<PAGE>
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 June 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 August 3, 1999, the Registrant had 5,705,929 shares of Common Stock,
$0.015 Par Value, outstanding.
<PAGE>
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...................... 12
Item 3. Quantitative and Qualitative Disclosures About Market Risk......... 17
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995......................... 19
PART II - OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders................. 20
Item 6. Exhibits and Reports on Form 8-K.................................... 20
Signatures................................................................... 21
</TABLE>
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
ASSETS
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------------- -------------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents................................... $ 27,415,000 $ 2,522,000
Available for sale securities, at market.................... 2,116,000 2,391,000
Receivables (net of allowance for doubtful
accounts: 6/30/99, $47,000; 12/31/98, $47,000)............ 4,727,000 4,696,000
Tubular goods inventory..................................... 516,000 612,000
Other....................................................... 273,000 452,000
------------- -------------
Total current assets.................................... 35,047,000 10,673,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method............................ 64,771,000 86,081,000
Less accumulated depreciation,
depletion and amortization................................ (35,436,000) (33,135,000)
------------- -------------
Oil and gas properties - net............................ 29,335,000 52,946,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment.................................. 5,960,000 4,353,000
Office furniture and equipment.............................. 849,000 815,000
Field office, shop and land................................. 474,000 439,000
------------- -------------
7,283,000 5,607,000
Less accumulated depreciation............................... (3,236,000) (2,946,000)
------------- -------------
Property and equipment - net.............................. 4,047,000 2,661,000
------------- -------------
OTHER ASSETS................................................ 257,000 586,000
------------- -------------
$ 68,686,000 $ 66,866,000
------------- -------------
------------- -------------
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
3
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
(UNAUDITED)
LIABILITIES AND STOCKHOLDERS' EQUITY
<TABLE>
<CAPTION>
JUNE 30, DECEMBER 31,
1999 1998
------------- -------------
<S> <C> <C>
CURRENT LIABILITIES
Accounts payable .......................................... $ 1,217,000 $ 2,122,000
Amounts payable to oil and gas property owners ............ 1,710,000 973,000
Production taxes payable .................................. 1,456,000 1,552,000
Income taxes payable ...................................... 5,788,000 0
Accrued and other liabilities ............................. 397,000 439,000
Current portion of note payable ........................... 304,000 120,000
------------- -------------
Total current liabilities ........................... 10,872,000 5,206,000
NOTE PAYABLE .............................................. 0 120,000
PRODUCTION TAXES, non-current ............................. 541,000 1,088,000
DEFERRED TAX LIABILITY .................................... 4,080,000 9,144,000
------------- -------------
Total liabilities ................................... 15,493,000 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; 5,838,056 and 5,835,556 shares issued ....... 87,000 87,000
Additional paid-in capital ................................ 4,440,000 4,417,000
Retained earnings ......................................... 50,841,000 47,550,000
Unrealized gain (loss) on available for sale securities.... (95,000) 51,000
Treasury stock, 162,127 and 63,787 shares at cost ......... (2,080,000) (797,000)
------------- -------------
Total stockholders' equity .......................... 53,193,000 51,308,000
------------- -------------
$ 68,686,000 $ 66,866,000
------------- -------------
------------- -------------
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
4
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
1999 1998 1999 1998
------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
REVENUES
Oil and gas sales ....................... $ 4,597,000 $ 4,126,000 $ 8,423,000 $ 8,276,000
Trading revenues ........................ 664,000 931,000 1,081,000 2,580,000
Oilfield services ....................... 1,074,000 989,000 2,106,000 2,117,000
Management and operator fees ............ 149,000 262,000 389,000 514,000
Interest and dividend income ............ 332,000 137,000 606,000 271,000
Other ................................... 30,000 (8,000) 30,000 3,857,000
------------ ------------ ------------ ------------
6,846,000 6,437,000 12,635,000 17,615,000
------------ ------------ ------------ ------------
EXPENSES
Depreciation, depletion and amortization 1,347,000 1,634,000 2,656,000 3,139,000
Lease operating expense ................. 539,000 517,000 1,032,000 1,021,000
Production taxes ........................ 418,000 319,000 720,000 664,000
Cost of trading ......................... 747,000 1,034,000 1,101,000 2,444,000
