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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 March 31, 2001
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)
1099 18TH STREET, SUITE 400, 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 April 30, 2001, the Registrant had 12,731,373 shares of Common Stock,
$0.015 Par Value, outstanding.
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PRIMA ENERGY CORPORATION
INDEX
PART I - FINANCIAL INFORMATION Page
----
Item 1. Financial Statements
Unaudited Consolidated Balance Sheets ................................. 3
Unaudited Consolidated Statements of Income ........................... 5
Unaudited Consolidated Statements of Comprehensive Income ............. 6
Unaudited Consolidated Statements of Cash Flows ....................... 7
Notes to Unaudited Consolidated Financial Statements .................. 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations .................. 11
Item 3. Quantitative and Qualitative Disclosures
About Market Risk .............................................. 14
Cautionary Statement for Purposes of the "Safe Harbor" Provisions of the
Private Securities Litigation Reform Act of 1995 ...................... 15
PART II - OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K ................................ 16
Signatures ............................................................... 17
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PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
MARCH 31, DECEMBER 31,
2001 2000
------------- -------------
(Unaudited)
CURRENT ASSETS
Cash and cash equivalents ............................. $ 24,184,000 $ 20,382,000
Available for sale securities, at market .............. 2,437,000 2,311,000
Receivables (net of allowance for doubtful
accounts: 3/31/01, $45,000; 12/31/00, $44,000) ...... 8,431,000 8,902,000
Derivatives, at fair value ............................ 2,058,000 0
Tubular goods inventory ............................... 1,759,000 1,409,000
Other ................................................. 824,000 1,042,000
------------- -------------
Total current assets ............................ 39,693,000 34,046,000
------------- -------------
OIL AND GAS PROPERTIES, at cost, accounted
for using the full cost method ...................... 119,712,000 109,652,000
Less accumulated depreciation,
depletion and amortization .......................... (45,703,000) (43,935,000)
------------- -------------
Oil and gas properties - net .................... 74,009,000 65,717,000
------------- -------------
PROPERTY AND EQUIPMENT, at cost
Oilfield service equipment ............................ 7,849,000 7,664,000
Furniture and equipment ............................... 755,000 729,000
Field office, shop and land ........................... 473,000 473,000
------------- -------------
9,077,000 8,866,000
Less accumulated depreciation ......................... (4,181,000) (3,986,000)
------------- -------------
Property and equipment - net .................... 4,896,000 4,880,000
------------- -------------
OTHER ASSETS .......................................... 1,257,000 257,000
------------- -------------
$ 119,855,000 $ 104,900,000
============= =============
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS (CONT'D.)
LIABILITIES AND STOCKHOLDERS' EQUITY
MARCH 31, DECEMBER 31,
2001 2000
------------- -------------
(Unaudited)
CURRENT LIABILITIES
Accounts payable ...................................... $ 3,755,000 $ 3,207,000
Amounts payable to oil and gas property owners ........ 3,175,000 2,501,000
Ad valorem and production taxes payable ............... 1,817,000 1,857,000
Accrued and other liabilities ......................... 786,000 803,000
Deferred tax liability ................................ 463,000 0
------------- -------------
Total current liabilities ....................... 9,996,000 8,368,000
AD VALOREM TAXES, non-current ......................... 4,718,000 3,213,000
DEFERRED TAX LIABILITY ................................ 16,741,000 13,021,000
------------- -------------
Total liabilities ............................... 31,455,000 24,602,000
------------- -------------
STOCKHOLDERS' EQUITY
Preferred stock, $0.001 par value, 2,000,000 shares
authorized; no shares issued or outstanding ......... 0 0
Common stock, $0.015 par value, 18,000,000 shares
authorized; 12,793,373 shares issued ................ 192,000 192,000
Additional paid-in capital ............................ 1,868,000 1,760,000
Retained earnings ..................................... 87,148,000 78,472,000
Accumulated other comprehensive income (loss) ......... 817,000 (126,000)
Treasury stock, 62,000 and 0 shares at cost ........... (1,625,000) 0
------------- -------------
Total stockholders' equity ...................... 88,400,000 80,298,000
------------- -------------
$ 119,855,000 $ 104,900,000
============= =============
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
-------------------------
2001 2000
----------- -----------
REVENUES
Oil and gas sales ........................................ $16,357,000 $ 8,727,000
Oilfield services ........................................ 1,776,000 1,659,000
Interest, dividend and other income ...................... 337,000 291,000
----------- -----------
18,470,000 10,677,000
----------- -----------
EXPENSES
Depreciation, depletion and amortization:
Depletion of oil and gas properties .................. 1,768,000 1,451,000
