applicable to oil and gas properties was
$3.07 per equivalent barrel of production for the 1999 period compared to $4.30
per equivalent barrel of production for the 1998 period. The DD&A rate is lower
in 1999 due to the lower net carrying value of oil and gas properties resulting
from the crediting of proceeds from the sale of the Bonny wells to the full cost
pool. Depreciation of other property and equipment was $217,000 and $162,000 for
the quarters ended September 30, 1999 and 1998, respectively.
LOE was $2,764,000 for the nine months ended September 30, 1999 compared to
$2,477,000 for the 1998 period, an increase of $287,000 or 12%. DD&A was
$4,003,000 and $4,785,000 for the same periods, a decrease of $782,000 or 16%.
Production for the nine months ended September 30, 1999 was 1,118,000 BOE
compared to 1,011,000 BOE for the nine months ended September 30, 1998, an
increase of 107,000 BOE or 11%. LOE per equivalent barrel of production was
$2.47 for the first nine months of 1999 compared to $2.45 for the comparable
period of 1998. DD&A applicable to oil and gas properties was $3.07 per
equivalent barrel of production for the 1999 period compared to $4.30 per
equivalent barrel of production for the 1998 period. Depreciation of other
property and equipment was $572,000 and $439,000 for the nine months ended
September 30, 1999 and 1998, respectively.
Oilfield services represent the revenues earned by Action Oilfield
Services, Inc. and Action Energy Services, wholly owned subsidiaries. These
revenues include well servicing fees from completion and swab rigs, trucking,
water hauling and rental equipment, and other related activities. Revenues were
$1,271,000 for the quarter ended September 30, 1999 compared to $910,000 for the
comparable quarter of 1998, an increase of $361,000, or 40%. For the quarter
ended September 30, 1999, 29% of the fees billed by the service companies were
for Company owned wells compared to 27% for the quarter ended September 30,
1998. Costs of oilfield services were $795,000 for the quarter ended September
30, 1999 compared to $632,000 for the same period of 1998, an increase of
$163,000 or 26%.
Oilfield services revenues were $3,377,000 for the nine months ended
September 30, 1999 compared to $3,027,000 for the comparable nine month period
of 1998, an increase of $350,000 or 12%. For the nine months ended September 30,
1999, 25% of the fees billed by the service
16
<PAGE> 17
companies were for Company owned wells compared to 20% for the nine months ended
September 30, 1998. Costs of oilfield services were $2,328,000 for the nine
months ended September 30, 1999 compared to $2,089,000 for the same period of
1998, an increase of $239,000 or 11%. 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.
Trading revenues and cost of trading represent the marketing of third party
natural gas by Prima Natural Gas Marketing, Inc., a wholly owned subsidiary.
Trading revenues were $929,000 for the three months ended September 30, 1999, an
increase of $274,000 or 42% from the $655,000 reported for the three months
ended September 30, 1998. The Company marketed 552,000 MMBtus for the third
quarter of 1999 compared to 369,000 MMBtus marketed during the comparable
quarter of 1998. Costs of trading were $1,253,000 for the 1999 quarter compared
to $733,000 for the 1998 quarter, an increase of $520,000 or 71%.
Trading revenues were $2,010,000 for the nine months ended September 30,
1999, a decrease of $1,225,000 or 38% from the $3,235,000 reported for the nine
months ended September 30, 1998. The Company marketed 1,128,000 MMBtus for the
nine month period of 1999 compared to 1,468,000 MMBtus marketed during the
comparable period of 1998. Costs of trading were $2,354,000 for the 1999 nine
month period compared to $3,177,000 for the 1998 nine month period, a decrease
of $823,000 or 26%. Trading activities fluctuate with natural gas markets and
the Company's ability to develop markets that meet the Company's trading
criteria. The Company contracted to sell gas at fixed prices and has purchased
the gas at higher spot prices, resulting in the losses for both the quarter and
year to date. The Company will report trading losses of approximately $156,000
in October 1999, at which point the contracts expire. The Company currently has
no trading purchase or sell agreements beyond October 1999.
Management and operator fees are earned pursuant to the Company's roles as
operator for approximately 365 oil and natural gas wells located primarily in
the Wattenberg Field area of Weld County, Colorado, and, until January 1, 1999,
as managing venturer of a joint venture which owned gas gathering and pipeline
facilities in the Bonny Field in Yuma County, Colorado. The Company is a working
interest owner in each of the operated wells. The Company is paid operating and
management fees by the other working interest owners in the properties. Fees
fluctuate with the number of wells operated, the percentage working interest in
a property owned by third parties, and the amount of drilling activity during
the period. Fees for the quarter ended September 30, 1999 were $99,000 compared
to $269,000 for the 1998 quarter, a decrease of $170,000 or 63%. Fees for the
nine months ended September 30, 1999 were $488,000 compared to $783,000 for the
1998 nine month period, a decrease of $295,000 or 38%. In January 1999, the
Company sold its interest in the Bonny Field assets, but continued to provide
various services to the new owner through March 31, 1999, after which time the
Company no longer earns management fees from the Bonny Field. Management and
operator fees attributable to the Bonny Field system were $66,000 and $304,000
for the nine months ended September 30, 1999 and 1998, respectively.