Cost of oilfield services ............... 866,000 593,000 1,533,000 1,457,000
General and administrative .............. 618,000 456,000 1,192,000 977,000
------------ ------------ ------------ ------------
4,535,000 4,553,000 8,234,000 9,702,000
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES .............. 2,311,000 1,884,000 4,401,000 7,913,000
PROVISION FOR INCOME TAXES .............. 535,000 415,000 1,110,000 2,305,000
------------ ------------ ------------ ------------
NET INCOME .............................. $ 1,776,000 $ 1,469,000 $ 3,291,000 $ 5,608,000
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
BASIC NET INCOME PER SHARE .............. $ 0.31 $ 0.25 $ 0.58 $ 0.97
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
DILUTED NET INCOME PER SHARE ............ $ 0.31 $ 0.25 $ 0.57 $ 0.95
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING .................... 5,674,923 5,772,556 5,709,861 5,771,410
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING ASSUMING DILUTION ......... 5,803,695 5,906,081 5,805,170 5,894,808
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
5
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Net income ............................. $ 1,776,000 $ 1,469,000 $ 3,291,000 $ 5,608,000
----------- ----------- ----------- -----------
Other comprehensive income:
Unrealized gain (loss) on
available-for-sale securities ........ (93,000) (4,000) (233,000) 0
Deferred income tax expense related
to unrealized gain (loss) on
available-for-sale securities ....... 35,000 2,000 87,000 0
----------- ----------- ----------- -----------
(58,000) (2,000) (146,000) 0
----------- ----------- ----------- -----------
COMPREHENSIVE INCOME ................... $ 1,718,000 $ 1,467,000 $ 3,145,000 $ 5,608,000
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
</TABLE>
See accompanying notes to unaudited consolidated financial statements.
6
<PAGE>
PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<TABLE>
<CAPTION>
SIX MONTHS ENDED
JUNE 30,
----------------------------
1999 1998
------------ ------------
<S> <C> <C>
OPERATING ACTIVITIES
Net income ................................................................... $ 3,291,000 $ 5,608,000
Adjustments to reconcile net income to net cash provided by operating
activities:
Depreciation, depletion and amortization .................................. 2,656,000 3,139,000
Deferred income taxes ..................................................... 731,000 1,669,000
Current taxes from sale of oil and gas properties.......................... (5,704,000) 0
Other ..................................................................... (30,000) (50,000)
Changes in operating assets and liabilities:
Receivables ............................................................. (31,000) 1,646,000
Inventory ............................................................... 96,000 (75,000)
Other current assets .................................................... 175,000 105,000
Accounts payable and payables to owners.................................. (168,000) (2,311,000)
Production taxes payable................................................. (643,000) (542,000)
Income taxes payable..................................................... 5,788,000 0
Accrued and other liabilities ........................................... (42,000) (175,000)
------------ ------------
Net cash provided by operating activities ............................. 6,119,000 9,014,000
------------ ------------
INVESTING ACTIVITIES
Proceeds from sales of oil and gas and other assets .......................... 27,421,000 56,000
Additions to oil and gas properties .......................................... (5,561,000) (7,637,000)
Purchases of other property .................................................. (1,650,000) (698,000)
Purchases of available for sale securities ................................... (56,000) (459,000)
------------ ------------
Net cash provided by (used in) investing activities ................... 20,154,000 (8,738,000)
------------ ------------
FINANCING ACTIVITIES
Treasury stock purchased ..................................................... (1,283,000) 0
Proceeds from issuance of common stock ....................................... 23,000 23,000
Repayment of long term debt .................................................. (120,000) (120,000)
------------ ------------
Net cash used in financing activities ................................ (1,380,000) (97,000)
------------ ------------
INCREASE IN CASH AND CASH EQUIVALENTS ........................................ 24,893,000 179,000
CASH AND CASH EQUIVALENTS, beginning of period ............................... 2,522,000 5,644,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ..................................... $ 27,415,000 $ 5,823,000
------------ ------------
------------ ------------
</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>
PRIMA ENERGY CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL
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 unaudited consolidated financial statements should
be read in conjunction with the Notes to Consolidated Financial Statements
which are included in the Annual Report on Form 10-K of Prima Energy
Corporation for the year ended December 31, 1998.
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 six 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 June 30, 1999 and 1998.