Depreciation of property and equipment ............... 282,000 266,000
Lease operating expense .................................. 799,000 636,000
Ad valorem and production taxes .......................... 1,424,000 731,000
Cost of oilfield services ................................ 1,134,000 1,280,000
General and administrative ............................... 1,088,000 539,000
----------- -----------
6,495,000 4,903,000
----------- -----------
Income Before Income Taxes and Cumulative
Effect of Change in Accounting Principle ............... 11,975,000 5,774,000
Provision for Income Taxes ............................... 3,910,000 1,590,000
----------- -----------
Net Income Before Cumulative Effect of
Change in Accounting Principle ......................... 8,065,000 4,184,000
Cumulative Effect of Change in Accounting Principle ...... 611,000 0
----------- -----------
NET INCOME ............................................... $ 8,676,000 $ 4,184,000
=========== ===========
Basic Net Income per Share Before Cumulative
Effect of Change in Accounting Principle ............... $ 0.63 $ 0.33
Cumulative Effect of Change in Accounting Principle ...... 0.05 0.00
----------- -----------
BASIC NET INCOME PER SHARE ............................... $ 0.68 $ 0.33
=========== ===========
Diluted Net Income per Share Before Cumulative Effect
Of Change in Accounting Principle ...................... $ 0.60 $ 0.32
Cumulative Effect of Change in Accounting Principle ...... 0.05 0.00
----------- -----------
DILUTED NET INCOME PER SHARE ............................. $ 0.65 $ 0.32
=========== ===========
Weighted Average Common Shares
Outstanding ............................................ 12,757,551 12,744,319
=========== ===========
Weighted Average Common Shares
Outstanding Assuming Dilution .......................... 13,322,748 13,210,295
=========== ===========
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
--------------------------
2001 2000
----------- -----------
Net income ............................................ $ 8,676,000 $ 4,184,000
----------- -----------
Other comprehensive income:
Unrealized gain (loss) on derivative activities ....... 1,820,000 0
Deferred income tax expense related to unrealized
gain on derivative activities ........................ (517,000) 0
Reclassification adjustment for gains included in
oil and gas sales ................................... (422,000) 0
Unrealized gain on available-for-sale securities ...... 98,000 25,000
Deferred income tax expense related to unrealized
gain on available-for-sale securities ................ (36,000) (9,000)
----------- -----------
943,000 16,000
----------- -----------
COMPREHENSIVE INCOME .................................. $ 9,619,000 $ 4,200,000
=========== ===========
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31,
----------------------------
2001 2000
------------ ------------
OPERATING ACTIVITIES
Net income ......................................................... $ 8,676,000 $ 4,184,000
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation, depletion and amortization ....................... 2,050,000 1,717,000
Deferred income taxes .......................................... 3,656,000 1,155,000
Unrealized gains from trading activities ....................... (660,000) 0
Other .......................................................... (19,000) (10,000)
Changes in operating assets and liabilities:
Receivables .................................................. 471,000 (587,000)
Inventory .................................................... (350,000) 79,000
Other current assets ......................................... 127,000 130,000
Accounts payable and payables to owners ...................... 1,222,000 (316,000)
Production taxes payable ..................................... 1,465,000 828,000
Accrued and other liabilities ................................ (16,000) 360,000
------------ ------------
Net cash provided by operating activities ................. 16,622,000 7,540,000
------------ ------------
INVESTING ACTIVITIES
Additions to oil and gas properties ................................ (11,060,000) (7,792,000)
Purchases of other property ........................................ (390,000) (467,000)
Purchases of available for sale securities ......................... (28,000) (28,000)
Proceeds from sales of oil & gas and other property ................ 111,000 29,000
------------ ------------
Net cash used in investing activities ..................... (11,367,000) (8,258,000)
------------ ------------
FINANCING ACTIVITIES
Net proceeds from short swing profit transaction ................... 172,000 0
Treasury stock purchased ........................................... (1,625,000) (1,778,000)
------------ ------------
Net cash used in financing activities ..................... (1,453,000) (1,778,000)
------------ ------------
INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS ............................................. 3,802,000 (2,496,000)
CASH AND CASH EQUIVALENTS, beginning of period ..................... 20,382,000 18,883,000
------------ ------------
CASH AND CASH EQUIVALENTS, end of period ........................... $ 24,184,000 $ 16,387,000
============ ============
Supplemental schedule of noncash investing and financing activities:
Other assets acquired in exchange for undeveloped
oil and gas properties ........................................... $ 1,000,000
============
See accompanying notes to unaudited consolidated financial statements.