General and administrative expenses ("G&A") were $579,000 for the quarter
ended September 30, 1999 compared to $571,000 for the quarter ended September
30, 1998, an increase of $8,000 or 1%. G&A was $1,771,000 for the nine months
ended September 30, 1999 compared to $1,548,000 for the nine months ended
September 30, 1998, an increase of $223,000 or 14%. The Company's G&A costs have
increased due to expansion of the Company's areas of activity.
17
<PAGE> 18
The provision for income taxes was $800,000 for the quarter ended September
30, 1999 compared to $353,000 for the quarter ended September 30, 1998. Income
before income taxes increased $1,586,000 for the 1999 quarter and the effective
tax rate increased to 25% from 22%. The provision for the nine months ended
September 30, 1999 was $1,910,000 compared to $2,658,000 for the same nine month
period of 1998. Income before income taxes for the nine month period of 1999
decreased by $1,926,000, and the effective tax rate also decreased to 25% from
28%. Effective tax rates are affected by amounts of permanent differences in
financial and taxable income, consisting primarily of statutory depletion
deductions Section 29 tax credits and compensation expense recognized from the
exercise of stock options.
Historically, oil and natural gas prices have been volatile and are likely
to continue to be volatile. Prices are affected by, among other things, weather,
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 natural gas prices
decline, the Company's revenues, cash flows, earnings and operations would be
adversely impacted. Oil and natural gas prices also affect reserve values used
in determining the "ceiling test" limitation for the Company's capitalized oil
and gas property costs accounted for under the full cost method. Should the net
capitalized costs of the Company's oil and gas properties exceed the estimated
present value of future net cash flows from proved oil and gas reserves, such
excess costs would be recognized as an impairment and charged to current
expense. A decline in oil and gas prices could possibly result in the
recognition of an impairment in future periods. The Company is unable to
accurately predict future oil and natural gas prices.
The Company's main 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.
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 deceases in oil and natural gas prices by entering into derivative
commodity instruments, including commodity futures contracts and price swaps. By
hedging only a portion of its market risk exposures, the Company is able to
participate in the increased earnings and cash flows associated with increases
in oil and natural gas prices; however, it is exposed to risk on the unhedged
portion of its oil and natural gas production should oil and gas prices decline.
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.
18
<PAGE> 19
Note 3 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. As of November 1, 1999, the Company had the following
variable for fixed derivatives in place:
<TABLE>
<CAPTION>
Volume Fixed Unrealized
Type of Derivative (barrels) Price Term Gain
- --------------------------- ------------ -------------- --------------- -------------
<S> <C> <C> <C> <C>
Crude oil futures contracts 5,000 $ 22.90 December 1999 $ 1,950
Crude oil call options sold 5,000 24.50 December 1999 3,300
</TABLE>
During the first nine months of 1999, the Company sold 235,000 barrels of
oil. A hypothetical decrease of $1.54 per barrel (10% of average price received
during the period) would have decreased the Company's production revenues by
$362,000 for that period. The Company sold 5,299,000 Mcf of natural gas during
the first nine months of 1999. A hypothetical decrease of $.195 per Mcf (10% of
average price received during the period) would have decreased the Company's
production revenues by $1,033,000 for that period.
-------------------------------
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,
19
<PAGE> 20
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, 1998,
beginning on page 16.
---------------------------
PART II OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibit is filed herewith pursuant to rule 601 of
Regulation S-K.
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, 1999.
20
<PAGE> 21
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 15, 1999 By /s/ Richard H. Lewis
------------------------ -----------------------------------
Richard H. Lewis,
President and
Principal Financial Officer
<PAGE> 22
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
- ------ -----------------------
<S> <C>
27.1 Financial Data Schedule
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM 10-Q
FOR PRIMA ENERGY CORPORATION FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999 AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 25,623,000
<SECURITIES> 2,060,000
<RECEIVABLES> 4,620,000
<ALLOWANCES> (47,000)
<INVENTORY> 570,000
<CURRENT-ASSETS> 33,346,000
<PP&E> 77,421,000
<DEPRECIATION> (39,709,000)
<TOTAL-ASSETS> 71,315,000
<CURRENT-LIABILITIES> 9,298,000
<BONDS> 0
0
0
<COMMON> 89,000
<OTHER-SE> 56,038,000
<TOTAL-LIABILITY-AND-EQUITY> 71,315,000
<SALES> 15,943,000
<TOTAL-REVENUES> 20,810,000
<CGS> 9,121,000
<TOTAL-COSTS> 11,449,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 7,590,000
<INCOME-TAX> 1,910,000
<INCOME-CONTINUING> 5,680,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,680,000
<EPS-BASIC> 0.99
<EPS-DILUTED> 0.98
</TABLE>