2. BASIS OF PRESENTATION
The accompanying unaudited consolidated financial statements
include the accounts of Prima Energy Corporation ("Prima") and its
subsidiaries, herein collectively referred to as the "Company." All
significant intercompany transactions have been eliminated. Certain amounts
in prior years have been reclassified to conform with the classifications at
June 30, 1999.
3. NOTES PAYABLE AND LINE OF CREDIT
The Company's notes payable consist of the following:
<TABLE>
<CAPTION>
June 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 June 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 June 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.
8
<PAGE>
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 (7.75% at June 30, 1999), with interest
payable monthly. At December 31, 1998 and June 30, 1999, there were no
amounts outstanding under the line of credit.
4. 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 57% and 0% of its oil production in the first six months of
1999 and 1998, respectively, and hedged approximately 23% and 47% of its
natural gas production in these same periods. Hedging gains and losses were
$13,000 and $(193,000) for the six months ended June 30, 1999 and 1998,
respectively, and were included in oil and gas revenues at the time the
hedged volumes were sold. At June 30, 1999, the Company had written natural
gas call options for August 1999 for 100,000 MMBtu with unrealized gains of
$2,000, and open swaps (variable for fixed) of 100,000 MMBtu per month for
each of the three months of August through October 1999 with unrealized
losses of $70,000. Additionally, Prima Natural Gas Marketing, Inc., a wholly
owned subsidiary of the Company, had sold physical volumes at fixed prices of
6,000 MMBtu per day for each of the months of July through October 1999,
which have unrealized losses of $300,000. These sales are reflected as
trading revenue and cost of trading in the accompanying income statement. At
August 10, 1999, the Company had no hedges in place or commitments in its
marketing subsidiary which extend beyond October of 1999. At June 30, 1999
and August 10, 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.
5. COMMON STOCK
Pursuant to the provisions of the Prima Energy Corporation 1993
Stock Incentive Plan, during the second quarter of 1999, 2,500 shares of
Prima's common stock were issued upon the exercise of stock options for total
proceeds of $23,000. Subsequent to June 30, 1999, an additional 30,000 shares
of common stock were issued for total proceeds of $265,000. This increased
the total number of shares of common stock outstanding to 5,705,929 as of
August 10, 1999.
9
<PAGE>
During the six months ended June 30, 1999, the Company repurchased
98,340 shares of its common stock for $1,283,000 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.
6. 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 June 30, 1999:
Basic Net Income per Share...................... $ 1,776,000 5,674,923 $ 0.31
------
------
Effect of Stock Options......................... 128,772
----------- -----------
Diluted Net Income per Share.................... $ 1,776,000 5,803,695 $ 0.31
----------- ----------- ------
----------- ----------- ------
Quarter Ended June 30, 1998:
Basic Net Income per Share...................... $ 1,469,000 5,772,556 $ 0.25
Effect of Stock Options......................... 133,525
----------- -----------
Diluted Net Income per Share.................... $ 1,469,000 5,906,081 $ 0.25
----------- ----------- ------
----------- ----------- ------
Six Months Ended June 30, 1999:
Basic Net Income per Share...................... $ 3,291,000 5,709,861 $ 0.58
------
------
Effect of Stock Options......................... 95,309
----------- -----------
Diluted Net Income per Share.................... $ 3,291,000 5,805,170 $ 0.57
----------- ----------- ------
----------- ----------- ------
Six Months Ended June 30, 1998:
Basic Net Income per Share...................... $ 5,608,000 5,771,410 $ 0.97
------
------
Effect of Stock Options......................... 123,398
----------- -----------
Diluted Net Income per Share.................... $ 5,608,000 5,894,808 $ 0.95
----------- ----------- ------
----------- ----------- ------
</TABLE>
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 $26,000,000 (subject to certain
closing and post closing adjustments). 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%
10
<PAGE>
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 sales proceeds were placed in a like-kind exchange escrow
account pursuant to the provisions of Section 1031 of the Internal Revenue
Code of 1986. The Company did not close on any qualifying transactions within
180 days of the closing of the Bonny Field transactions, the time limit
mandated by the IRS provisions. 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 $6,000,000 have been reflected in the accompanying balance
sheet as a current liability.