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PRIMA ENERGY CORPORATION
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL
Prima Energy Corporation ("Prima") is an independent oil and gas
company primarily engaged in the exploration for, acquisition, development and
production of, crude oil and natural gas. Through its wholly owned subsidiaries,
Prima is also engaged in oil and gas property operations, oilfield services and
natural gas gathering, marketing and trading. Prima's current activities are
principally conducted in the Rocky Mountain region of the United States.
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 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,
2000.
The results for interim periods are not necessarily indicative of
results to be expected for the fiscal year of the Company ending December 31,
2001. The Company believes that the three 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 March 31, 2001 and 2000.
2. BASIS OF PRESENTATION
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 March 31, 2001.
3. DERIVATIVE ACTIVITIES
The Company's marketing and trading activities consist of marketing the
Company's own production and marketing the production of others from wells
operated by the Company. Crude oil and natural gas futures, options and swaps
and basis swaps are used from time to time in order to hedge the price of a
portion of the Company's production and to lock in the basis from NYMEX to the
Rocky Mountains. This is done to mitigate the risk of fluctuating oil and
natural gas prices and fluctuating basis differential, which can adversely
affect operating results. These transactions have been entered into with major
financial institutions, thereby minimizing credit risk. Approximately 36% of the
Company's natural gas production was hedged during the quarter ended March 31,
2001, with hedging gains of $422,000 included in oil and gas revenues at the
time the hedged volumes were sold. The Company did not hedge any of its oil in
the first quarter of 2001, and did not hedge any of its natural gas or oil
production in the first quarter of 2000. At March 31, 2001, the Company had open
derivative positions as follows:
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Monthly Volume
(MMBtu) or Unrealized
Type of Derivative (Barrels) Term Gains
------------------------- -------------- -------------------- -----------
Natural gas futures 300,000 April 2001 $ 88,200
Natural gas basis swaps 440,000 April 2001 225,200
Natural gas futures 200,000 May - September 2001 449,200
Natural gas basis swaps 240,000 May - November 2001 1,289,400
Crude oil calls 10,000 May 2001 6,000
Statement of Financial Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"), as amended, was
adopted January 1, 2001 by the Company. SFAS 133 establishes accounting and
reporting 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. If the
derivative is designated as a fair value hedge, the changes in the fair value of
the derivative and the hedged item will be recognized in earnings. If the
derivative is designated as a cash flow hedge, changes in the fair value of the
derivative will be recorded in other comprehensive income and will be recognized
in the income statement when the hedged item affects earnings. SFAS 133 defines
new requirements for designation and documentation of hedging relationships as
well as ongoing effectiveness assessments in order to use hedge accounting. For
a derivative that does not qualify as a hedge, changes in fair value will be
recognized in earnings.
In connection with the adoption of SFAS 133, all derivatives within the
Company were identified pursuant to SFAS 133 requirements. To the extent
derivatives met the requirements of cash flow hedges, changes in the fair value
of the derivatives were recognized in other comprehensive income until such time
as the hedged item was or will be recognized in earnings. Hedge effectiveness is
measured based on the relative changes in the fair value between the derivative
contract and the hedged item over time. Any changes in fair value resulting from
ineffectiveness, as defined by SFAS 133, will be recognized immediately in
current earnings. To the extent derivatives are fair value hedges, changes in
fair value were marked-to-market and recognized in earnings immediately.
The adoption of SFAS 133 as of January 1, 2001 resulted in the
recognition of a current asset of $1,241,000, a current liability of $549,000,
and net-of-tax cumulative effect adjustments reducing other comprehensive income
by $129,000 and increasing net income by $611,000. The $611,000 is reflected as
the cumulative effect of a change in accounting principle in the March 31, 2001
financial statements. As of March 31, 2001, the Company recorded a current asset
of $2,058,000, a net of tax increase in other comprehensive income of $881,000,
and hedging gains of $422,000 which are included in oil and gas revenues for the
period.