11
<PAGE>
PRIMA ENERGY CORPORATION
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 six months
ended June 30, 1999 was $6,119,000 compared to $9,014,000 for the same six
month period of 1998. Net working capital at June 30, 1999 was $24,175,000
compared to $5,467,000 at December 31, 1998. Current assets at June 30, 1999
increased from December 31, 1998 levels by $24,374,000 and current
liabilities increased by $5,666,000 for the same period. The increase in
working capital of $18,708,000 was primarily generated by sales of oil and
gas properties and by cash flows from operations during the six months ended
June 30, 1999. The Company also received proceeds from the sales of
securities and other assets of $551,000 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 $6 million after
utilization of minimum tax credit carryforwards. This liability has been
reflected as a current liability in the accompanying balance sheet.
The Company invested $7,211,000 in property and equipment during
the six months ended June 30, 1999, compared to $8,335,000 for the 1998 six
month period. The Company expended $4,432,000 during the 1999 period for its
proportionate share of the costs of drilling, completing and refracturing
wells, $1,030,000 for undeveloped acreage, $99,000 for developed properties
and $1,650,000 for other property and equipment. These expenditures compare
to $5,407,000 for well costs, $2,205,000 for undeveloped acreage, $25,000 for
producing properties and $698,000 for other equipment in the 1998 period. The
Company also expended $1,283,000 for the purchase of treasury stock during
the first six months of 1999.
During the first six months of 1999, the Company refractured or
recompleted 28 gross (21.9 net) wells in the Wattenberg Field Area of the
Denver Basin. All of these operations have been successfully completed and
the wells are all back on production. Production increases have averaged 180
Mcf of natural gas and 8 barrels of oil per day. Current plans are to refrac
or recomplete approximately 30 additional wells in this area during the
second half of 1999. In addition, the Company plans to drill approximately 15
to 25 new wells in the Wattenberg Area and on leases at Denver International
Airport. To date in the third quarter, four additional refrac wells have been
completed and placed on production and the first of the additional wells at
DIA has commenced drilling.
12
<PAGE>
The Company drilled and set pipe on an offset well in the Cedar
Draw area of the Powder River Basin of Wyoming during the first quarter of
1999. The well, the Cedar Draw Federal 11-21, was completed during July 1999
and is currently producing at rates of 1,360 Mcf of natural gas and 37
barrels of oil per day. The Company has drilled two additional wells in this
area in July 1999. One is currently waiting on completion and one was plugged
and abandoned. The Company currently anticipates drilling one additional
10,000 foot Muddy Formation test well in this area during the remainder of
1999.
To date in 1999, the Company has drilled three coalbed methane
test wells in the Powder River Basin of Wyoming. These wells were drilled as
initial test wells to enable the Company to begin to test and evaluate its
acreage. The Company anticipates drilling additional initial 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: 1) the issuance of a Record of Decision under an ongoing Environmental
Impact Study, 2) the lifting of a current moratorium on the issuance of
drilling permits on federal acreage by the BLM and, 3) the Company's ability
to obtain water discharge permits. It is the Company's understanding that a
Record of Decision has been delayed until November of 1999 from a previously
anticipated September date. The Company continues to acquire and evaluate
acreage in this burgeoning play, where approximately 135,000 acres are under
lease as of the date of this report.
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 three non-operated wells during the first quarter of 1999 and two
additional wells during the second quarter of 1999. Prima's working interests
in these wells range from 6% to 15%. Three of these wells were producing, one
was being completed and one was drilling as of August 10, 1999.
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 Company for $460,000 and
other service equipment for $1,031,000 during the first six 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 ISSUE
The Year 2000 Issue is the result of computer applications being
written using two digits rather than four to define the applicable year. As
the year 2000 approaches, such applications may be unable to accurately
process certain date-based information. The Company believes it has
identified the significant internal computer applications that will require
modification to ensure Year 2000 compliance. Internal and external resources
are being used to make the required modifications and test 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 ongoing. Third
parties with whom the Company has material
13
<PAGE>
relationships have been contacted regarding their Year 2000 issues and
responses are being monitored to determine the potential effect on Prima. The
Company's operations would be impacted by various third parties abilities to
be Year 2000 compliant.
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 has not
yet determined the potential adverse effect that Year 2000 risks may have on
its financial condition, liquidity or results of operations. The Company's
program is expected to significantly reduce 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 is not anticipated
to be material to the Company's financial position or results of operations
in any given year.
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 June 30, 1999, the Company earned net income
of $1,776,000, or $.31 per diluted share, on revenues of $6,846,000, compared
to net income of $1,469,000, or $.25 per diluted share, on revenues of
$6,437,000 for the comparable quarter of 1998. Expenses were $4,535,000 for
the 1999 second quarter compared to $4,553,000 for the 1998 second quarter.
Revenues increased $409,000, or 6%, expenses decreased $18,000, or less than
1%, and net income increased $307,000, or 21%.
For the six months ended June 30, 1999, the Company earned net
income of $3,291,000, or $.57 per diluted share, on revenues of $12,635,000,
compared to net income of $5,608,000, or $.95 per diluted share, on revenues
of $17,615,000 for the six months ended June 30, 1998. Expenses were
$8,234,000 for the 1999 six month period compared to $9,702,000 for the 1998
six month period. Revenues decreased $4,980,000, or 28%, expenses decreased
$1,468,000, or 15%, and net income decreased $2,317,000, or 41%. 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 June 30, 1999 were
$4,597,000 compared to $4,126,000 for the same quarter of 1998, an increase
of $471,000 or 11%. The Company's net natural gas production was 1,796,000
Mcf and 1,647,000 Mcf for the second quarters of 1999 and 1998, respectively,
an increase of 149,000 Mcf or 9%. Its net oil production was 79,000 barrels
compared to 71,000 barrels for the same periods, an increase of 8,000 barrels
or 11%. The average price received for natural gas production was $1.89 per
Mcf for the 1999 quarter compared to $1.94 per Mcf for the 1998 quarter, a
decrease of $.05 per Mcf or 3%. Approximately 4% of natural gas production
for the three months ended June 30, 1998 was attributable to production sold
under a fixed contract
14
<PAGE>
price of $5.90 per MMBtu. The average price for the Company's natural gas
production exclusive of the fixed price contract gas was $1.76 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 second quarter of 1999 was $15.24 per barrel compared to $13.11 per
barrel for the second quarter of 1998, an increase of $2.13 per barrel or
16%. During the second quarter of 1999, the Company hedged approximately 90%
of its oil production and 20% of its natural gas production. Hedging losses
of $50,000 are included in oil and gas revenues for this period, which
decreased the average price received per barrel of oil by $.63 and had no
effect upon the price received per Mcf of natural gas. During the second
quarter of 1998, the Company hedged approximately 42% of its natural gas
production. Hedging losses of $67,000 decreased the average price received
for natural gas by $0.04 per Mcf. No oil was hedged during this period.
Oil and gas sales for the six months ended June 30, 1999 were
$8,423,000 compared to $8,276,000 for the six months ended June 30, 1998, an
increase of $147,000 or 2%. The Company's net natural gas production was
3,544,000 Mcf and 3,157,000 Mcf for the first six months of 1999 and 1998,
respectively, an increase of 387,000 Mcf or 12%. Its net oil production was
159,000 barrels compared to 139,000 barrels for the same six month periods,
an increase of 20,000 barrels or 14%. The average price received for natural
gas production was $1.78 per Mcf for the six months ended June 30, 1999
compared to $2.01 per Mcf for the six months ended June 30, 1998, a decrease
of $.23 per Mcf or 11%. Approximately 5% of natural gas production for the
six months ended June 30, 1998 was attributable to production sold under the
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 $1.83
per Mcf for the six months ended June 30,1998. The average price received for
oil for the first six months of 1999 was $13.30 per barrel compared to $13.78
per barrel for the same period of 1998, a decrease of $.48 per barrel or 3%.
During the six months ended June 30, 1999, the Company hedged approximately
57% of its oil production and 23% of it natural gas production. Net hedging
gains of $13,000 reduced the average price received per barrel of oil by $.26
and increased the price received per Mcf of natural gas by $0.02. During the
six months ended June 30, 1998, the Company hedged approximately 47% of it
natural gas production. Hedging losses of $193,000 reduced the average price
received for natural gas by $0.06 per Mcf. No oil production was hedged
during this period.
Lease operating expenses and production taxes ("LOE") were
$957,000 for the second quarter of 1999 compared to $836,000 for the 1998
quarter, an increase of $121,000 or 14%. Depreciation, depletion and
amortization ("DD&A") was $1,347,000 and $1,634,000 for the same periods, a
decrease of $287,000 or 18%. Production for the quarter ended June 30, 1999
was 378,000 barrels of oil equivalent ("BOE") compared to 346,000 BOE for the
quarter ended June 30, 1998, an increase of 32,000 BOE or 9%. LOE per
equivalent barrel of production was $2.53 for the second quarter of 1999
compared to $2.41 for the comparable quarter of 1998. DD&A applicable to oil
and gas properties was $3.07 per equivalent barrel of production for the 1999
quarter compared to $4.30 per equivalent barrel of production for the 1998
quarter. 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 $188,000 and $147,000 for the quarters ended June 30, 1999
and 1998, respectively.