4. EARNINGS PER SHARE
Basic net income per share is computed by dividing net income by the
weighted average common shares outstanding during the period. Diluted net income
per share includes the potential dilution that could occur upon exercise of
options to acquire common stock, computed using the treasury stock method. The
treasury stock method assumes that the increase in the number of shares issued
is reduced by the number of shares which could have been repurchased by the
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Company with the proceeds from the exercise of the options. Repurchases 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.
Income Shares Per Share
(Numerator) (Denominator) Amount
----------- ------------- ---------
Quarter Ended March 31, 2001:
Basic Net Income per Share .............. $8,676,000 12,757,551 $ 0.68
========
Effect of Stock Options ................. 565,197
---------- ----------
Diluted Net Income per Share ............ $8,676,000 13,322,748 $ 0.65
========== ========== ========
Quarter Ended March 31, 2000:
Basic Net Income per Share .............. $4,184,000 12,744,319 $ 0.33
========
Effect of Stock Options ................. 465,976
---------- ----------
Diluted Net Income per Share ............ $4,184,000 13,210,295 $ 0.32
========== ========== ========
During the quarter ended March 31, 2001, the Company repurchased 62,000
shares for $1,625,000 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. At March 31, 2001, the Company had repurchased approximately 10% of the
repurchase amount approved by the Board, or .5% of the issued shares.
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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 operations and existing cash and cash equivalents. Net cash
provided by operating activities for the three months ended March 31, 2001 was
$16,622,000 compared to $7,540,000 for the same three month period of 2000. Net
working capital at March 31, 2001 was $29,697,000 compared to $25,678,000 at
December 31, 2000.
The Company invested $11,060,000 in additions to oil and gas properties
during the quarter ended March 31, 2001, compared to $7,792,000 for the 2000
quarter. The Company expended $10,502,000 during the 2001 quarter for its
proportionate share of the costs of drilling, completing and refracturing wells
and $558,000 for undeveloped acreage. These expenditures compare to $7,457,000
for well costs and $335,000 for undeveloped acreage in the 2000 quarter. The
Company also expended $1,625,000 for the purchase of 62,000 shares of treasury
stock and $390,000 for other property and equipment during the first quarter of
2001.
During the first quarter of 2001, the Company participated in the
drilling of 10 gross ( 9.96 net) wells and the refracturing of 25 gross (22.8
net) wells in the Wattenberg Field area of the Denver Basin. All of these wells
have been successfully completed and placed on production. Current plans are to
drill an additional 15 to 20 new wells and to refrac or recomplete approximately
40 additional wells in this area during the remainder of 2001. To date in the
second quarter, two gross and net wells have been drilled, with one on
production and one waiting on pipeline hook-up. Ten refracs (9.45 net) have been
completed to date in the second quarter.
Prima drilled 35 gross (34.0 net) Powder River Basin Coalbed Methane
("CBM") wells during the first quarter of 2001, and an additional 15 gross (14.9
net) CBM wells to date in the second quarter. A total of 220 CBM wells have been
drilled since inception of the Company's program. The Company anticipates
drilling 175 to 200 CBM wells in 2001.
All of Prima's CBM production to date has been from the Company's
Stones Throw project area, where there are currently 99 wells hooked-up. By the
end of the second quarter, Prima expects to have approximately 108 wells
hooked-up and capable of production at Stones Throw. The Company recently
hooked-up the first seven wells at its Kingsbury project area, and expects to
hook-up 20 additional wells there by the end of May. Prima continues to expect
that a total of approximately 140 Powder River Basin CBM wells will be hooked-up
and capable of production by mid-third quarter, with that total reaching 200 by
year end 2001.
During the first quarter of 2001, Prima formed two federal units,
Echeta and Wild Turkey, on its acreage in the Powder River Basin CBM play. The
Company expects to drill a minimum of nine unit obligation wells during the
third quarter of 2001 on each of these federal units.
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During the first quarter of 2001, Prima participated with a 15% working
interest in the initial test well in the Jim Hill Draw Prospect located in
Converse County, Wyoming. This Muddy sandstone test was unsuccessful and has
been plugged and abandoned.
Prima has acquired or controls approximately 77,000 gross, 73,000 net
acres on the Wasatch Plateau in central Utah. Approximately 34,000 net acres
were added during the 2001 first quarter. The Company's leasehold position is
located approximately 12-15 miles northwest of Price, Utah. The lease block has
several potential targets, including the Blackhawk coals, Emery coals and Ferron
sandstones and coals. The Company is currently finalizing plans to test its
lease position later this year. Timing is dependent on rig availability and
government permits and regulations.