LOE was $1,752,000 for the six months ended June 30, 1999 compared to
$1,685,000 for the 1998 period, an increase of $67,000 or 4%. DD&A was
$2,656,000 and $3,139,000 for the same periods, a decrease of $483,000 or 15%.
Production for the six months ended June 30, 1999 was 750,000 BOE compared to
665,000 BOE for the six months ended June 30, 1998, an increase of
15
<PAGE>
85,000 BOE or 13%. LOE per equivalent barrel of production was $2.34 for the
first six months of 1999 compared to $2.53 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 $355,000 and $278,000 for the six months ended June 30, 1999 and 1998,
respectively.
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 $664,000 for the quarter ended June 30,
1999 compared to $931,000 for the quarter ended June 30, 1998, a decrease of
$267,000 or 29%. The Company marketed 396,000 MMBtus for the second quarter
of 1999 compared to 501,000 MMBtus marketed during the comparable quarter of
1998, a decrease of 105,000 MMBtus or 21%. Costs of trading were $747,000 for
the 1999 quarter compared to $1,034,000 for the 1998 quarter, a decrease of
$287,000 or 28%.
Trading revenues were $1,081,000 for the six months ended June 30,
1999, a decrease of $1,499,000 or 58% from the $2,580,000 reported for the
six months ended June 30, 1998. The Company marketed 576,000 MMBtus for the
six month period of 1999 compared to 1,099,000 MMBtus marketed during the
comparable period of 1998, a decrease of 523,000 or 48%. Costs of trading
were $1,101,000 for the 1999 six month period compared to $2,444,000 for the
1998 six month period, a decrease of $1,343,000 or 55%. Trading activities
fluctuate with natural gas markets and the Company's ability to identify
markets that meet the Company's trading criteria.
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 $1,074,000 for the quarter ended June 30, 1999 compared to $989,000 for
the comparable quarter of 1998, an increase of $85,000, or 9%. For the
quarter ended June 30, 1999, 19% of the fees billed by the service companies
were for Company owned wells compared to 25% for the quarter ended June 30,
1998. Costs of oilfield services were $866,000 for the quarter ended June 30,
1999 compared to $593,000 for the same period of 1998, an increase of
$273,000 or 46%.
Oilfield services revenues were $2,106,000 for the six months
ended June 30, 1999 compared to $2,117,000 for the comparable six month
period of 1998, a decrease of $11,000 or 1%. For the six months ended June
30, 1999, 22% of the fees billed by the service companies were for Company
owned wells compared to 17% for the six months ended June 30, 1998. Costs of
oilfield services were $1,533,000 for the six months ended June 30, 1999
compared to $1,457,000 for the same period of 1998, an increase of $76,000 or
5%. 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.
Management and operator fees are earned pursuant to the Company's
roles as operator for approximately 375 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 June 30, 1999 were
16
<PAGE>
$149,000 compared to $262,000 for the 1998 quarter, a decrease of $113,000 or
43%. Fees for the six months ended June 30, 1999 were $389,000 compared to
$514,000 for the 1998 six month period, a decrease of $125,000 or 24%. 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. Management and operator fees attributable to the Bonny Field system
were $66,000 and $203,000 for the six months ended June 30, 1999 and 1998,
respectively.
General and administrative expenses ("G&A") were $618,000 for the
quarter ended June 30, 1999 compared to $456,000 for the quarter ended June
30, 1998, an increase of $162,000 or 36%. G&A was $1,192,000 for the six
months ended June 30, 1999 compared to $977,000 for the six months ended June
30, 1998, an increase of $215,000 or 22%. The Company's G&A costs have
increased due to expansion of the Company's areas of activity.
The provision for income taxes was $535,000 for the quarter ended
June 30, 1999 compared to $415,000 for the quarter ended June 30, 1998. The
provision for the six months ended June 30, 1999 was $1,110,000 compared to
$2,305,000 for the same six month period of 1998. Income before income taxes
increased $427,000 for the 1999 quarter, and the effective tax rate increased
to 23.2% from 22.0%. Income before income taxes for the six month period of
1999 decreased by $3,512,000, and the effective tax rate decreased from 29.1%
to 25.2%. Effective tax rates are affected by amounts of permanent
differences in financial and taxable income, consisting primarily of
statutory depletion deductions and Section 29 tax credits.
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.
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
17
<PAGE>
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. As of August 10, 1999, the Company had the
following variable for fixed derivative or physical positions in place:
<TABLE>
<CAPTION>
Volume Fixed Unrealized
Type of Derivative (Mcf) Price Term Gain/(Loss)
- ------------------ ------- ----- ------------------ -----------
<S> <C> <C> <C> <C>
Natural gas commodity swap 50,000/mo $1.82 Sept. to Oct. 1999 $(42,000)
Natural gas commodity swap 50,000/mo 1.87 Sept. to Oct. 1999 (37,000)
Natural gas physical trade 6,000/day 1.68 Aug. to Oct. 1999 (335,000)
</TABLE>
During the first six months of 1999, the Company sold 159,000
barrels of oil. A hypothetical decrease of $1.33 per barrel (10% of average
price received during the period) would have decreased the Company's
production revenues by $211,000 for that period. The Company sold 3,544,000
Mcf of natural gas during the first six months of 1999. A hypothetical
decrease of $.178 per Mcf (10% of average price received during the period)
would have decreased the Company's production revenues by $631,000 for that
period.
18
<PAGE>
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR"
PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" included in Item 2 of this Report contains
"forward-looking statements" and are made pursuant to the "safe harbor"
provisions of the Private Securities Litigation Reform Act of 1995. These
statements include, without limitation, statements relating to liquidity,
financing of operations, capital expenditures budget (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," "expects,"
"believes" or "plans" 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;
volatility of oil and natural gas prices; hedging activities; 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.
19
<PAGE>
PART II OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
On May 19, 1999, the Company held an annual meeting of
stockholders. The following table sets forth certain information relating to
each matter voted upon at the meeting.
<TABLE>
<CAPTION>
Votes
--------------------------------------------------
Withheld/ Broker
Matters Voted Upon For Against Abstain Non-Votes
- --------------------------------------- --------- ------- --------- ---------
<S> <C> <C> <C> <C>
Election of Robert E. Childress 4,961,679 70,858
as Class II Director.
Election of Douglas J. Guion 4,952,966 79,571
as Class II Director.
Approval of the adoption of the Prima 4,875,903 127,166 29,468
Energy Corporation Non-Employee
Directors' Stock Option Plan
Ratification of the selection of 4,998,929 9,456 24,152
Deloitte & Touche LLP as independent
auditors for 1999.
</TABLE>
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.
EXHIBIT NO. DOCUMENT
27 Financial Data Schedules
(b) REPORTS ON FORM 8-K
No reports on Form 8-K were filed during the Registrants' fiscal quarter
ended June 30, 1999.
20
<PAGE>
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 August 16, 1999 By /s/ Richard H. Lewis
------------------- ---------------------------
Richard H. Lewis,
President and
Principal Financial Officer
21
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM FORM
10-Q FOR PRIMA ENERGY CORPORATION FOR THE SIX MONTHS ENDED JUNE 30, 1999
AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<CASH> 27,415,000
<SECURITIES> 2,116,000
<RECEIVABLES> 4,774,000
<ALLOWANCES> (47,000)
<INVENTORY> 516,000
<CURRENT-ASSETS> 35,047,000
<PP&E> 72,054,000
<DEPRECIATION> (38,672,000)
<TOTAL-ASSETS> 68,686,000
<CURRENT-LIABILITIES> 10,872,000
<BONDS> 0
0
0
<COMMON> 87,000
<OTHER-SE> 53,106,000
<TOTAL-LIABILITY-AND-EQUITY> 68,686,000
<SALES> 9,504,000
<TOTAL-REVENUES> 12,635,000
<CGS> 5,509,000
<TOTAL-COSTS> 7,042,000
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 4,401,000
<INCOME-TAX> 1,110,000
<INCOME-CONTINUING> 3,291,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,291,000
<EPS-BASIC> 0.58
<EPS-DILUTED> 0.57
</TABLE>