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, various cost-sharing
arrangements, or from other financing alternatives.
Results of Operations
For the quarter ended March 31, 2001, the Company earned net income of
$8,676,000, or $0.65 per diluted share, on revenues of $18,470,000, compared to
net income of $4,184,000, or $0.32 per diluted share on revenues of $10,677,000
for the comparable quarter of 2000. The results for 2001 include $611,000 (net
of income taxes), or $0.05 per diluted share, cumulative effect adjustment
resulting from the adoption of FAS 133 on January 1, 2001. Expenses were
$6,495,000 for the 2001 quarter compared to $4,903,000 for the 2000 quarter.
Revenues increased $7,793,000, or 73%, expenses increased $1,592,000, or 32% and
net income increased $4,492,000, or 107%.
Oil and gas sales for the quarter ended March 31, 2001 were $16,357,000
compared to $8,727,000 for the same period of 2000, an increase of $7,630,000 or
87%. The increase is primarily attributable to significantly higher natural gas
prices. The Company's net natural gas production was 2,099,000 Mcf and 2,165,000
Mcf for the first quarters of 2001 and 2000, respectively, a decrease of 66,000
Mcf or 3%. The Company's net oil production was 111,000 barrels compared to
112,000 barrels for the same periods, a decrease of 1,000 barrels or 1%. Net
production on an equivalent basis decreased 2% (converted on the basis of one
barrel of oil being the equivalent of six Mcf of natural gas).
The average price received for natural gas production was $6.29 per Mcf
for the 2001 quarter compared to $2.62 per Mcf for the 2000 quarter, an increase
of $3.67 per Mcf or 140%. The average price received for oil in 2001 was $28.51
per barrel compared to $27.29 per barrel for the same period of 2000, an
increase of $1.22 per barrel or 4%. During the first quarter of 2001, the
Company hedged approximately 36% of its natural gas production. Hedging gains of
$422,000 are included in oil and gas revenues for this period, which increased
the average price received per Mcf of natural gas by $0.20. No oil production
was hedged during the first quarter of 2001 and no natural gas or oil production
was hedged during the first quarter of 2000.
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The Company's depletion of oil and gas properties was $1,768,000 or
$0.64 per Mcfe on 2,765,000 equivalent Mcf produced during the first quarter of
2001, compared to $1,451,000 or $0.51 per Mcfe on 2,839,000 equivalent Mcf
produced during the first quarter of 2000. Depletion increased $317,000, or 22%.
The higher depletion rate for 2001 is comparable to the rate in the fourth
quarter of 2000, which reflected higher drilling and operating costs incurred
since October 1, 2000. Depreciation of other fixed assets was $282,000 and
$266,000 for the quarters ended March 31, 2001 and 2000, respectively, and is
attributable to depreciation of service equipment, furniture and equipment and
buildings. Depreciation expense on these assets increased $16,000, or 6%.
Lease operating expenses ("LOE") were $799,000 for the quarter ended
March 31, 2001 compared to $636,000 for the quarter ended March 31, 2000. Ad
valorem and production taxes were $1,424,000 and $731,000 for the same periods.
Production taxes increased with higher product prices. Total lifting costs (LOE
plus ad valorem and production taxes) were 14% of oil and gas revenues and $0.80
per Mcfe for the 2001 quarter compared to 16% and $0.48 per Mcfe for 2000.
Oilfield services represent the revenues earned by Action Oilfield
Services, Inc. (Colorado) and Action Energy Services (Wyoming), wholly owned
subsidiaries. These revenues include well servicing fees from drilling,
completion and swab rigs, trucking, water hauling, rental equipment, and other
related activities. Revenues from third parties were $1,776,000 for the quarter
ended March 31, 2001 compared to $1,659,000 for the comparable quarter of 2000,
an increase of $117,000, or 7%. For the quarter ended March 31, 2001, 39% of the
fees billed by the service companies were for Company owned wells compared to
31% for the quarter ended March 31, 2000. The Company's share of fees paid to
its service companies and the costs associated with providing the services are
eliminated in the consolidated financial statements. Costs of oilfield services
were $1,134,000 for the quarter ended March 31, 2001 compared to $1,280,000 for
the same quarter of 2000, a decrease of $146,000 or 11%.
General and administrative expenses ("G&A"), net of third party
reimbursements, were $1,088,000 for the quarter ended March 31, 2001 compared to
$539,000 for the quarter ended March 31, 2000, an increase of $549,000 or 102%.
The Company's G&A has increased due to expansion of the Company's activities and
operations and the related increase in personnel costs.
The provision for income taxes, including the tax effect of change in
accounting principle, was $4,175,000 for the three months ended March 31, 2001
compared to $1,590,000 for the three months ended March 31, 2000, an increase of
$2,585,000 or 163%. The effective income tax rate was 32.5% for the 2001 quarter
compared to 27.5% for the 2000 quarter. The Company's effective tax rates are
less than statutory rates due to permanent differences in financial and taxable
income, consisting primarily of statutory depletion deductions and Section 29
tax credits. The Company's effective tax rate increased primarily because income
before income taxes, including income from the change in accounting principle,
increased $7,077,000 or 123% for 2001, while the permanent differences did not
increase proportionately.
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.
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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 or increases in the
basis differential from NYMEX to the Rocky Mountains by entering into derivative
commodity instruments, including commodity futures contracts, price swaps and
basis 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.
The Company has derivative positions which are designed to hedge the
Company's oil and natural gas prices from downward price movements and basis
swaps to protect the Company from increases in the basis differential. Pursuant
to SFAS 133, the Company's derivatives either qualify as cash flow hedges or
fair value hedges, and are accounted for accordingly.
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.
The Company periodically hedges a portion of the price risk associated
with the sale of its oil and natural gas production through the use of
derivative commodity instruments, which consist of commodity futures contracts,
price swaps and basis swaps. These instruments reduce the Company's exposure to
decreases in oil and natural gas prices and/or increases in basis differential
on the hedged portion of its production by enabling it to effectively receive a
fixed price on its oil and natural gas sales. For the period April 1, 2001
through May 8, 2001, the Company settled derivative positions at a net gain of
$615,000. These gains will be reflected in the second quarter 2001 financial
statements as an adjustment to natural gas prices realized during the period. As
of May 8, 2001, the Company had the following open derivative positions in
place:
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Monthly
Volume
(MMBtu) or Unrealized
Type of Derivative (Barrels) Term Gains
--------------------------------------- ----------- -------------------- --------------
Natural gas futures 50,000 June 2001 $ 56,500
Natural gas basis swaps 60,000 June - September 2001 9,000
Natural gas futures 200,000 June - September 2001 931,600
Natural gas basis swaps 240,000 June - November 2001 730,800
Crude oil futures and calls sold 10,000 July 2001 10,300
Crude oil futures and calls sold 10,000 August 2001 7,800
During the first quarter of 2001, the Company sold 111,000 barrels of
oil. A hypothetical decrease of $2.85 per barrel (10% of average first quarter
prices) would have decreased the Company's production revenues by $316,000 for
that period. The Company sold 2,099,000 Mcf of natural gas during the first
quarter of 2001. A hypothetical decrease of $0.63 per Mcf (10% of average first
quarter prices) would have decreased the Company's production revenues by
$1,322,000 for that period.
During 2000, the Company sold 440,000 barrels of oil. A hypothetical
decrease of $2.93 per barrel (10% of the average price received during the year)
would decrease the Company's production revenues by $1,289,000 during 2001,
assuming that oil production remains at 2000 levels. The Company sold 8.7 Bcf of
natural gas in 2000. A hypothetical decrease of $.36 per Mcf (10% of the average
price received during the year) would decrease the Company's production revenues
by $3,132,000 for 2001, assuming that natural gas production remains at 2000
levels.
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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" or
"estimates" 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 fund its operations; risks related to exploration and developmental drilling;
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and uncertainties about oil and natural gas reserve estimates. For a more
complete explanation 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, 2000, beginning on page 19.
PART II OTHER INFORMATION
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
No exhibits are filed herewith pursuant to Rule 601 of Regulation S-K.
(b) Reports on Form 8-K
The Company filed a Report on Form 8-K dated January 31, 2001,
reporting its preliminary capital expenditures budget for 2001 of $45 million
and updating its operating activities in the Denver and Powder River Basins. The
Company filed a Report on Form 8-K dated February 15, 2001, reporting year end
2000 oil and natural gas reserve information and year 2000 production data. The
Company filed a Report on Form 8-K dated May 10, 2001, reporting its first
quarter 2001 earnings and providing an operations update
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934,
the Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
PRIMA ENERGY CORPORATION
(Registrant)
Date May 15, 2001 By /s/ Richard H. Lewis
------------------ ------------------------------------
Richard H. Lewis,
President and
Principal Financial Officer
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